Form 20-F
Table of Contents

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

Form 20-F

 

 

(Mark One)

 

¨ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

 

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

OR

 

¨ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report

Commission file number: 1-10888

 

 

TOTAL S.A.

(Exact Name of Registrant as Specified in Its Charter)

Republic of France

(Jurisdiction of Incorporation or Organization)

2, place Jean Millier

La Défense 6

92400 Courbevoie

France

(Address of Principal Executive Offices)

Patrick de La Chevardière

Chief Financial Officer

TOTAL S.A.

2, place Jean Millier

La Défense 6

92400 Courbevoie

France

Tel: +33 (0)1 47 44 45 46

Fax: +33 (0)1 47 44 49 44

(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)

 

 

Securities registered or to be registered pursuant to Section 12(b) of the Act.

 

 

 

Title of each class

 

Name of each exchange on which registered

Shares

American Depositary Shares

 

New York Stock Exchange*

New York Stock Exchange

 

* Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

2,363,767,313 Shares, par value 2.50 each, as of December 31, 2011

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  þ    No  ¨

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.    Yes  ¨    No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).**

Yes  ¨    No  ¨

** This requirement is not currently applicable to the registrant.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  þ   Accelerated filer  ¨    Non-accelerated filer   ¨

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

 

U.S. GAAP  ¨

  

International Financial Reporting Standards as issued by the International

Accounting Standards Board  þ

  Other   ¨

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.    Item 17  ¨    Item 18  ¨

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).      Yes  ¨     No  þ

 

 


Table of Contents

TABLE OF CONTENTS

 

          Page  

CERTAIN TERMS

     iii   

ABBREVIATIONS

     iv   

CONVERSION TABLE

     v   

Item 1.

  

Identity of Directors, Senior Management and Advisers

     1   

Item 2.

  

Offer Statistics and Expected Timetable

     1   

Item 3.

  

Key Information

     1   
  

Selected Financial Data

     1   
  

Exchange Rate Information

     3   
  

Risk Factors

     4   

Item 4.

  

Information on the Company

     10   
  

History and Development

     10   
  

Business Overview

     11   
  

Other Matters

     54   

Item 4A.

  

Unresolved Staff Comments

     65   

Item 5.

  

Operating and Financial Review and Prospects

     65   

Item 6.

  

Directors, Senior Management and Employees

     81   
  

Directors and Senior Management

     81   
  

Compensation

     92   
  

Corporate Governance

     112   
  

Employees and Share Ownership

     121   

Item 7.

  

Major Shareholders and Related Party Transactions

     124   

Item 8.

  

Financial Information

     126   

Item 9.

  

The Offer and Listing

     132   

Item 10.

  

Additional Information

     133   

Item 11.

  

Quantitative and Qualitative Disclosures About Market Risk

     146   

Item 12.

  

Description of Securities Other than Equity Securities

     147   

Item 13.

  

Defaults, Dividend Arrearages and Delinquencies

     148   

Item 14.

  

Material Modifications to the Rights of Security Holders and Use of Proceeds

     148   

Item 15.

  

Controls and Procedures

     148   

Item 16A.

  

Audit Committee Financial Expert

     149   

Item 16B.

  

Code of Ethics

     149   

Item 16C.

  

Principal Accountant Fees and Services

     149   

Item 16D.

  

Exemptions from the Listing Standards for Audit Committees

     149   

Item 16E.

  

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

     150   

Item 16F.

  

Change in Registrant’s Certifying Accountant

     150   

Item 16G.

  

Corporate Governance

     150   

Item 17.

  

Financial Statements

     153   

Item 18.

  

Financial Statements

     153   

Item 19.

  

Exhibits

     153   

 

i


Table of Contents

Basis of Presentation

Financial information included in this Annual Report is presented according to International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and IFRS as adopted by the European Union (EU) as of December 31, 2011.

Statements Regarding Competitive Position

Unless otherwise indicated, statements made in “Item 4. Information on the Company” referring to TOTAL’s competitive position are based on the Company’s estimates, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and TOTAL’s internal assessments of market share based on publicly available information about the financial results and performance of market participants.

Additional Information

This Annual Report on Form 20-F reports information primarily regarding TOTAL’s business, operations and financial information relating to the fiscal year ended December 31, 2011. For more recent updates regarding TOTAL, you may inspect any reports, statements or other information TOTAL files with the United States Securities and Exchange Commission (“SEC”). All of TOTAL’s SEC filings made after December 31, 2001, are available to the public at the SEC Web site at http://www.sec.gov and from certain commercial document retrieval services. See also “Item 10. Additional Information — Documents on Display”.

 

ii


Table of Contents

CERTAIN TERMS

Unless the context indicates otherwise, the following terms have the meanings shown below:

 

“acreage”

The area, expressed in acres, over which TOTAL has interests in exploration or production.

 

“ADRs”

American Depositary Receipts evidencing ADSs.

 

“ADSs”

American Depositary Shares representing the shares of TOTAL S.A.

 

“barrels”

Barrels of crude oil, natural gas liquids (NGL) or bitumen.

 

“Company”

TOTAL S.A.

 

“condensates”

Condensates are a mixture of hydrocarbons that exist in a gaseous phase at original reservoir temperature and pressure, but that, when produced, exist in a liquid phase at surface temperature and pressure. Condensates are sometimes referred to as C5+.

 

“crude oil”

Crude oil is a mixture of compounds (mainly pentanes and heavier hydrocarbons) that exists in a liquid phase at original reservoir temperature and pressure and remains liquid at atmospheric pressure and ambient temperature. “Crude oil” or “oil” are sometimes used as generic terms to designate crude oil plus natural gas liquids (NGL).

 

“Depositary”

The Bank of New York Mellon.

 

“Depositary Agreement”

The depositary agreement pursuant to which ADSs are issued, a copy of which is attached as Exhibit 1 to the registration statement on Form F-6 (Reg. No. 333-172005) filed with the SEC on February 1, 2011.

 

“Group”

TOTAL S.A. and its subsidiaries and affiliates. The terms TOTAL and Group are used interchangeably.

 

“hydrocracker”

A refinery unit which uses a catalyst and extraordinarily high pressure, in the presence of surplus hydrogen, to shorten molecules.

 

“liquids”

Liquids consist of crude oil, bitumen and natural gas liquids (NGL).

 

“LNG”

Liquefied natural gas.

 

“LPG”

Liquefied petroleum gas is a mixture of hydrocarbons, the principal components of which are propane and butane, in a gaseous state at atmospheric pressure, but which is liquefied under moderate pressure and ambient temperature

 

“NGL”

Natural gas liquids consist of condensates and LPG.

 

“oil and gas”

Generic term which includes all hydrocarbons (e.g., crude oil, natural gas liquids (NGL), bitumen and natural gas).

 

“proved reserves”

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The full definition of “proved reserves” that we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the SEC is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended (including

 

iii


Table of Contents
 

as amended by the SEC “Modernization of Oil and Gas Reporting” Release No. 33-8995 of December 31, 2008).

 

“proved developed reserves”

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. The full definition of “developed reserves” that we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the SEC is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended (including as amended by the SEC “Modernization of Oil and Gas Reporting” Release No. 33-8995 of December 31, 2008).

 

“proved undeveloped reserves”

Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The full definition of “undeveloped reserves” that we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the SEC is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended (including as amended by the SEC “Modernization of Oil and Gas Reporting” Release No. 33-8995 of December 31, 2008).

 

“steam cracker”

A petrochemical plant that turns naphtha and light hydrocarbons into ethylene, propylene, and other chemical raw materials.

 

“TOTAL”

TOTAL S.A. and its subsidiaries and affiliates. We use such term interchangeably with the term Group. When we refer to the parent holding company alone, we use the term TOTAL S.A. or the Company.

 

“trains”

Facilities for converting, liquefying, storing and off-loading natural gas.

 

“ERMI”

ERMI is an indicator intended to represent the refining margin after variable costs for a theoretical complex refinery located around Rotterdam in Northern Europe that processes a mix of crude oil and other inputs commonly supplied to this region to produce and market the main refined products at prevailing prices in the region.

 

“turnarounds”

Temporary shutdowns of facilities for maintenance, overhaul and upgrading.

ABBREVIATIONS

 

b

  barrel   k    thousand

cf

  cubic feet   M    million

boe

  barrel of oil equivalent   B    billion

t

  metric ton   W    watt

m3

  cubic meter   GWh    gigawatt-hour

/d

  per day   TWh    terawatt-hour

/y

  per year   Wp    watt peak
    Btu    British thermal unit

 

iv


Table of Contents

CONVERSION TABLE

 

1 acre

   = 0.405 hectares   

1 b

   = 42 U.S. gallons   

1 boe

   = 1 b of crude oil    = 5,447 cf of gas in 2011(a)
      = 5,478 cf of gas in 2010
      = 5,490 cf of gas in 2009

1 b/d of crude oil

   = approximately 50 t/y of crude oil   

1 Bm3/y

   = approximately 0.1 Bcf/d   

1 m3

   = 35.3147 cf   

1 kilometer

   = approximately 0.62 miles   

1 ton

   = 1 t    = 1,000 kilograms (approximately 2,205 pounds)

1 ton of oil

   = 1 t of oil    = approximately 7.5 b of oil (assuming a specific gravity of 37° API)

1 Mt of LNG

   = approximately 48 Mcf of gas   

1 Mt/y LNG

   = approximately 131 Mcf/d   

 

(a) Natural gas is converted to barrels of oil equivalent using a ratio of cubic feet of natural gas per one barrel. This ratio is based on the actual average equivalent energy content of TOTAL’s natural gas reserves during the applicable periods, and is subject to change. The tabular conversion rate is applicable to TOTAL’s natural gas reserves on a group-wide basis.

 

v


Table of Contents

Cautionary Statement Concerning Forward-Looking Statements

TOTAL has made certain forward-looking statements in this document and in the documents referred to in, or incorporated by reference into, this Annual Report. Such statements are subject to risks and uncertainties. These statements are based on the beliefs and assumptions of the management of TOTAL and on the information currently available to such management. Forward-looking statements include information concerning forecasts, projections, anticipated synergies, and other information concerning possible or assumed future results of TOTAL, and may be preceded by, followed by, or otherwise include the words “believes”, “expects”, “anticipates”, “intends”, “plans”, “targets”, “estimates” or similar expressions.

Forward-looking statements are not assurances of results or values. They involve risks, uncertainties and assumptions. TOTAL’s future results and share value may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results and values are beyond TOTAL’s ability to control or predict. Except for its ongoing obligations to disclose material information as required by applicable securities laws, TOTAL does not have any intention or obligation to update forward-looking statements after the distribution of this document, even if new information, future events or other circumstances have made them incorrect or misleading.

You should understand that various factors, certain of which are discussed elsewhere in this document and in the documents referred to in, or incorporated by reference into, this document, could affect the future results of TOTAL and could cause results to differ materially from those expressed in such forward-looking statements, including:

 

   

material adverse changes in general economic conditions or in the markets served by TOTAL, including changes in the prices of oil, natural gas, refined products, petrochemical products and other chemicals;

   

changes in currency exchange rates and currency devaluations;

   

the success and the economic efficiency of oil and natural gas exploration, development and production programs, including, without limitation, those that are not controlled and/or operated by TOTAL;

   

uncertainties about estimates of changes in proven and potential reserves and the capabilities of production facilities;

   

uncertainties about the ability to control unit costs in exploration, production, refining and marketing (including refining margins) and chemicals;

   

changes in the current capital expenditure plans of TOTAL;

   

the ability of TOTAL to realize anticipated cost savings, synergies and operating efficiencies;

   

the financial resources of competitors;

   

changes in laws and regulations, including tax and environmental laws and industrial safety regulations;

   

the quality of future opportunities that may be presented to or pursued by TOTAL;

   

the ability to generate cash flow or obtain financing to fund growth and the cost of such financing and liquidity conditions in the capital markets generally;

   

the ability to obtain governmental or regulatory approvals;

   

the ability to respond to challenges in international markets, including political or economic conditions (including national and international armed conflict) and trade and regulatory matters (including actual or proposed sanctions on companies that conduct business in certain countries);

   

the ability to complete and integrate appropriate acquisitions, strategic alliances and joint ventures;

   

changes in the political environment that adversely affect exploration, production licenses and contractual rights or impose minimum drilling obligations, price controls, nationalization or expropriation, and regulation of refining and marketing, chemicals and power generating activities;

   

the possibility that other unpredictable events such as labor disputes or industrial accidents will adversely affect the business of TOTAL; and

   

the risk that TOTAL will inadequately hedge the price of crude oil or finished products.

For additional factors, you should read the information set forth under “Item 3. Risk Factors”, “Item 4. Information on the Company — Other Matters”, “Item 5. Operating and Financial Review and Prospects” and “Item 11. Quantitative and Qualitative Disclosures About Market Risk”.

 

vi


Table of Contents

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3. KEY INFORMATION

SELECTED FINANCIAL DATA

 

 

The following table presents selected consolidated financial data for TOTAL on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and IFRS as adopted by the European Union for the years ended December 31, 2011, 2010, 2009, 2008 and 2007. The historical consolidated financial statements of TOTAL for these

periods, from which the financial data presented below for such periods are derived, have been audited by Ernst & Young Audit and KPMG S.A., independent registered public accounting firms, and the Company’s auditors. All such data should be read in conjunction with the Consolidated Financial Statements and the Notes thereto included elsewhere herein.

 

 

1


Table of Contents

SELECTED CONSOLIDATED FINANCIAL DATA

 

(M , except share and per share data)   2011     2010     2009     2008     2007  

INCOME STATEMENT DATA

         

Revenues from sales

    166,550        140,476        112,153        160,331        136,824   

Net income, Group share

    12,276        10,571        8,447        10,590        13,181   

Earnings per share

    5.46        4.73        3.79        4.74        5.84   

Fully diluted earnings per share

    5.44        4.71        3.78        4.71        5.80   

CASH FLOW STATEMENT DATA

         

Cash flow from operating activities

    19,536        18,493        12,360        18,669        17,686   

Total expenditures

    24,541        16,273        13,349        13,640        11,722   

BALANCE SHEET DATA

         

Total assets

    164,049        143,718        127,753        118,310        113,541   

Non-current financial debt

    22,557        20,783        19,437        16,191        14,876   

Non-controlling interests

    1,352        857        987        958        842   

Shareholders’ equity — Group share

    68,037        60,414        52,552        48,992        44,858   

Common shares

    5,909        5,874        5,871        5,930        5,989   

DIVIDENDS

         

Dividend per share (euros)

    2.28 (a)      2.28        2.28        2.28        2.07   

Dividend per share (dollars)

    $3.10 (a)(b)      $3.15        $3.08        $3.01        $3.14   

COMMON SHARES(c)

         

Average number outstanding of common shares 2.50 par value (shares undiluted)

    2,247,479,529        2,234,829,043        2,230,599,211        2,234,856,551        2,255,294,231   

Average number outstanding of common shares 2.50 par value (shares diluted)

    2,256,951,403        2,244,494,576        2,237,292,199        2,246,658,542        2,274,384,984   

 

(a) Subject to approval by the shareholders’ meeting on May 11, 2012.
(b) Estimated dividend in dollars includes the first quarterly interim dividend of $0.763 paid in September 2011 and the second quarterly interim dividend of $0.742 paid in December 2011, as well as the third quarterly interim dividend of 0.57 payable in March 2012 (ADR-related payment in April 2012) and the proposed final dividend of 0.57 payable in June 2012 (ADR-related payment in July 2012), both converted at a rate of $1.40/.
(c) The number of common shares shown has been used to calculate per share amounts.

 

2


Table of Contents

EXCHANGE RATE INFORMATION

 

 

For information regarding the effects of currency fluctuations on TOTAL’s results, see “Item 5. Operating and Financial Review and Prospects”.

Most currency amounts in this Annual Report on Form 20-F are expressed in euros (“euros” or “”) or in U.S. dollars (“dollars” or “$”). For the convenience of the reader, this Annual Report on Form 20-F presents certain translations into dollars of certain euro amounts.

The following table sets out the average dollar/euro exchange rates expressed in dollars per 1.00 for the years indicated, based on an average of the daily European Central Bank (“ECB”) reference exchange rate.(1) Such rates are used by TOTAL in preparation of its Consolidated Statement of Income and Consolidated Statement of Cash Flow in its Consolidated Financial Statements. No representation is made that the euro could have been converted into dollars at the rates shown or at any other rates for such periods or at such dates.

DOLLAR/EURO EXCHANGE RATES

 

Year    Average Rate  

2007

     1.3705   

2008

     1.4708   

2009

     1.3948   

2010

     1.3257   

2011

     1.3920   

The table below shows the high and low dollar/euro exchange rates for the three months ended December 31, 2011, and for the first three months of 2012, based on the daily ECB reference exchange rates published during the relevant month expressed in dollars per 1.00.

DOLLAR/EURO EXCHANGE RATES

 

Period    High      Low  

October 2011

     1.4160         1.3181   

November 2011

     1.3809         1.3229   

December 2011

     1.3511         1.2889   

January 2012

     1.3176         1.2669   

February 2012

     1.3454         1.2982   

March 2012(a)

     1.3312         1.3057   

 

(a) Through March 22, 2012.

The ECB reference exchange rate on March 22, 2012, for the dollar against the euro was $1.3167/.

 

 

 

(1) For the period 2007 — 2011, the averages of the ECB reference exchange rates expressed in dollars per 1.00 on the last business day of each month during the relevant year are as follows: 2007 — 1.38; 2008 — 1.47; 2009 — 1.40; 2010 — 1.32; and 2011 — 1.40.

 

3


Table of Contents

RISK FACTORS

 

 

The Group and its businesses are subject to various risks relating to changing competitive, economic, political, legal, social, industry, business and financial conditions. These conditions, along with TOTAL’s approaches to managing certain of these risks, are described below and discussed in greater detail elsewhere in this Annual Report, particularly under the headings “Item 4. Information on the Company — Other Matters”, “Item 5. Operating and Financial Review and Prospects” and “Item 11. Quantitative and Qualitative Disclosures About Market Risk”.

A substantial or extended decline in oil or natural gas prices would have a material adverse effect on our results of operations.

Prices for oil and natural gas historically have fluctuated widely due to many factors over which we have no control. These factors include:

 

 

global and regional economic and political developments in resource-producing regions, particularly in the Middle East, Africa and South America;

 

global and regional supply and demand;

 

the ability of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to influence global production levels and prices;

 

prices of alternative fuels which affect our realized prices under our long-term gas sales contracts;

 

governmental regulations and actions;

 

global economic and financial market conditions;

 

war or other conflicts;

 

cost and availability of new technology;

 

changes in demographics, including population growth rates and consumer preferences; and

 

adverse weather conditions (such as hurricanes) that can disrupt supplies or interrupt operations of our facilities.

Substantial or extended declines in oil and natural gas prices would adversely affect our results of operations by reducing our profits. For the year 2012, we estimate that a decrease of $1.00 per barrel in the average annual price of Brent crude would have the effect of reducing our annual adjusted net operating income from the Upstream segment by approximately 0.11 billion (calculated with a base case exchange rate of $1.40 per 1.00). In addition to the adverse effect on revenues, margins and profitability

from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators could lead to reviews for impairment of the Group’s oil and natural gas properties and could impact reserves. Such reviews would reflect management’s view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on our results of operations in the period in which it occurs. Lower oil and natural gas prices over prolonged periods may also reduce the economic viability of projects planned or in development, causing us to cancel or postpone capital expansion projects, and may reduce liquidity, thereby potentially decreasing our ability to finance capital expenditures. If we are unable to follow through with capital expansion projects, our opportunities for future revenue and profitability growth would be reduced, which could materially impact our financial condition.

However, in a high oil and gas price environment, we can experience sharp increases in cost and fiscal take, and, under some production-sharing contracts, our entitlement to reserves could be reduced. Higher prices can also reduce demand for our products.

Our long-term profitability depends on cost effective discovery, acquisition and development of new reserves; if we are unsuccessful, our results of operations and financial condition would be materially and adversely affected.

A significant portion of our revenues and the majority of our operating income are derived from the sale of oil and gas which we extract from underground reserves developed as part of our Upstream business. In order for this business to continue to be profitable, we need to replace depleted reserves with new proved reserves. Furthermore, we need to accomplish such replacement in a manner that allows subsequent production to be economically viable. However, our ability to discover or acquire and develop new reserves successfully is uncertain and can be negatively affected by a number of factors, including:

 

 

unexpected drilling conditions, including pressure or irregularities in geological formations;

 

the risk of dry holes or failure to find commercial quantities of hydrocarbons;

 

equipment failures, fires, blow-outs or accidents;

 

our inability to develop new technologies that permit access to previously inaccessible fields;

 

 

4


Table of Contents
 

adverse weather conditions;

 

compliance with both anticipated and unanticipated governmental requirements;

 

shortages or delays in the availability or delivery of appropriate equipment;

 

industrial action;

 

competition from publicly held and state-run oil and gas companies for the acquisition of assets and licenses;

 

increased taxes and royalties, including retroactive claims; and

 

problems with legal title.

Any of these factors could lead to cost overruns and impair our ability to make discoveries and acquisitions or complete a development project, or to make production economical. If we fail to develop new reserves cost-effectively on an ongoing basis, our results of operations, including profits, and our financial condition, would be materially and adversely affected.

Our oil and gas reserve data are only estimates, and subsequent downward adjustments are possible. If actual production from such reserves is lower than current estimates indicate, our results of operations and financial condition would be negatively impacted.

Our proved reserves figures are estimates reflecting applicable reporting regulations as they may evolve. Proved reserves are those reserves which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Reserves are estimated by teams of qualified, experienced and trained geoscientists, petroleum engineers and project engineers, who rigorously review and analyze in detail all available geosciences and engineering data (e.g., seismic, electrical logs, cores, fluids, pressures, flow rates, facilities parameters). This process involves making subjective judgments, including with respect to the estimate of hydrocarbons initially in place, initial production rates and recovery efficiency, based on available geological, technical and economic data. Consequently, estimates of reserves are not exact measurements and are subject to revision. In addition, they may be negatively impacted by a variety of

factors which are beyond our control and which could cause such estimates to be adjusted downward in the future, or cause our actual production to be lower than our currently reported proved reserves indicate. The main such factors include:

 

 

a decline in the price of oil or gas, making reserves no longer economically viable to exploit and therefore not classifiable as proved;

 

an increase in the price of oil or gas, which may reduce the reserves that we are entitled to under production sharing and risked service contracts and other contractual terms;

 

changes in tax rules and other government regulations that make reserves no longer economically viable to exploit; and

 

the actual production performance of our reservoirs.

Our reserves estimates may therefore require substantial downward revisions to the extent our subjective judgments prove not to have been conservative enough based on the available geosciences and engineering data, or our assumptions regarding factors or variables that are beyond our control prove to be incorrect over time. Any downward adjustment would indicate lower future production amounts, which could adversely affect our results of operations, including profits as well as our financial condition.

We have significant production and reserves located in politically, economically and socially unstable areas, where the likelihood of material disruption of our operations is relatively high.

A significant portion of our oil and gas production occurs in unstable regions around the world, most significantly Africa, but also the Middle East, Asia-Pacific and South America. Approximately 28%, 24%, 10% and 8%, respectively, of our 2011 combined liquids and gas production came from these four regions. In recent years, a number of the countries in these regions have experienced varying degrees of one or more of the following: economic instability, political volatility, civil war, violent conflict and social unrest. In Africa, certain of the countries in which we have production have recently suffered from some of these conditions, including Nigeria, where we had in 2011 our second highest hydrocarbon production, and Libya.

The Middle East in general has recently suffered increased political volatility in connection with violent conflict and social unrest. A number of countries in South America where we have production and other facilities, including Argentina, Bolivia and Venezuela, have suffered from political or economic instability and social unrest and related

 

 

5


Table of Contents

problems. In Asia-Pacific, Indonesia has suffered some of these conditions. Any of these conditions alone or in combination could disrupt our operations in any of these regions, causing substantial declines in production. Furthermore, in addition to current production, we are also exploring for and developing new reserves in other regions of the world that are historically characterized by political, social and economic instability, such as the Caspian Sea region where we have large projects currently underway. The occurrence and magnitude of incidents related to economic, social and political instability are unpredictable. It is possible that they could have a material adverse impact on our production and operations in the future.

We are exposed to risks regarding the safety and security of our operations.

TOTAL engages in a broad scope of activities, which include drilling, oil and gas production, processing, transportation, refining and petrochemical activities, storage and distribution of petroleum products, and production of base chemical and specialty products, and involve a wide range of operational risks. Among these risks are those of explosions, fires, accidents, equipment failures or leakage of toxic products or emissions or discharges into the air, water or soil, including related environmental risks. We also face risks, once production is discontinued, because our activities require environmental site remediation. In the transportation area, the type of risk depends not only on the hazardous nature of the products transported, but also on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road), the volumes involved, and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). Acts of terrorism against our plants and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people.

Certain branches or activities face specific additional risks. In Exploration & Production, we face risks related to the physical characteristics of our oil or gas fields. These include the risks of eruptions of oil or of gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and risks of fire or explosion. These events may cause injury or death, damage or destroy oil or gas wells as well as equipment and other property, lead to a disruption of activity or cause environmental damage. In addition, since exploration and production activities may take place on sites that are ecologically sensitive (for example, in tropical forests or in a marine environment), each site requires a

risk-based approach to avoid or minimize the impact on human health, flora and fauna, the ecosystem and biodiversity. In certain situations where TOTAL is not the operator, the Group may have reduced influence and control over third parties, which may limit its ability to manage and control these risks. TOTAL’s activities in the Refining & Chemicals and Supply & Marketing segments also entail additional health, safety and environmental risks related to the overall life cycle of the products manufactured, as well as raw materials used in the manufacturing process, such as catalysts, additives and monomer feedstocks. These risks can arise from the intrinsic characteristics of the products involved (flammability, toxicity, or long-term environmental impacts such as greenhouse gas emissions), their use (including by customers), emissions and discharges resulting from their manufacturing process, and from recycling or disposing of materials and wastes at the end of their useful life.

Contractual terms may provide for indemnification obligations, either by TOTAL in favor of third-parties or by third-parties for TOTAL’s benefit, if, notably, an event occurs leading to personal injury, death, property damage or discharge of hazardous materials into the environment. With respect to joint ventures the assets of which are operated by TOTAL, contractual terms generally provide that TOTAL assumes liability for damages caused by its gross negligence or willful misconduct. With respect to joint ventures in which TOTAL has an interest but that assets of which are operated by others, contractual terms generally provide that the operator assumes liability for damages caused by its gross negligence or willful misconduct. All other liabilities of any type of joint venture are generally assumed by the partners in proportion to their respective ownership interests. With respect to third party providers of goods and services, the amount and nature of liabilities assumed by the third party depends on the context and may be limited by contract. With respect to the Group’s customers, TOTAL seeks to ensure that its products meet applicable specifications and that TOTAL abides by all applicable consumer protection laws. Failure to do so could lead to personal injury, environmental harm, regulatory violations and loss of customers, and could negatively impact our results of operations, financial condition and reputation.

While our insurance coverage is in line with industry practice, we are not insured against all possible risks.

We maintain insurance to protect us against the risk of damage to Group property and/or business disruption to our main refining and petrochemical sites. In addition, we also maintain worldwide third-party liability insurance

 

 

6


Table of Contents

coverage for all of our subsidiaries. Our insurance and risk management policies are described under “Item 4. Other Matters — Insurance and risk management”. While we believe our insurance coverage is in line with industry practice and sufficient to cover normal risks in our operations, we are not insured against all possible risks. In the event of a major environmental disaster, for example, our liability may exceed the maximum coverage provided by our third-party liability insurance. The loss we could suffer in the event of such a disaster would depend on all the facts and circumstances and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster. The Group cannot guarantee that it will not suffer any uninsured loss and there can be no assurance, particularly in the case of a major environmental disaster or industrial accident, that such loss would not have a material adverse effect on the Group.

We are subject to stringent environmental, health and safety laws in numerous jurisdictions around the world and may incur material costs to comply with these laws and regulations.

Our workforce and the public are exposed to risks inherent to our operations that potentially could lead to injuries, loss of life or environmental damage and could result in regulatory action, legal liability and damage to our reputation.

We incur, and expect to continue to incur, substantial capital and operating expenditures to comply with increasingly complex laws and regulations covering the protection of the natural environment and the promotion of worker health and safety, including:

 

 

costs to prevent, control, eliminate or reduce certain types of air and water emissions, including those costs incurred in connection with government action to address climate change;

 

remedial measures related to environmental contamination or accidents at various sites, including those owned by third parties;

 

compensation of persons claiming damages caused by our activities or accidents; and

 

costs in connection with the decommissioning of drilling platforms and other facilities.

If our established financial reserves prove inadequate, environmental costs could have a material effect on our results of operations and our financial position. Furthermore, in the countries where we operate or expect to operate in the near future, new laws and regulations, the

imposition of tougher license requirements, increasingly strict enforcement or new interpretations of existing laws and regulations or the discovery of previously unknown contamination may also cause us to incur material costs resulting from actions taken to comply with such laws and regulations, including:

 

 

modifying operations;

 

installing pollution control equipment;

 

implementing additional safety measures; and

 

performing site clean-ups.

As a further result of any new laws and regulations or other factors, we may also have to curtail, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish our productivity and materially and adversely impact our results of operations, including profits.

Regulatory measures designed to address climate change and physical effects attributed to climate change may adversely affect our businesses.

Growing public concerns in the EU and globally that rising greenhouse gas emissions and climate change may significantly affect the environment and society could adversely affect our businesses, including by the addition of stricter regulations that increase our operating costs, affect product sales and reduce profitability. Furthermore, our business operates in varied locales where the potential physical impacts of climate change, including changes in weather patterns, are highly uncertain and may adversely impact the results of our operations.

Our operations throughout the developing world are subject to intervention by various governments, which could have an adverse effect on our results of operations.

We have significant exploration and production, and in some cases refining, marketing or chemicals operations, in developing countries whose governmental and regulatory framework is subject to unexpected change and where the enforcement of contractual rights is uncertain. In addition, our exploration and production activity in such countries is often done in conjunction with state-owned entities, for example as part of a joint venture, where the state has a significant degree of control. In recent years, in various regions globally, we have seen governments and state-owned enterprises exercising greater authority and imposing more stringent conditions on companies pursuing exploration and production activities in their respective countries, increasing the costs and uncertainties of our business operations, which is a trend we expect to

 

 

7


Table of Contents

continue. Potential increasing intervention by governments in such countries can take a wide variety of forms, including:

 

 

the award or denial of exploration and production interests;

 

the imposition of specific drilling obligations;

 

price and/or production quota controls;

 

nationalization or expropriation of our assets;

 

unilateral cancellation or modification of our license or contract rights;

 

increases in taxes and royalties, including retroactive claims;

 

the establishment of production and export limits;

 

the renegotiation of contracts;

 

payment delays; and

 

currency exchange restrictions or currency devaluation.

Imposition of any of these factors by a host government in a developing country where we have substantial operations, including exploration, could cause us to incur material costs or cause our production to decrease, potentially having a material adverse effect on our results of operations, including profits.

We face foreign exchange risks that could adversely affect our results of operations.

Our business faces foreign exchange risks because a large percentage of our revenues and cash receipts are denominated in dollars, the international currency of petroleum sales, while a significant portion of our operating expenses and income taxes accrue in euros and other currencies. Movements between the dollar and euro or other currencies may adversely affect our business by negatively impacting our booked revenues and income, and may also result in significant translation adjustments that impact our shareholders’ equity.

Ethical misconduct or breaches of applicable laws by our employees could expose us to criminal and civil penalties and be damaging to our reputation and shareholder value.

Our Code of Conduct, which applies to all of our employees, defines our commitment to integrity, compliance with all applicable legal requirements, high ethical standards and the behaviors and actions we expect of our businesses and people wherever we operate. Ethical misconduct or non-compliance with applicable laws and regulations, including non-compliance with anti-bribery, anticorruption and other applicable laws, could expose TOTAL and our employees to criminal and civil penalties

and could be damaging to our reputation and shareholder value.

Disruption of our critical IT services or breaches of information security could adversely affect our operations.

Our businesses depend heavily on the reliability and security of our information technology (“IT”) systems. If the integrity of our IT systems were compromised due to, for example, technical failure or cyber attack, our business operations and assets could sustain serious damage, material intellectual property could be divulged and, in some cases, personal injury, environmental harm and regulatory violations could occur.

We have activities in certain countries which are subject to U.S. and EU sanctions and our activities in Iran and Syria could lead to sanctions under relevant U.S. and EU legislation.

The United States and the European Union (“EU”) have adopted legal restrictions with respect to certain activities in Cuba, Iran, Sudan and Syria, and the U.S. Department of State has identified these countries as state sponsors of terrorism. We currently have investments in Iran and, to a lesser extent, Syria and Cuba.

With respect to Iran, the United States adopted legislation in 1996 implementing sanctions against non-U.S. companies doing business in Iran and Libya (the Iran and Libya Sanctions Act, referred to as “ILSA”), which in 2006 was amended to concern only business in Iran (then renamed the Iran Sanctions Act, referred to as “ISA”).

Pursuant to this statute, the President of the United States is authorized to initiate an investigation into the activities of non-U.S. companies in Iran and the possible imposition of sanctions (from a list that includes denial of financing by the U.S. Export-Import Bank, limitations on the amount of loans or credits available from U.S. financial institutions and prohibition of U.S. federal procurements from sanctioned persons) against persons found, in particular, to have knowingly made investments of $20 million or more in any 12-month period in the petroleum sector in Iran. In May 1998, the U.S. government waived the application of sanctions for TOTAL’s investment in the South Pars gas field. This waiver, which has not been modified since it was granted, does not address TOTAL’s other activities in Iran, although TOTAL has not been notified of any related sanctions.

In November 1996, the Council of the European Union adopted regulations which prohibit TOTAL from complying with any requirement or prohibition based on or resulting

 

 

8


Table of Contents

directly or indirectly from certain enumerated legislation, including ILSA (now ISA). It also prohibits TOTAL from having its waiver for South Pars extended to other activities.

In each of the years since the passage of ILSA and until 2007, TOTAL made investments in Iran in excess of $20 million (excluding the investments made as part of the development of South Pars). Since 2008, TOTAL’s position has consisted essentially in being reimbursed for its past investments as part of buyback contracts signed between 1995 and 1999 with respect to permits on which the Group is no longer the operator. In 2011, TOTAL had no production in Iran.

ISA was amended in July 2010 by the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010 (“CISADA”), which expanded the scope of ISA and restricted the President’s ability to grant waivers. In addition to sanctionable investments in Iran’s petroleum sector, parties may now be sanctioned for any transaction exceeding $1 million or series of transactions exceeding $5 million in any 12-month period for knowingly providing to Iran refined petroleum products, and for knowingly providing to Iran goods, services, technology, information or support that could directly and significantly either (i) facilitate the maintenance or expansion of Iran’s domestic production of refined petroleum products, or (ii) contribute to the enhancement of Iran’s ability to import refined petroleum products. The sanctions to be imposed against violating parties generally prohibit transactions in foreign exchange by the sanctioned party, prohibit any transfers of credit or payments between, by, through or to any financial institution to the extent that such transfers or payments involve any interest of the sanctioned party, and require blocking of any property of the sanctioned party that is subject to the jurisdiction of the United States. Investments in the petroleum sector commenced prior to the adoption of CISADA appear to remain subject to the pre-amended version of ISA. The new sanctions added by CISADA would be available with respect to new investments in the petroleum sector or any other sanctionable activity occurring on or after July 1, 2010. Prior to CISADA’s enactment, TOTAL discontinued prohibited sales under ISA, as amended by CISADA, of refined products to Iran.

On September 30, 2010, the U.S. State Department announced that the U.S. government, pursuant to the “Special Rule” provision of ISA added by CISADA that allows it to avoid making a determination of sanctionability under ISA with respect to any party that provides certain assurances, would not make such a determination with respect to TOTAL. The U.S. State Department further

indicated at that time that, as long as TOTAL acts in accordance with its commitments, TOTAL will not be regarded as a company of concern for its past Iran-related activities.

On November 21, 2011, President Obama issued Executive Order 13590, which authorized sanctions that are similar to those available under ISA for knowingly, on or after November 21, 2011, selling, leasing, or providing to Iran goods, services, technology, or support that (i) has a fair market value of $1 million or more or that, during a 12-month period, has an aggregate fair market value of $5 million or more, and that could directly and significantly contribute to the maintenance or enhancement of Iran’s ability to develop petroleum resources located in Iran, or (ii) has a fair market value of $250,000 or more or that, during a 12-month period, has an aggregate fair market value of $1 million or more, and that could directly and significantly contribute to the maintenance or expansion of Iran’s domestic production of petrochemical products. TOTAL does not conduct activities in Iran that could be sanctionable under Executive Order 13590, and there is no provision in Executive Order 13590 that modifies the aforementioned “Special Rule”. In addition, the U.S. State Department has published guidance that states the completion of existing contracts is not sanctionable under Executive Order 13590.

France and the EU have adopted measures, based on United Nations Security Council resolutions, which restrict the movement of certain individuals and goods to or from Iran as well as certain financial transactions with Iran, in each case when such individuals, goods or transactions are related to nuclear proliferation and weapons activities or likely to contribute to their development. In July and October 2010, the European Union adopted new restrictive measures regarding Iran. Among other things, the supply of key equipment and technology in the following sectors of the oil and gas industry in Iran are prohibited: refining, liquefied natural gas, exploration and production. The prohibition extends to technical assistance, training and financial assistance in connection with such items. Extension of loans or credit to, acquisition of shares in, entry into joint ventures with or other participation in enterprises in Iran (or Iranian-owned enterprises outside of Iran) engaged in any of the targeted sectors also is prohibited. Moreover, with respect to restrictions on transfers of funds and on financial services, any transfer of at least 40,000 or equivalent to an Iranian individual or entity shall require a prior authorization of the competent authorities of the EU Member States.

On January 23, 2012, the Council of the European Union prohibited the purchase, import and transport of Iranian oil

 

 

9


Table of Contents

and petroleum and petrochemical products by European persons and by entities constituted under the laws of an EU Member State. Prior to that date, TOTAL had ceased these now-prohibited activities.

TOTAL continues to closely monitor legislative and other developments in France, the EU and the United States in order to determine whether its limited activities in Iran, Syria and other sanctioned or potentially sanctioned jurisdictions could subject it to the application of sanctions. The Group cannot assure that current or future regulations or developments will not have a negative impact on its business or reputation.

With respect to Syria, the EU adopted measures in May 2011 with criminal and financial penalties that prohibit the supply of certain equipment to Syria, as well as certain financial and asset transactions with respect to a list of named individuals and entities. These measures apply to European persons and to entities constituted under the laws of an EU Member State. In September 2011, the EU adopted further measures, including, notably, a prohibition on the purchase, import or transportation from Syria of crude oil and petroleum products. Since early September 2011, the Group ceased to purchase hydrocarbons from Syria. On December 1, 2011, the EU extended sanctions against, among others, three state-owned Syrian oil firms, including General Petroleum Corporation, TOTAL’s co-contracting partner in PSA 1988 (Deir Es Zor licence) and the Tabiyeh contract. TOTAL has ceased its activities that contribute to oil and gas production in Syria.

The U.S. Treasury Department’s Office of Foreign Assets Control (referred to as “OFAC”) administers and enforces broad and comprehensive economic sanctions programs, as well as sanctions that are based on the United Nations Security Council resolutions referred to above and that target individuals engaged in terrorism or weapons proliferation in Iran, using the blocking of assets and trade restrictions. The activities that are restricted depend on the sanctions program and targeted country or parties, and

civil and/or criminal penalties, imposed on a per transaction basis, can be substantial. These OFAC sanctions generally apply to U.S. persons and activities taking place in the United States or that are otherwise subject to U.S. jurisdiction. Sanctions administered by OFAC target, among others, Cuba, Iran, Myanmar (Burma), Sudan and Syria. TOTAL does not believe that these sanctions are applicable to any of its activities in the OFAC-targeted countries and, since the independence of the Republic of South Sudan on July 9, 2011, TOTAL is no longer present in Sudan.

On December 8, 2011, OFAC amended the Sudanese Sanctions Regulations with the publication of two general licenses that authorize all activities and transactions relating to the petroleum and petrochemical industries in the Republic of South Sudan and related financial transactions, and the transshipment of goods, technology and services through Sudan to or from the Republic of South Sudan and related financial transactions.

In addition, many U.S. states have adopted legislation requiring state pension funds to divest themselves of securities in any company with active business operations in Iran or Sudan, and state contracts not to be awarded to such companies. State insurance regulators have adopted similar initiatives relating to investments by insurance companies in companies doing business with the Iranian oil and gas, nuclear, and defense sectors. CISADA supports these state legislative initiatives. If TOTAL’s operations in Iran were determined to fall within the prohibited scope of these laws, and TOTAL were not to qualify for any available exemptions, certain U.S. institutions holding interests in TOTAL may be required to sell their interests. If significant, sales of securities resulting from such laws and/or regulatory initiatives could have an adverse effect on the prices of TOTAL’s securities.

For more information on TOTAL’s presence in Cuba, Iran, Sudan and Syria, see “Item 4. Other Matters — Business Activities in Cuba, Iran, Sudan and Syria”.

 

 

ITEM 4. INFORMATION ON THE COMPANY

HISTORY AND DEVELOPMENT

 

 

TOTAL S.A., a French société anonyme (limited company) incorporated in France on March 28, 1924, together with its subsidiaries and affiliates, is the fifth largest publicly-traded integrated international oil and gas company in the world(1).

With operations in more than 130 countries, TOTAL has activities in every sector of the oil industry: in the upstream (oil and gas exploration, development and production, liquefied natural gas) and downstream (refining, petrochemicals, specialty chemicals, marketing and the

 

 

 

(1) Based on market capitalization (in dollars) as of December 31, 2011.

 

10


Table of Contents

trading and shipping of crude oil and petroleum products). In addition, TOTAL has equity stakes in coal mines and operates in the power generation and renewable energy sectors. TOTAL began its Upstream operations in the Middle East in 1924. Since that time, the Company has grown and expanded its operations worldwide. In early 1999, the Company acquired control of PetroFina S.A. (hereafter referred to as “PetroFina” or “Fina”) and in early 2000, the Company acquired control of Elf Aquitaine S.A. (hereafter referred to as “Elf Aquitaine” or “Elf”).

The Company’s corporate name is TOTAL S.A. Its registered office is 2, place Jean Millier, La Défense 6, 92400 Courbevoie, France. Its telephone number is +33 (0)1 47 44 45 46.

TOTAL S.A. is registered in France at the Nanterre Trade Register under the registration number 542 051 180. The length of the life of the Company is 99 years from March 22, 2000, unless it is dissolved or extended prior to such date.

 

 

BUSINESS OVERVIEW

 

 

TOTAL’s worldwide operations in 2011 were conducted through three business segments: Upstream, Downstream, and Chemicals. The table below gives

information on the geographic breakdown of TOTAL’s activities and is taken from Note 5 to the Consolidated Financial Statements included elsewhere herein.

 

 

(M)    France      Rest of
Europe
     North
America
     Africa      Rest of
world
     Total  

2011

                 

Non-Group sales(a)

     42,626         81,453         15,917         15,077         29,620         184,693   

Property, plant and equipment, intangible assets, net

     5,637         15,576         14,518         23,546         17,593         76,870   

Capital expenditures

     1,530         3,802         5,245         5,264         8,700         24,541   

2010

                 

Non-Group sales(a)

     36,820         72,636         12,432         12,561         24,820         159,269   

Property, plant and equipment, intangible assets, net

     5,666         14,568         9,584         20,166         13,897         63,881   

Capital expenditures

     1,062         2,629         3,626         4,855         4,101         16,273   

2009

                 

Non-Group sales(a)

     32,437         60,140         9,515         9,808         19,427         131,327   

Property, plant and equipment, intangible assets, net

     6,973         15,218         8,112         17,312         11,489         59,104   

Capital expenditures

     1,189         2,502         1,739         4,651         3,268         13,349   

 

(a) Non-Group sales from continuing operations.

UPSTREAM

 

 

TOTAL’s Upstream segment includes the Exploration & Production and Gas & Power divisions. The Group has exploration and production activities in more than forty countries and produces oil or gas in approximately thirty countries. The Group’s Gas & Power division conducts

activities downstream from production related to natural gas, liquefied natural gas (LNG) and liquefied petroleum gas (LPG), as well as power generation and trading, and other activities.

 

 

Exploration & Production

 

 

Exploration and development

TOTAL’s Upstream segment aims at continuing to combine long-term growth and profitability at the level of the best in the industry.

TOTAL evaluates exploration opportunities based on a variety of geological, technical, political and economic factors (including taxes and license terms), and on projected oil and gas prices. Discoveries and extensions of existing fields accounted for approximately 76% of the 2,037 Mboe added to the Upstream segment’s proved reserves during the three-year period ended December 31,

2011 (before deducting production and sales of reserves in place and adding any acquisitions of reserves in place during this period). The remaining 24% comes from revisions of previous estimates. The level of revisions during this three year period was significantly impacted by the effect of successive increases of the reference oil price (from $36.55/b at the end of 2008 to $110.96/b in 2011 for Brent crude) which induced a substantial negative revision.

In 2011, the exploration investments of consolidated subsidiaries amounted to 1,629 million (including exploration bonuses included in the unproved property

 

 

11


Table of Contents

acquisition costs). Exploration investments were made primarily in Norway, the United Kingdom, Angola, Brazil, Azerbaijan, Indonesia, Brunei, Kenya, French Guiana and Nigeria. In 2010, the exploration investments of consolidated subsidiaries amounted to 1,472 million (including exploration bonuses included in the unproved property acquisition costs). The main exploration investments were made in Angola, Norway, Brazil, the United Kingdom, the United States, Indonesia, Nigeria and Brunei. In 2009, exploration investments of consolidated subsidiaries amounted to 1,486 million (including exploration bonuses included in the unproved property acquisition costs) notably in the United States, Angola, the United Kingdom, Norway, Libya, Nigeria and the Republic of the Congo.

The Group’s consolidated Exploration & Production subsidiaries’ development investments amounted to 10 billion in 2011, primarily in Angola, Nigeria, Norway, Kazakhstan, the United Kingdom, Australia, Canada, Gabon, Indonesia, the Republic of the Congo, the United States and Thailand. The Group’s consolidated Exploration & Production subsidiaries’ development investments amounted to 8 billion in 2010, primarily in Angola, Nigeria, Kazakhstan, Norway, Indonesia, the Republic of the Congo, the United Kingdom, the United States, Canada, Thailand, Gabon and Australia. In 2009, development investments amounted to nearly 8 billion, predominantly in Angola, Nigeria, Norway, Kazakhstan, Indonesia, the Republic of the Congo, the United Kingdom, the United States, Gabon, Canada, Thailand, Russia and Qatar.

Reserves

The definitions used for proved, proved developed and proved undeveloped oil and gas reserves are in accordance with the United States Securities & Exchange Commission (“SEC”) Rule 4-10 of Regulation S-X as amended by the SEC Modernization of Oil and Gas Reporting release issued on December 31, 2008. Proved reserves are estimated using geological and engineering data to determine with reasonable certainty whether the crude oil or natural gas in known reservoirs is recoverable under existing regulatory, economic and operating conditions.

TOTAL’s oil and gas reserves are consolidated annually, taking into account, among other factors, levels of production, field reassessments, additional reserves from discoveries and acquisitions, disposal of reserves and other economic factors. Unless otherwise indicated, any reference to TOTAL’s proved reserves, proved developed reserves, proved undeveloped reserves and production reflects the Group’s entire share of such reserves or such production. TOTAL’s worldwide proved reserves include the proved reserves of its consolidated subsidiaries as well as its

proportionate share of the proved reserves of equity affiliates. For further information concerning changes in TOTAL’s proved reserves for the years ended December 31, 2011, 2010 and 2009, see “Supplemental Oil and Gas Information (Unaudited)”.

The reserves estimation process involves making subjective judgments. Consequently, estimates of reserves are not exact measurements and are subject to revision under well-established control procedures.

The reserves booking process requires, among other things:

 

 

internal peer reviews of technical evaluations to ensure that the SEC definitions and guidance are followed; and

 

that management makes significant funding commitments towards the development of the reserves prior to booking.

For further information regarding the preparation of reserves estimates, see “Supplemental Oil and Gas Information (Unaudited)”.

Proved reserves

In accordance with the amended Rule 4-10 of Regulation S-X, proved reserves for the years ended on or after December 31, 2009, are calculated using a 12-month average price determined as the unweighted arithmetic average of the first-day-of-the-month price for each month of the relevant year unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The reference prices for 2011, 2010 and 2009 were, respectively, $110.96/b, $79.02/b and $59.91/b for Brent crude.

As of December 31, 2011, TOTAL’s combined proved reserves of oil and gas were 11,423 Mboe (53% of which were proved developed reserves). Liquids (crude oil, natural gas liquids and bitumen) represented approximately 51% of these reserves and natural gas the remaining 49%. These reserves were located in Europe (mainly in Italy, Norway and the United Kingdom), in Africa (mainly in Angola, Gabon, Libya, Nigeria and the Republic of the Congo), in the Americas (mainly in Canada, the United States, Argentina and Venezuela), in the Middle East (mainly in Qatar, the United Arab Emirates and Yemen), and in Asia (mainly in Australia, Indonesia, Kazakhstan and Russia).

As of December 31, 2010, TOTAL’s combined proved reserves of oil and gas were 10,695 Mboe (53% of which were proved developed reserves). Liquids (crude oil, natural gas liquids and bitumen) represented approximately 56% of these reserves and natural gas the remaining 44%. These reserves were located in Europe (mainly in Norway

 

 

12


Table of Contents

and the United Kingdom), in Africa (mainly in Angola, Gabon, Libya, Nigeria and the Republic of the Congo), in the Americas (mainly in Canada, the United States, Argentina and Venezuela), in the Middle East (mainly in Qatar, the United Arab Emirates and Yemen), and in Asia (mainly in Indonesia and Kazakhstan).

As of December 31, 2009, TOTAL’s combined proved reserves of oil and gas were 10,483 Mboe (56% of which were proved developed reserves). Liquids (crude oil, natural gas liquids and bitumen) represented approximately 54% of these reserves and natural gas the remaining 46%. These reserves were located in Europe (mainly in Norway and the United Kingdom), in Africa (mainly in Angola, Gabon, Libya, Nigeria and the Republic of the Congo), in the Americas (mainly in Canada, the United States, Argentina and Venezuela), in the Middle East (mainly in Oman, Qatar, the United Arab Emirates and Yemen), and in Asia (mainly in Indonesia and Kazakhstan).

Sensitivity to oil and gas prices

Changes in the price used as a reference for the proved reserves estimation result in non-proportionate inverse changes in proved reserves associated with production sharing and risked service contracts (which together represent approximately 26% of TOTAL’s reserves as of December 31, 2011). Under such contracts, TOTAL is entitled to a portion of the production, the sale of which is meant to cover expenses incurred by the Group. As oil prices increase, fewer barrels are necessary to cover the same amount of expenses. Moreover, the number of barrels retrievable under these contracts may vary according to criteria such as cumulative production, the rate of return on investment or the income-cumulative expenses ratio. This decrease is partly offset by an extension of the duration over which fields can be produced economically. However, the increase in reserves due to extended field life resulting from higher prices is generally less than the decrease in reserves under production sharing or risked service contracts due to such higher prices. As a result, higher prices lead to a decrease in TOTAL’s reserves.

Furthermore, changes in the price used as a reference for the proved reserves estimation impact the volume of royalties in Canada and thus TOTAL’s share of proved reserves.

Production

For the full year 2011, average daily oil and gas production was 2,346 kboe/d compared to 2,378 kboe/d in 2010.

Liquids accounted for approximately 52% and natural gas accounted for approximately 48% of TOTAL’s combined liquids and natural gas production in 2011.

The table on the next page sets forth by geographic area TOTAL’s average daily production of liquids and natural gas for each of the last three years.

Consistent with industry practice, TOTAL often holds a percentage interest in its fields rather than a 100% interest, with the balance being held by joint venture partners (which may include other international oil companies, state-owned oil companies or government entities). TOTAL frequently acts as operator (the party responsible for technical production) on acreage in which it holds an interest. See the table “Presentation of production activities by region” on the following pages for a description of TOTAL’s producing assets.

As in 2010 and 2009, substantially all of the liquids production from TOTAL’s Upstream segment in 2011 was marketed by the Trading & Shipping division of TOTAL’s Downstream segment. See the table “— Business Overview — Trading & Shipping — Trading division’s supply and sales of crude oil”.

The majority of TOTAL’s natural gas production is sold under long-term contracts. However, its North American production, and part of its production from the United Kingdom, Norway and Argentina, is sold on the spot market. The long-term contracts under which TOTAL sells its natural gas usually provide for a price related to, among other factors, average crude oil and other petroleum product prices, as well as, in some cases, a cost-of-living index. Though the price of natural gas tends to fluctuate in line with crude oil prices, a slight delay may occur before changes in crude oil prices are reflected in long-term natural gas prices. Due to the interaction between the contract price of natural gas and crude oil prices, contract prices are not usually affected by short-term market fluctuations in the spot price of natural gas.

Some of TOTAL’s long-term contracts, notably in Argentina, Indonesia, Nigeria, Norway, Qatar and Russia, specify the delivery of quantities of natural gas that may or may not be fixed and determinable. Such delivery commitments vary substantially, both in duration and in scope, from contract to contract throughout the world. For example, in some cases, contracts require delivery of natural gas on an as-needed basis, and, in other cases, contracts call for the delivery of varied amounts of natural gas over different periods of time. Nevertheless, TOTAL estimates the fixed and determinable quantity of gas to be delivered over the period 2012-2014 to be 4,051 Bcf. The Group expects to satisfy most of these obligations through the production of its proved reserves of natural gas, with, if needed, additional sourcing from spot market purchases. See “Supplemental Oil and Gas Information (Unaudited)”.

 

 

13


Table of Contents

PRODUCTION BY REGION

 

      2011      2010      2009  
      Liquids
kb/d
     Natural
gas
Mcf/d
     Total
kboe/d
     Liquids
kb/d
     Natural
gas
Mcf/d
     Total
kboe/d
     Liquids
kb/d
     Natural
gas
Mcf/d
     Total
kboe/d
 

Africa

     517         715         659         616         712         756         632         599         749   

Algeria

     16         94         33         25         87         41         47         143         74   

Angola

     128         39         135         157         34         163         186         33         191   

Cameroon

     2         1         3         9         2         9         12         2         12   

Gabon

     55         17         58         63         20         67         67         20         71   

Libya

     20                 20         55                 55         60                 60   

Nigeria

     179         534         287         192         542         301         159         374         235   

The Congo, Republic of

     117         30         123         115         27         120         101         27         106   

North America

     27         227         67         30         199         65         20         22         24   

Canada(a)

     11                 11         10                 10         8                 8   

United States

     16         227         56         20         199         55         12         22         16   

South America

     71         648         188         76         569         179         80         564         182   

Argentina

     14         397         86         14         381         83         15         364         80   

Bolivia

     3         118         25         3         94         20         3         91         20   

Colombia

     5         27         11         11         34         18         13         45         23   

Trinidad & Tobago

     4         47         12         3         2         3         5         2         5   

Venezuela

     45         59         54         45         58         55         44         62         54   

Asia-Pacific

     27         1,160         231         28         1,237         248         33         1,228         251   

Australia

             25         4                 6         1                           

Brunei

     2         56         13         2         59         14         2         49         12   

Indonesia

     18         757         158         19         855         178         25         898         190   

Myanmar

             119         15                 114         14                 103         13   

Thailand

     7         203         41         7         203         41         6         178         36   

CIS

     22         525         119         13         56         23         14         52         24   

Azerbaijan

     4         57         14         3         54         13         3         50         12   

Russia

     18         468         105         10         2         10         11         2         12   

Europe

     245         1,453         512         269         1,690         580         295         1,734         613   

France

     5         69         18         5         85         21         5         100         24   

The Netherlands

     1         214         38         1         234         42         1         254         45   

Norway

     172         619         287         183         683         310         199         691         327   

United Kingdom

     67         551         169         80         688         207         90         689         217   

Middle East

     317         1,370         570         308         1,185         527         307         724         438   

United Arab Emirates

     226         72         240         207         76         222         201         72         214   

Iran

                             2                 2         8                 8   

Oman

     24         62         36         23         55         34         22         56         34   

Qatar

     44         616         155         49         639         164         50         515         141   

Syria

     11         218         53         14         130         39         14         34         20   

Yemen

     12         402         86         13         285         66         12         47         21   

Total production

     1,226         6,098         2,346         1,340         5,648         2,378         1,381         4,923         2,281   

Including share of equity affiliates

     316         1,383         571         300         781         444         286         395         359   

Algeria

     10         3         10         19         4         20         20         3         21   

Colombia

     4                 4         7                 7         6                 6   

Venezuela

     44         7         45         45         6         46         44         6         45   

United Arab Emirates

     219         62         231         199         66         212         191         62         202   

Oman

     22         62         34         22         55         32         22         56         34   

Qatar

     8         382         78         8         367         75         3         221         42   

Russia

     9         465         95                                                   

Yemen

             402         74                 283         52                 47         9   

 

(a) The Group’s production in Canada consists of bitumen only. All of the Group’s bitumen production is in Canada.

 

14


Table of Contents

PRESENTATION OF PRODUCTION ACTIVITIES BY REGION

The table below sets forth, by country, TOTAL’s producing assets, the year in which TOTAL’s activities commenced, the Group’s interest in each asset and whether TOTAL is operator of the asset.

 

TOTAL’s producing assets as of December 31, 2011(a)      
      Year of
entry into
the country
  

Operated

(Group share in %)

  

Non-operated

(Group share in %)

Africa

              

Algeria

   1952      
               Tin Fouye Tabankort (35.00%)

Angola

   1953   

Girassol, Jasmim,

Rosa, Dalia, Pazflor (Block 17) (40.00%)

  
              

Block 0 (10.00%)

Kuito, BBLT, Tombua-Landana (Block 14) (20.00%)

Oombo (Block 3/91) (50.00%)

The Congo, Republic of

   1928   

Kombi-Likalala-Libondo (65.00%)

Moho Bilondo (53.50%)

Nkossa (53.50%)

Nsoko (53.50%)

Sendji (55.25%)

Tchendo (65.00%)

Tchibeli-Litanzi-Loussima (65.00%) Tchibouela (65.00%)

Yanga (55.25%)

  
              

Loango (50.00%)

Zatchi (35.00%)

Gabon

   1928   

Anguille (100.00%)

Anguille Nord-Est (100.00%)

Anguille Sud-Est (100.00%)

Atora (40.00%)

Avocette (57.50%)

Ayol Marine (100.00%)

Baliste (50.00%)

Barbier (100.00%)

Baudroie Marine (50.00%)

Baudroie Nord Marine (50.00%)

Coucal (57.50%)

Girelle (100.00%)

Gonelle (100.00%)

Grand Anguille Marine (100.00%) Grondin (100.00%)

Hylia Marine (75.00%)

Lopez Nord (100.00%)

Mandaros (100.00%)

M’Boumba (100.00%)

Mérou Sardine Sud (50.00%)

Pageau (100.00%)

Port Gentil Océan (100.00%)

Port Gentil Sud Marine (100.00%) Tchengue (100.00%)

Torpille (100.00%)

Torpille Nord Est (100.00%)

  
               Rabi Kounga (47.50%)

Libya

   1959        

Zones 15, 16 & 32 (ex C 137, 75.00%(b)) Zones 70 & 87 (ex C 17, 75.00%(b))

Zones 129 & 130 (ex NC 115, 30.00%(b)) Zones 130 & 131 (ex NC 186, 24.00%(b))

Nigeria

   1962   

OML 58 (40.00%)

OML 99 Amenam-Kpono (30.40%)

OML 100 (40.00%)

OML 102 (40.00%)

   OML 102-Ekanga (40.00%)
      OML 130 (24.00%)   
              

Shell Petroleum Development Company (SPDC 10.00%)

OML 118-Bonga (12.50%)

 

15


Table of Contents
      Year of
entry into
the country
  

Operated

(Group share in %)

  

Non-operated

(Group share in %)

North America

              

Canada

   1999      
               Surmont (50.00%)

United States

   1957      
              

Several assets in the Barnett Shale

area (25.00%)(c)

Several assets in the Utica Shale area (25.00%)(c)

Tahiti (17.00%)

South America

              

Argentina

   1978   

Aguada Pichana (27.27%)

Aries (37.50%)

Cañadon Alfa Complex (37.50%)

Carina (37.50%)

Hidra (37.50%)

San Roque (24.71%)

  
               Sierra Chata (2.51%)

Bolivia

   1995      
              

San Alberto (15.00%) San Antonio (15.00%)

Itau (41.00%)

Colombia

   1973      
               Cusiana (11.60%)

Trinidad & Tobago

   1996      
               Angostura (30.00%)

Venezuela

   1980      
               PetroCedeño (30.323%) Yucal Placer (69.50%)

Asia-Pacific

              

Australia

   2005      
               GLNG (27.50%)

Brunei

   1986    Maharaja Lela Jamalulalam (37.50%)     

Indonesia

   1968   

Bekapai (50.00%)

Handil (50.00%)

Peciko (50.00%)

Sisi-Nubi (47.90%)

Tambora (50.00%)

Tunu (50.00%)

  
              

Badak (1.05%)

Nilam-gas and condensates (9.29%)

Nilam-oil (10.58%)

Myanmar

   1992    Yadana (31.24%)     

Thailand

   1990      
               Bongkot (33.33%)

Commonwealth of Independent States

    

Azerbaijan

   1996      
               Shah Deniz (10.00%)

Russia

   1991    Kharyaga (40.00%)   
               Several fields through the participation in Novatek (14.09%)

Europe

              

France

   1939   

Lacq (100.00%)

Meillon (100.00%)

Pécorade (100.00%)

Vic-Bilh (73.00%)

Lagrave (100.00%)

Lanot (100.00%)

Itteville (78.73%)

La Croix-Blanche (100.00%)

Vert-le-Grand (90.05%)

Vert-le-Petit (100.00%)

  
               Dommartin-Lettrée (56.99%)

 

16


Table of Contents
      Year of
entry into
the country
  

Operated

(Group share in %)

  

Non-operated

(Group share in %)

Norway

   1965    Skirne (40.00%)   
              

Åsgard (7.68%)

Ekofisk (39.90%)

Eldfisk (39.90%)

Embla (39.90%)

Gimle (4.90%)

Glitne (21.80%)

Gungne (10.00%)

Heimdal (16.76%)

Huldra (24.33%)

Kristin (6.00%)

Kvitebjørn (5.00%)

Mikkel (7.65%)

Morvin (6.00%)

Oseberg (10.00%)

Oseberg East (10.00%)

Oseberg South (10.00%)

Sleipner East (10.00%)

Sleipner West (9.41%)

Snøhvit (18.40%)

Snorre (6.18%)

Statfjord East (2.80%)

Sygna (2.52%)

Tor (48.20%)

Tordis (5.60%)

Troll I (3.69%)

Troll II (3.69%)

Tune (10.00%)

Tyrihans (23.18%)

Vale (24.24%)

Vigdis (5.60%)

Vilje (24.24%)

Visund (7.70%)

Yttergryta (24.50%)

The Netherlands

   1964   

F6a gas (55.66%)

F6a oil (65.68%)

F15a Jurassic (38.20%)

F15a/F15d Triassic (32.47%)

F15d (32.47%)

J3a (30.00%)

K1a (40.10%)

K1b/K2a (54.33%)

K2c (54.33%)

K3b (56.16%)

K3d (56.16%)

K4a (50.00%)

K4b/K5a (36.31%)

K5b (45.27%)

K6/L7 (56.16%)

L1a (60.00%)

L1d (60.00%)

L1e (55.66%)

L1f (55.66%)

L4a (55.66%)

  
              

E16a (16.92%)

E17a/E17b (14.10%)

J3b/J6 (25.00%)

Q16a (6.49%)

 

17


Table of Contents
     Year of
entry into
the country
 

Operated

(Group share in %)

 

Non-operated

(Group share in %)

United Kingdom

  1962  

Alwyn North, Dunbar, Ellon, Grant Nuggets (100.00%)

Elgin-Franklin (EFOG 46.17%)(d)

Forvie Nord (100.00%)

Glenelg (49.47%)

Jura (100.00%)

West Franklin (EFOG 46.17%)(d)

 
           

Alba (12.65%)

Armada (12.53%)

Bruce (43.25%)

Markham unitized fields (7.35%)

ETAP (Mungo, Monan) (12.43%)

Everest (0.87%)

Keith (25.00%)

Maria (28.96%)

Otter (50.00%)

Seymour (25.00%)

Middle East

           

U.A.E.

  1939   Abu Dhabi-Abu Al Bu Khoosh (75.00%)  
           

Abu Dhabi offshore (13.33%)(e)

Abu Dhabi onshore (9.50%)(f)

GASCO (15.00%)

ADGAS (5.00%)

Oman

  1937    
           

Various fields onshore (Block 6) (4.00%)(g)

Mukhaizna field (Block 53) (2.00%)(h)

Qatar

  1936   Al Khalij (100.00%)  
           

North Field-Block NF Dolphin (24.50%) North Field-Block NFB (20.00%)

North Field-Qatargas 2 Train 5 (16.70%)

Syria

  1988   Deir Ez Zor (Al Mazraa, Atalla North, Jafra, Marad, Qahar, Tabiyeh) (100.00%)(i)    

Yemen

  1987   Kharir/Atuf (Block 10) (28.57%)  
            Various fields onshore (Block 5) (15.00%)

 

(a) The Group’s interest in the local entity is approximately 100% in all cases except for Total Gabon (58.28%) and certain entities in the United Kingdom, Abu Dhabi and Oman (see notes b through h below).
(b) TOTAL’s stake in the foreign consortium.
(c) TOTAL’s interest in the joint venture.
(d) TOTAL has a 46.17% indirect interest in Elgin Franklin through its interest in EFOG.
(e) Through ADMA (equity affiliate), TOTAL has a 13.33% interest and participates in the operating company, Abu Dhabi Marine Operating Company.
(f) Through ADPC (equity affiliate), TOTAL has a 9.50% interest and participates in the operating company, Abu Dhabi Company for Onshore Oil Operation.
(g) TOTAL has a direct interest of 4.00% in Petroleum Development Oman LLC, operator of Block 6, in which TOTAL has an indirect interest of 4.00% via Pohol (equity affiliate). TOTAL also has a 5.54% interest in the Oman LNG facility (trains 1 and 2), and an indirect participation of 2.04% through OLNG in Qalhat LNG (train 3).
(h) TOTAL has a direct interest of 2.00% in Block 53.
(i) Operated by DEZPC, which is 50% owned by TOTAL and 50% owned by GPC. Following the extension of European Union sanctions against Syria on December 1, 2011, TOTAL has ceased its activities that contribute to oil and gas production in Syria. For further information on U.S. and European restrictions relevant to TOTAL’s activities in Syria, see “Item 3. Key Information — Risk Factors”.

 

Africa

In 2011, TOTAL’s production in Africa was

659 kboe/d, representing 28% of the Group’s overall production, compared to 756 kboe/d in 2010 and

749 kboe/d in 2009.

In Algeria, TOTAL’s production was 33 kboe/d in 2011, compared to 41 kboe/d in 2010 and 74 kboe/d in 2009.

This decline was due on the one hand to the termination of the Hamra contract in October 2009 and on the other hand to the divestment of TOTAL’s stake in CEPSA (48.83%), which was finalized in July 2011. The Group’s production now comes entirely from the TFT field (Tin Fouyé Tabenkort, 35%). TOTAL also has 37.75% and 47% stakes in the Timimoun and Ahnet gas development projects respectively.

 

 

18


Table of Contents
 

On the TFT field, plateau production was maintained at 185 kboe/d. A 3D seismic survey covering 1,380 km2 on the East and West portions of the field was completed in October 2011. The data is currently being processed and interpreted.

 

Launched in 2010 following approval of the development plan by the ALNAFT national agency, the basic engineering phase for the Timimoun project has been completed. Commercial gas production is scheduled to start up in 2016, with anticipated plateau production of 1.6 Bm3/y (160 Mcf/d).

 

Under the Ahnet project, the technical section of a development plan was submitted to the authorities in July 2011. Discussions are underway with the project partners and the authorities with regard to bringing the gas to market, with anticipated plateau production of 4 Bm3/y (400 Mcf/d).

In Angola, the Group’s production was 135 kboe/d in 2011, compared to 163 kboe/d in 2010 and 191 kboe/d in 2009. Production comes mainly from Blocks 0, 14 and 17. Highlights of the period 2009 to 2011 included several discoveries on Blocks 15/06 and 17/06, and progress on the major Pazflor and CLOV projects.

 

 

Deep-offshore Block 17 (40%, operator) is TOTAL’s principal asset in Angola. It is composed of four major zones: Girassol, Dalia, Pazflor and CLOV.

On the Girassol hub, production from the Girassol, Jasmim and Rosa fields was 220 kb/d in 2011.

On the Dalia hub, production was nearly 240 kb/d in 2011.

Production on Pazflor, the third hub consisting of the Perpetua, Zinia, Hortensia and Acacia fields, started up in August 2011 and reached 170 kb/d at the end of 2011. The production capacity of the FPSO is 220 kb/d.

The development of CLOV, the fourth hub, started in 2010 and will result in the installation of a fourth FPSO with a capacity of 160 kb/d. Start-up of production is expected in 2014.

 

 

On Block 14 (20%), production on the Tombua-Landana field started in August 2009 and adds to production from the Benguela-Belize-Lobito-Tomboco and Kuito fields.

 

 

On ultra-deep offshore Block 32 (30%, operator), appraisal is continuing and pre-development studies for a first production zone in the central/southeastern portion of the block are underway (Kaombo project).

 

 

On Block 15/06 (15%), a first development hub including the discoveries located on the northwest portion of the block has been identified. The development plan for the hub has been submitted to the authorities.

TOTAL has operations on exploration Blocks 33 (55%, operator), 17/06 (30%, operator), 25 (35%, operator), 39 (15%) and 40 (50%, operator).

TOTAL is also developing in LNG through the Angola LNG project (13.6%), which includes a gas liquefaction plant near Soyo. The plant will be supplied in particular by the gas associated with production from Blocks 0, 14, 15, 17 and 18. Construction work is ongoing and start-up is expected in 2012.

In Cameroon, the Group’s production was 3 kboe/d in 2011, compared to 9 kboe/d in 2010 and 12 kboe/d in 2009. In April 2011, TOTAL finalized the divestment of its stake in its upstream subsidiary Total E&P Cameroon, a Cameroonian company in which the Group had a 75.8% holding. Since that time, the Group no longer owns any exploration and production assets in the country.

In Côte d’Ivoire, TOTAL is operator of the Cl-100 exploration license, with a 60% stake. The 2,000 km2 license is located approximately 100 km southeast of Abidjan in water depths ranging from 1,500 to 3,100 m. Exploration work started with a 3D seismic survey of over 1,000 km2 at the end of 2011, which completed the 3D coverage of the entire block. Initial exploratory drilling is planned for the end of 2012.

In February 2012, TOTAL acquired interests in three ultra-deepwater exploration licenses : CI-514 (54%, operator), CI-515 (45%) and CI-516 (45%). For the two last blocks TOTAL will become the operator upon the first commercial discovery. The work program includes a 3D seismic survey of the whole acreage and one well to be drilled on each block during the initial three-year exploration period.

In Egypt, TOTAL signed a concession agreement in February 2010 and became operator of Block 4 (East El Burullus Offshore) with a 90% stake. The license, located in the Nile Basin where a number of gas discoveries have been made, covers a 4-year initial exploration period and includes a commitment to carrying out 3D seismic work and drilling exploration wells. Following the 3,374 km2 3D seismic survey shot in 2011, drilling is under preparation.

In Gabon, the Group’s production was 58 kboe/d in 2011, compared to 67 kboe/d in 2010 and 71 kboe/d in 2009, due to the natural decline of fields. The Group’s exploration and production activities in Gabon are mainly carried out

 

 

19


Table of Contents

by Total Gabon(1), one of the Group’s oldest subsidiaries in sub-Saharan Africa.

 

 

Under the Anguille field redevelopment project, the AGM N platform, from which twenty-one additional development wells are to be drilled, left the Fos-sur-Mer shipyard at the end of 2011 for Gabon. The drilling campaign is expected to start at the beginning of the second quarter of 2012.

 

On the deep-offshore Diaba license (Total Gabon 63.75%, operator), following the 2D seismic survey that was performed in 2008 and 2009, a 6,000 km2 3D seismic was shot in 2010. This new seismic survey has been processed and the results are currently being interpreted.

 

Total Gabon farmed into the onshore Mutamba-Iroru (50%), DE7 (30%) and Nziembou (20%) exploration licenses in 2010. Following negative exploratory drilling on license DE7, Total Gabon relinquished the license in 2011. Studies are underway to shoot a seismic survey on the Nziembou license and drill an exploration well on the Mutamba license in 2012.

In Kenya, TOTAL acquired in September 2011 a 40% stake in five offshore licenses in the Lamu Basin: L5, L7, L11a, L11b and L12. This transaction has been approved by the Kenyan authorities.

In Libya, the Group’s production was 20 kb/d in 2011, compared to 55 kb/d in 2010 and 60 kb/d in 2009. Events in the country forced the entire industry to stop production and freeze development. Depending on the field, production was suspended from late February or early March 2011. The new EPSA IV contracts came into effect in 2010. At that time, the contract zones in which TOTAL is a partner were redefined: 15, 16 & 32 (formerly C 137, 75%(2)), 70 & 87 (formerly C 17, 75%(2)), 129 & 130 (formerly NC 115, 30%(2)) and 130 & 131 (formerly NC 186, 24%(2)).

 

 

In offshore zones 15, 16 and 32, production resumed in September 2011 and reached its former level within a few days. Exploration work is expected to restart in 2012.

 

In onshore zones 70 and 87, production resumed in January 2012. It will gradually be ramped back up to plateau level.

In addition, the Group expects to continue the development of the Dahra and Garian fields.

 

 

In onshore zones 129, 130 and 131, production resumed in October 2011. A return to plateau level

   

production is expected during 2012. The seismic campaign started before the events is expected to resume by the end of 2012.

 

In the onshore Murzuk Basin, following a successful appraisal well drilled on the discovery made on a portion of Block NC 191 (100%(2), operator), a development plan was submitted to the authorities in 2009. After the interruption related to the events, discussions with the authorities have resumed.

In Madagascar, TOTAL acquired in 2008 a 60% stake in the Bemolanga license (operator), to appraise the oil sand accumulations it contains. The appraisal phase did not confirm the feasibility of the mining development of the resources. However, the contract was extended by one year until June 2012 to assess the conventional exploration potential of the license.

In Mauritania, TOTAL has exploration operations on the Ta7 and Ta8 licenses (60%, operator), located in the Taoudenni Basin. In January 2012, TOTAL (90%, operator) acquired interests in two exploration licenses: Block C9 in ultra-deep offshore, and Block Ta29 onshore in the Taoudenni Basin.

 

 

On the Ta7 license, a 1,220 km 2D seismic survey was shot in 2011 and is being interpreted.

 

On the Ta8 license, drilling of the exploration well ended in 2010. Results from the well were disappointing.

 

On the C9 and Ta29 licenses, a seismic acquisition campaign is planned as the first phase of the exploration program.

In Nigeria, the Group’s production was 287 kboe/d in 2011, compared to 301 kboe/d in 2010 and 235 kboe/d in 2009. TOTAL has been present in Nigeria since 1962. It operates seven production licenses (OML) out of the forty-four in which it has a stake, and two exploration licenses (OPL) out of the eight in which it has a stake. The Group is also active in LNG through Nigeria LNG and the Brass LNG project. With regard to recent changes in acreage:

 

 

In 2011, TOTAL (operator) increased its stake from 45.9% to 48.3% in Block 1 of the Joint Development Zone, administered jointly by Nigeria and São Tomé and Principe.

 

 

The divestment of 10% of the Group’s stakes held through the joint venture operated by Shell Petroleum Development Company (SPDC) in Blocks OML 26 and 42 has been finalized.

 

 

 

(1) Total Gabon is a Gabonese company whose shares are listed on Euronext Paris. TOTAL holds 58.28%, the Republic of Gabon holds 25% and the public float is 16.72%.
(2) TOTAL’s stake in the foreign consortium.

 

20


Table of Contents
 

TOTAL owns 15% of the Nigeria LNG gas liquefaction plant, located on Bonny Island, with an overall LNG capacity of 22.7 Mt/y. In 2011, the plant’s operating rate continued to increase and reached 81%, compared to 72% in 2010 and 50% in 2009, mainly due to the increased reliability of gas deliveries from the other suppliers.

Preliminary work continued in 2011 prior to launching the Brass LNG gas liquefaction plant project (17%), which calls for the construction of two trains, each with a capacity of 5 Mt/y. Calls for tenders for the construction of the plant and loading facilities are underway.

 

 

TOTAL continues its efforts to strengthen its ability to supply gas to the LNG projects in which it owns a stake and to meet the growing domestic demand for gas:

 

   

On the OML 136 license (40%), the positive results for the Agge 3 appraisal well confirmed the development potential of the license. Development studies are underway.

   

As part of its joint venture with the Nigerian National Petroleum Company (NNPC), TOTAL is continuing with the project to increase the production capacity of the OML 58 license (40%, operator) from 370 Mcf/d to 550 Mcf/d of gas in 2012. A second phase of this project is expected to allow the development of other resources through these facilities.

   

On the OML 112/117 licenses (40%), TOTAL continued development studies in 2011 for the Ima gas field.

 

 

On the OML 102 license (40%, operator), TOTAL confirmed the launch of the Ofon phase 2 project in 2011 with the signing of the main construction contracts, with production start-up scheduled for 2014. In 2011 the Group also discovered Etisong North, located 15 km from the Ofon field, which is currently producing. This is the second exploration well on the Etisong hub after the Etisong Main discovery made in 2008. The exploration campaign is expected to continue with two additional wells in 2012.

 

 

On the OML 130 license (24%, operator), the Akpo field, which started up in March 2009, reached plateau production of 225 kboe/d in 2010. Production was limited between March and September 2011 by a technical issue on the engine of the gas reinjection compressor (liquids production of 160 kb/d instead of 190 kb/d). On this license, the Group is actively working on the Egina field, for which a development

   

plan has been approved by the Nigerian authorities. Calls for tender are underway and construction is expected to start in 2012.

 

 

On the OML 138 license (20%, operator), TOTAL finalized the development of the Usan offshore project (180 kb/d, production capacity) with the drilling of production wells, installation of sub-sea equipment and connection to the FPSO. Production started up in February 2012.

 

 

TOTAL also strengthened its deep offshore position with the ongoing development of the Bonga Northwest project on the OML 118 license (12.5%).

Due to the relative calm with regard to safety in the Niger Delta region in 2011, it has been possible to maintain oil production operated by the SPDC joint venture, in which TOTAL has a 10% stake, at close to 2010 levels. The SPDC joint venture’s gas production was higher in 2011 as a result of the contribution of the Gbaran-Ubie project, which started up in 2010.

In Uganda, TOTAL finalized in February 2012 its farm-in for an interest of 33.33%, which covers the EA-1 and EA-2 licenses as well as the new Kanywataba license and the Kingfisher production license. All of these licenses are located in the Lake Albert region, where oil resources have already been discovered and a substantial potential remains to be explored.

TOTAL will be the operator of EA-1 and partner on the other licenses. TOTAL and its partners Tullow and CNOOC are embarking on an ambitious exploration and appraisal program from 2012 onwards. First priority will be given to the exploration of Kanywataba and EA-1 licenses west of the Nile.

In the Republic of the Congo, the Group’s production was 123 kboe/d in 2011, compared to 120 kboe/d in 2010 and 106 kboe/d in 2009.

 

 

On the Moho Bilondo field (53.5%, operator), which started up in April 2008, drilling of development wells continued until 2010. The field reached plateau production of 90 kboe/d in June 2010.

Two positive appraisal wells (Bilondo Marine 2 & 3) drilled at year-end 2010 in the southern portion of the field confirmed an additional growth potential as an extension of existing facilities. Studies are underway for the development of these additional reserves.

The development of the resources in the northern portion of the field, the potential of which was bolstered by appraisal and exploration wells drilled in 2008 and 2009, is also being examined (Moho North project).

 

 

21


Table of Contents
 

Production on Libondo (65%, operator), which is part of the Kombi-Likalala-Libondo operating license, started up in March 2011. Plateau production has reached 12 kb/d. A substantial portion of the equipment was sourced locally in Pointe-Noire through the redevelopment of a construction site that had been idle for several years.

In the Democratic Republic of the Congo, following the Presidential decree approving TOTAL’s entry as operator with a 60% interest in Block III of the Graben Albertine, the exploration permit was issued in January 2012 by the Minister of Hydrocarbons for a period of three years. This block is located in the Lake Albert region.

In the Republic of South Sudan, which became an independent state on July 9, 2011, TOTAL holds an interest in Block B and is preparing with state authorities the resumption of exploration activities on this block.

North America

In 2011, TOTAL’s production in North America was 67 kboe/d, representing 3% of the Group’s overall production, compared to 65 kboe/d in 2010 and 24 kboe/d in 2009.

In Canada, TOTAL signed in December 2010 a strategic partnership with Suncor related to the Fort Hills and Joslyn mining projects and the Voyageur upgrader. The partnership was finalized in March 2011 and allows TOTAL to reorganize around two major hubs the different oil sands assets that it has acquired over the last few years: on the one hand, a Steam Assisted Gravity Drainage (SAGD) hub focused on Surmont’s (50%) ongoing development and, on the other hand, a mining and upgrading hub, which includes the TOTAL-operated Joslyn (38.25%) and Suncor-operated Fort Hills (39.2%) mining projects and the Suncor-operated Voyageur upgrader (49%) project. The Group also has a 50% stake in the Northern Lights mining project (operator) and 100% of a number of oil sands leases acquired through several auction sales. In 2011, the Group’s production was 11 kb/d, compared to 10 kb/d in 2010 and 8 kb/d in 2009.

 

 

On the Surmont lease, commercial production in SAGD mode of the first development phase, which started up in late 2007, is now producing around 25 kb/d of bitumen from thirty-five well pairs. The operator plans to drill additional wells in 2012 and to continue to convert the activation method on the existing wells from gas lift to electric submersible pump (ESP) in order to improve production.

In early 2010, the partners of the project decided to launch the construction of the second development

phase. The goal of production start-up from Surmont Phase 2 has been set for 2015 and overall production capacity from the field is expected to increase to 130 kb/d. In April 2011, the authorities issued a license permitting production (phases 1 and 2) of up to 136 kb/d.

 

 

The Joslyn lease is expected to be developed through mining, with a first development phase having an anticipated capacity of 100 kb/d.

The basic engineering for the Joslyn North Mine started in March 2010. To take into account changes to the project following the partnership with Suncor, the revision of the basic engineering is expected to be finalized in 2012. A decision to launch the project is planned for 2013.

Public hearings that are necessary for the project to be approved by the Canadian authorities were held in autumn 2010. The project was recommended as being in the public interest in January 2011, and approval from the Alberta authorities (Order in Council, OIC) was obtained in April 2011. The provincial authorizations from the Energy Resources Conservation Board (ERCB) and Alberta Environment were also obtained in May and September 2011, respectively. The project received federal approval (Federal OIC and approval from the Canadian Ministry of the Environment) at the end of 2011. As a result, preliminary site preparation work began in early 2012 and production is scheduled to start in 2018.

 

 

TOTAL closed in September 2010 the acquisition of UTS and its main asset: a 20% stake in the Fort Hills lease. In December 2010, as part of their partnership, TOTAL acquired from Suncor an additional 19.2% stake in the lease, thereby increasing its stake to 39.2%. Basic engineering and site preparation work are underway. Start-up of the Fort Hills mining project, which has already been approved by the relevant authorities for a first development phase with a capacity of 160 kb/d, is expected in 2016.

 

 

TOTAL had also acquired in late December 2010 a 49% stake in Suncor’s Voyageur upgrader project. This Voyageur upgrader project, which Suncor mothballed at year-end 2008, resumed in 2011 and is expected to start up concurrently with the Fort Hills project. As a consequence, the Group has abandoned its upgrader project in Edmonton.

 

 

In 2008, the Group closed the acquisition of Synenco, the two principal assets of which are a 60% stake in the Northern Lights project and 100% of the adjacent McClelland lease. In early 2009, the Group sold to

 

 

22


Table of Contents
   

Sinopec, the other partner in the project, a 10% stake in the Northern Lights project and a 50% stake in the McClelland lease, reducing its equity stake in each of the assets to 50%. The Northern Lights project is expected to be developed through mining.

In the United States, the Group’s production was 56 kboe/d in 2011, compared to 55 kboe/d in 2010 and 16 kboe/d in 2009.

 

 

In the Gulf of Mexico:

   

The deep-offshore Tahiti oil field (17%) started producing in 2009 and reached production of 135 kboe/d. Phase 2, which was launched in September 2010, comprises drilling four injection wells and two producing wells. Water injection started in February 2012. This phase should partly offset the production decline seen on wells currently in production.

   

Development of the first phase of the deep-offshore Chinook project (33.33%) is ongoing. The production test is scheduled to start in mid-2012 after sub-sea work carried out following an incident on one of the risers.

   

In 2009, TOTAL and Cobalt had signed an agreement related to the merger of their deep offshore acreage, with Cobalt operating the exploration phase. The TOTAL (40%) — Cobalt (60%, operator) alliance’s exploratory drilling campaign was launched in 2009 and the drilling of the first three wells produced disappointing results. This campaign was disrupted due to the U.S. government’s moratorium on offshore drilling operations from May to October 2010 and resumed at the beginning of 2012 with the start of drilling of the Ligurian 2 well.

   

In April 2010, the Group disposed of its equity stakes in the Matterhorn and Virgo operated fields.

 

Following the signature of an agreement in late 2009, a joint venture was set up with Chesapeake to produce shale gas in the Barnett Shale Basin, Texas. Under this joint venture, TOTAL owns 25% of Chesapeake’s portfolio in the area. In 2011, approximately 300 additional wells were drilled, enabling gas production reaching 1.4 Bcf/d in 100% at the end of 2011. Engineers from TOTAL are assigned to the teams led by Chesapeake.

 

At the end of 2011, TOTAL signed an agreement with Chesapeake and EnerVest to enter into a joint venture. Pursuant to the agreement, TOTAL acquired a 25% share in Chesapeake’s and EnerVest’s liquid-rich area

   

of the Utica shale play (Ohio). At the end of 2011, thirteen wells have been drilled across the acreage with very promising results seen from each well in terms of productivity and liquid content.

 

In 2009, the Group closed the acquisition of a 50% stake in American Shale Oil LLC (AMSO) to develop shale oil technology. The pilot to develop this technology is underway in Colorado.

In Mexico, TOTAL is conducting various studies with state-owned PEMEX under a general technical cooperation agreement renewed in July 2011 for a period of five years.

South America

In 2011, TOTAL’s production in South America was 188 kboe/d, representing 8% of the Group’s overall production, compared to 179 kboe/d in 2010 and 182 kboe/d in 2009.

In Argentina, where TOTAL has been present since 1978, the Group operates 30%(1) of the country’s gas production. The Group’s production was 86 kboe/d in 2011, compared to 83 kboe/d in 2010 and 80 kboe/d in 2009.

 

 

In Tierra del Fuego, the Group notably operates the Carina and Aries offshore fields (37.5%). The award of the contracts to build the offshore facilities for the development of the Vega Pleyade gas and condensates field is scheduled for 2012. The project is scheduled to start production in 2014 and should make it possible to maintain the production operated by the Group in Tierra del Fuego at around 615 Mcf/d.

 

 

In the Neuquén Basin, TOTAL started a drilling campaign in 2011 on its operated licenses in order to assess their shale gas potential. The campaign, which started on the Aguada Pichana (27.3%, operator) and San Roque (24.7%, operator) fields, will be extended subsequently to the Rincon la Ceniza and La Escalonada licenses acquired in 2010 (85%, operator) and to the four fields acquired in 2011: Aguada de Castro (42.5%, operator), Pampa de la Yeguas II (42.5%, operator), Cerro Las Minas (40%) and Cerro Partido (45%).

The connection of satellite discoveries on the edge of the main Aguada Pichana field, particularly in the Las Carceles canyons area, and the increase in compression capacity at San Roque, have extended plateau production of the mature fields in these two blocks.

In Bolivia, the Group’s production, primarily gas, amounted to 25 kboe/d in 2011, compared to 20 kboe/d

 

 

 

(1) Source: Argentinean Ministry of Federal Planning, Public Investment and Services — Energy Secretary.

 

23


Table of Contents

in 2010 and 2009. TOTAL has stakes in six licenses: three producing licenses — San Alberto and San Antonio (15%) and Block XX Tarija Oeste (41%), and three licenses in the exploration or appraisal phase — Aquio and Ipati (80%, operator) and Rio Hondo (50%).

 

 

Production started up in February 2011 on the gas and condensates Itaú field located on Block XX Tarija Oeste; it is routed to the existing facilities of the neighboring San Alberto field. A development plan for a second phase at Itaú was approved by the local authorities in June 2011. In early 2011, TOTAL decreased its stake in Block XX Tarija Oeste to 41% after divesting 34% and is no longer the operator.

 

 

In 2004, TOTAL discovered the Incahuasi gas field on the Ipati Block. Following the interpretation of the 3D seismic shot in 2008, an appraisal well was drilled on the adjacent Aquio Block and the extension of the discovery to the north was confirmed in 2011.

Due to the positive results from the well, TOTAL filed a declaration of commerciality for the Aquio and Ipati Blocks, which was approved by the local authorities in April 2011. Additional appraisal work is underway, notably with the drilling of a second well on the Ipati Block in 2012.

 

 

In 2010, TOTAL signed an agreement to dispose of 20% in the Aquio and Ipati licenses to Gazprom. Following approval of the agreement by the Bolivian authorities, TOTAL will have a 60% stake in the licenses.

In Brazil, TOTAL has equity stakes in three exploration blocks: Blocks BC-2 (41.2%) and BM-C-14 (50%) in the Campos Basin, and Block BM-S-54 (20%) in the Santos Basin.

 

 

The Xerelete field is mainly located on Block BC2, with an extension on Block BM-C-14. A unitization agreement was finalized by the partners on both blocks and submitted to the authorities for approval in April 2011.

In 2012, pending the authorities’ approval, TOTAL is expected to become operator of the unitized Xerelete field. After seismic reprocessing, a pre-salt prospect was found under the Xerelete discovery made in 2001 at a water depth of 2,400 m. TOTAL is planning to resume drilling activities on the block in 2012.

 

 

On Block BM-S-54, a first well was drilled in the pre-salt at the end of 2010 on the Gato do Mato structure, and a significant oil column was found. The appraisal plan approved by the authorities in October 2011 includes testing the Gato do Mato well and, if

   

that test is successful, drilling a second well on the structure in 2012. As the Gato do Mato structure extends beyond the boundaries of Block BM-S-54 into a free zone, a draft unitization agreement has been submitted to the authorities.

At the end of 2011, a second structure (Epitonium) identified on Block BM-S-54 was drilled. The results of the well are under analysis.

In Colombia, where TOTAL has had operations since 1973, the Group’s production was 11 kboe/d in 2011, compared to 18 kboe/d in 2010 and 23 kboe/d in 2009. The decline in production in 2011 was mainly due to the divestment of TOTAL’s stake in CEPSA, which was finalized in July 2011.

On the Cusiana field (11.6%), production from the project to extract 6 kb/d of LPG started at the end of 2011.

Following the discovery of Huron-1 in 2009 on the Niscota (50%) exploration license and a 3D seismic survey in 2010, the first appraisal well has been underway since mid-2011. A second appraisal well is expected in 2012.

In 2011, TOTAL sold 10% of its stake in the Ocensa oil pipeline, reducing its holding to 5.2%.

In February 2012, TOTAL signed an agreement to sell TEPMA BV. This wholly-owned affiliate of TOTAL holds the working interest in the Cusiana field as well as a participation in OAM and ODC pipelines in Colombia. This transaction is subject to approval by the relevant authorities.

In French Guiana, TOTAL owns a 25% stake in the Guyane Maritime license. The license, located about 150 km off the coast, covers an area of approximately 26,000 km2 in water depths ranging from 200 to 3,000 m.

Located around 170 km northeast off Cayenne, drilling of the GM-ES-1 well on the Zaedyus prospect took place in 2011. The well was drilled at water depths of over 2,000 m and reached a vertical depth of 5,908 m below sea level. It revealed two hydrocarbon columns in gravelly reservoirs.

This discovery follows on from the shooting of a 3D seismic survey covering 2,500 km2 on the eastern zone of the Guyane Maritime license.

An extensive drilling campaign and a further 3D seismic survey are planned on the license starting in 2012.

In Trinidad & Tobago, where TOTAL has had operations since 1996, the Group’s production was 12 kboe/d in 2011, compared to 3 kboe/d in 2010 and 5 kboe/d in 2009. TOTAL holds a 30% stake in the offshore Angostura

 

 

24


Table of Contents

field located on Block 2C. Production started up in May 2011 on Phase 2, which corresponds to the gas reserves development phase. A drilling campaign on three wells started in mid-2011 in order to increase oil production. An exploration well was also drilled in 2011 and revealed additional gas resources.

In Venezuela, where TOTAL has had operations since 1980, the Group’s production was 54 kboe/d in 2011, compared to 55 kboe/d in 2010 and 54 kboe/d in 2009. TOTAL has equity stakes in PetroCedeño (30.323%), which produces and upgrades extra heavy oil in the Orinoco Belt, in Yucal Placer (69.5%), which produces gas dedicated to the domestic market, and in the offshore exploration Block 4, located in the Plataforma Deltana (49%).

The development phase of the southern portion of the PetroCedeño field was launched in the second half of 2011.

An additional development phase on the Yucal Placer field to increase production capacity from 100 Mcf/d to 300 Mcf/d is under discussion with the authorities.

Asia-Pacific

In 2011, TOTAL’s production in Asia-Pacific was 231 kboe/d, representing 10% of the Group’s overall production, compared to 248 kboe/d in 2010 and 251 kboe/d in 2009.

In Australia, where TOTAL has held leasehold rights since 2005, the Group owns 24% of the Ichthys project, 27.5% of the GLNG project and nine offshore exploration licenses, including four that it operates, off the northwest coast in the Browse, Vulcan and Bonaparte Basins. In 2011, the Group produced 4 kboe/d due to its stake in GLNG, compared to 1 kboe/d in 2010.

 

 

The Ichthys LNG project is aimed at the development of the Ichthys gas and condensates field, located in the Browse Basin. This development includes a floating platform designed for gas production, treatment and export, an FPSO to stabilize and export condensates, an 889 km gas pipeline and an onshore liquefaction plant located in Darwin. The project was launched in early 2012 following completion of the engineering studies, calls for tender and subcontractor selection. The LNG has already been sold under long-term contracts mainly to Asian buyers.

Production capacity is expected to be 8.4 Mt/y of LNG and nearly 1.6 Mt/y of LPG as well as a production of 100 kb/d of condensates at peak. Production start-up is expected at year-end 2016.

 

 

In late 2010, TOTAL acquired a 20% stake in the GLNG project, followed by an additional 7.5% stake in

   

March 2011. This integrated gas production, transport and liquefaction project is based on the development of coal gas from the Fairview, Roma, Scotia and Arcadia fields. The final investment decision was made in January 2011 and start-up is expected in 2015. LNG production is expected to eventually reach 7.2 Mt/y. The preliminary project development and engineering work are continuing. The 420 km pipeline for transporting the gas has received environmental approval. Off the coast near Gladstone, on Curtis Island, site preparations have started with civil engineering, dredging and construction of the initial jetty and the residential compound.

 

 

Following extensive seismic surveying in 2008 and interpretation of the data in 2009, a drilling campaign on two wells started in early 2011 on license WA-403 (60%, operator). As one well demonstrated the presence of hydrocarbons, additional appraisal work will take place on this block (3D seismic).

Three new exploration wells are planned for 2012/2013 on license WA-408 (100%, operator).

In Brunei, where TOTAL has been present since 1986, the Group operates the offshore Maharaja Lela Jamalulalam gas and condensates field located on Block B (37.5%). The Group’s production was 13 kboe/d in 2011, compared to 14 kboe/d in 2010 and 12 kboe/d in 2009. The gas is delivered to the Brunei LNG liquefaction plant.

On Block B, the drilling campaign that started in 2009 continued in 2010 and 2011. Production on the first well started in 2010. The next two wells, which were exploratory, revealed new reserves in the southern portion of the field, for which development studies are underway. A fourth well drilled in 2011 in the southern portion of the field was connected to the production facilities at the end of the year. A ten-year extension of the mining rights period was recently granted by the Brunei government.

On deep-offshore exploration Block CA1 (54%, operator), formerly Block J, exploration operations that had been suspended since May 2003 due to a border dispute between Brunei and Malaysia resumed in September 2010. A seismic survey started before the summer of 2011 and an initial campaign of three drillings started in October 2011.

In China, the Group has had operations since 2006 on the South Sulige Block, located in the Ordos Basin in the Inner Mongolia province. Following appraisal work by TOTAL, China National Petroleum Corporation (CNPC) and TOTAL agreed in November 2010 to submit to the authorities for approval a development plan under which CNPC is the operator and provides the benefit of its experience in

 

 

25


Table of Contents

developing Great Sulige. TOTAL has a 49% stake and provides support in its areas of expertise.

The authorities gave the operator permission to undertake preliminary development work in the spring of 2011. Drilling operations started and additional 3D seismic data was shot in 2011 in preparation for the upcoming drilling campaigns. Start-up of production is expected in 2012.

In Indonesia, where TOTAL has had operations since 1968, the Group’s production was 158 kboe/d in 2011, compared to 178 kboe/d in 2010 and 190 kboe/d in 2009.

TOTAL’s operations in Indonesia are primarily concentrated on the Mahakam permit (50%, operator), which covers in particular the Peciko and Tunu gas fields. TOTAL also has a stake in the Sisi-Nubi gas field (47.9%, operator). TOTAL delivers most of its natural gas production to the Bontang LNG plant operated by the Indonesian company PT Badak. The overall capacity of the eight liquefaction trains of the Bontang plant is 22 Mt/y.

In 2011, gas production operated by TOTAL amounted to 2,227 Mcf/d. The gas operated and delivered by TOTAL accounted for nearly 80% of Bontang LNG’s supply. In addition to gas production, operated condensates and oil production from the Handil and Bekapai fields amounted to 59 kb/d and 23 kb/d, respectively.

 

 

On the Mahakam permit:

   

In 2011, the scheduled drilling of additional wells in the main reservoir of the Tunu field continued with increasing density. The second phase of drilling development wells to discover shallow gas reservoirs has started.

   

On the Peciko field, Phase 7 drilling, which started in 2009, is continuing.

   

The development of South Mahakam, which includes the Stupa, West Stupa and East Mandu fields, is ongoing. Start-up of production is expected in early 2013.

 

On the Sisi-Nubi field, which began production in 2007, drilling operations continue within the framework of a second phase of development. The gas from Sisi-Nubi is produced through Tunu’s processing facilities.

 

In October 2010, TOTAL closed the acquisition of a 15% stake in the Sebuku permit, where the gas field Ruby was discovered. Development of the field, with the aim of producing 100 Mcf/d of natural gas, started in February 2011. Production start-up is scheduled for the end of 2013.

 

On the Southeast Mahakam exploration block (50%, operator), the first exploration well (Trekulu 1) completed at the end of 2010 produced negative results.

 

In May 2010, the Group acquired a 24.5% stake in two exploration blocks — Arafura and Amborip VI — located in the Arafura Sea. Two wells were drilled on these blocks in late 2010/early 2011. The results were negative.

 

In September 2011, TOTAL signed an agreement to acquire a stake in three exploration blocks located in the southern Makassar Strait (Sageri, 50%, South Sageri, 35% and Sadang, 20%). A first well was drilled on the Sageri block at the end of 2011.

 

In September 2011, TOTAL also signed an agreement to acquire a stake in an exploration block located in the southern Makassar Strait (South Mandar, 33%). Under the agreement, the Group acquired additional 10% stakes in the South Sageri and Sadang blocks.

 

In May 2011, TOTAL acquired a 100% stake in the South West Bird’s Head exploration block. The block is located onshore and offshore in the Salawati Basin, in the province of West Papua.

 

The Group signed a production sharing agreement in March 2011, for a 50% stake in a coal bed methane (CBM) field on the Kutai Timur Block in East Kalimantan province.

In the autumn of 2010, the Group signed an agreement with the consortium Nusantara Regas (Pertamina-PGN) for the delivery of 11.75 Mt of LNG over the period 2012-2022 to a re-gasification terminal located near Jakarta. The first deliveries are expected in the second quarter of 2012.

In Malaysia, TOTAL signed a production sharing agreement in 2008 with state-owned Petronas for the offshore exploration Blocks PM303 and PM324. Following the seismic studies performed in 2009 and 2010, TOTAL withdrew from offshore exploration Block PM303 in early 2011. Exploration work continued on Block PM324 (50%, operator); initial drilling in high pressure/high temperature conditions started in October 2011 and continues in 2012.

TOTAL also signed in November 2010 a new production sharing agreement with Petronas for the deep offshore exploration Block SK 317 B (85%, operator) located off the state of Sarawak. 3D seismic surveys have been carried out on the zone. The results should be available shortly.

In Myanmar, the Group’s production was 15 kboe/d in 2011, compared to 14 kboe/d in 2010 and 13 kboe/d in 2009. TOTAL operates the Yadana field (31.2%), located on offshore Blocks M5 and M6, which produces gas that is delivered primarily to PTT (the Thai state-owned company) to be used in Thai power plants. The Yadana field also supplies the domestic market via a land pipeline and, since June 2010, via a sub-sea pipeline built and operated by Myanmar’s state-owned company MOGE.

 

 

26


Table of Contents

In Thailand, the Group’s production was 41 kboe/d in 2011 and 2010, compared to and 36 kboe/d in 2009. This comes from the Bongkot (33.33%) offshore gas and condensates field. PTT purchases all of the natural gas and condensates production.

 

 

On the northern portion of the Bongkot field, the 3H (three wellhead platforms) development phase came onstream in early 2011. New investments are being made to meet gas demand and maintain plateau production:

   

phase 3J (two well platforms) was launched in late 2010 with start-up scheduled for 2012;

   

phase 3K (two well platforms) was approved in September 2011 with start-up scheduled for 2013; and

   

the second low-pressure compressor installation phase to increase gas production was completed in the first quarter of 2012.

 

The southern portion of the field (Greater Bongkot South) is also being developed in several phases. This development is designed to include a processing platform, a residential platform and thirteen production platforms. Construction of the facilities started in 2009 and accelerated in 2011 with the installation of the residential and gas processing platforms in August. Production is expected to start in the spring of 2012, with a capacity of 350 Mcf/d.

In Vietnam, TOTAL holds a 35% stake in the production sharing agreement for the offshore 15-1/05 exploration block following an agreement signed in 2007 with PetroVietnam. Two oil discoveries were made on the southern portion of the block, one in November 2009 and the other in October 2010. The results from the additional wells drilled on these discoveries between November 2010 and October 2011 are being assessed.

In 2009, TOTAL and PetroVietnam signed a production sharing agreement for Blocks DBSCL-02 and DBSCL-03. The onshore blocks, located in the Mekong Delta region, are held by TOTAL (75%, operator) and PetroVietnam (25%). Based on the seismic information obtained in 2009 and 2010, the partners have decided not to continue the exploration work.

Commonwealth of Independent States (CIS)

In 2011, TOTAL’s production in the CIS was 119 kboe/d, representing 5% of the Group’s overall production, compared to 23 kboe/d in 2010 and 24 kboe/d in 2009.

In Azerbaijan, where TOTAL has had operations since 1996, production was 14 kboe/d in 2011, compared to

13 kboe/d in 2010 and 12 kboe/d in 2009. The Group’s production comes from the Shah Deniz field (10%). TOTAL also holds a 10% stake in South Caucasus Pipeline Company, owner of the South Caucasus Pipeline (SCP) gas pipeline that transports the gas produced in Shah Deniz to the Turkish and Georgian markets. TOTAL also holds a 5% stake in BTC Co., owner of the Baku-Tbilisi-Ceyhan (BTC) oil pipeline, which connects Baku and the Mediterranean Sea. In 2009, TOTAL and state-owned SOCAR signed an exploration, development and production sharing agreement for a license located on the Absheron block in the Caspian Sea. TOTAL (40%) is the operator during the exploration phase and a joint operating company will manage operations during the development phase. Drilling of an exploratory well started in early 2011. In September 2011, the well showed the existence of a substantial gas accumulation. The well will be tested in 2012.

Gas deliveries to Turkey and Georgia from the Shah Deniz field continued throughout 2011, at a lower pace for Turkey due to weaker demand than initially forecast. Conversely, SOCAR took greater quantities of gas than provided for by the agreement.

Development studies and business negotiations for the sale of additional gas needed to launch a second development phase in Shah Deniz continued in 2011. In October 2011, SOCAR and Botas, a Turkish state-owned company, signed an agreement on the sale of additional gas volumes and the transfer conditions for volumes intended for the European market. The agreement is expected to enable the start of FEED studies for this second phase in the first quarter of 2012, although some of the commercial provisions of the agreement have yet to be finalized.

In Kazakhstan, TOTAL has owned since 1992 a stake in the North Caspian license, which covers the Kashagan field in particular.

The Kashagan project is expected to be developed in several phases. The development plan for the first phase (300 kb/d) was approved in February 2004 by the Kazakh authorities, allowing work to begin on the field. The consortium continues to target first production by year-end 2012.

In October 2008, the members of the North Caspian Sea Production Sharing Agreement (NCSPSA) consortium and the Kazakh authorities signed agreements to end the disagreement that began in August 2007. Their implementation led to a reduction of TOTAL’s share in NCSPSA from 18.52% to 16.81%. The operating structure was reconfigured and the North Caspian Operating Company (NCOC), a joint operating company, was entrusted with the operatorship in January 2009. NCOC supervises and coordinates NCSPSA’s operations.

 

 

27


Table of Contents

In Russia, where TOTAL has had operations through its subsidiary since 1991, the Group’s production was 105 kboe/d in 2011, compared to 10 kboe/d in 2010 and 12 kboe/d in 2009. This comes from the Kharyaga field (40%, operator) and TOTAL’s stake in Novatek.

 

 

In 2007, TOTAL and Gazprom signed an agreement for the first phase of development on the giant Shtokman gas and condensates field, located in the Barents Sea. Under this agreement, Shtokman Development AG (TOTAL, 25%) was created in 2008 to design, build, finance and operate this first development phase, with estimated overall production capacity of 23.7 Bm3/y (0.4 Mboe/d). Engineering studies are underway for the portion of the project that will allow the transport of gas by pipeline through the Gazprom network (offshore development, gas pipeline and onshore gas and condensates processing facilities on the Teriberka site) and for the LNG part of the project, which will allow the export of 7.5 Mt/y of LNG from a new harbor located in Teriberka, representing approximately half of the gas produced by the first development phase.

 

 

In late 2009, TOTAL closed the acquisition from Novatek of a 49% stake in Terneftegas, which holds a development and production license on the onshore Termokarstovoye field. An appraisal well was drilled in 2010. The results of this well and of the pre-project studies allowed for the final investment decision to be made at year-end 2011.

 

 

On the Kharyaga field, work related to the development plan of phase 3 is ongoing. This development plan is intended to maintain plateau production at the 30 kboe/d (in 100%) level reached in late 2009. TOTAL sold 10% of the field to state-owned Zarubezhneft in January 2010, thereby decreasing its interest to 40%.

 

 

In the autumn of 2009, TOTAL signed an agreement setting forth the principles of a partnership with KazMunaiGas (KMG) for the development of the Khvalynskoye gas and condensates field, located offshore in the Caspian Sea on the border between Kazakhstan and Russia, under Russian jurisdiction. Gas production is expected to be transported to Russia. Pursuant to this agreement, TOTAL is planning to acquire 17% of KMG’s share.

 

 

In March 2011, TOTAL and the Russian listed company Novatek signed a strategic partnership agreement pursuant to which TOTAL acquired a 12.09% stake in Novatek in April 2011, with the intention of both parties for TOTAL to increase its

   

holding to 15% within 12 months and 19.40% within three years. In December 2011, TOTAL increased its stake in Novatek by 2% to 14.09%.

 

 

In October 2011, TOTAL and Novatek signed the final agreements for the joint development of the Yamal LNG project. With a 20% stake, TOTAL has become Novatek’s main international partner in the gas liquefaction project. Novatek, which will retain a 51% stake, intends to dispose of the remaining 29% to other partners. The Yamal LNG project covers the development of the South Tambey gas and condensates field, located on the Yamal Peninsula in the Arctic.

Europe

In 2011, TOTAL’s production in Europe was 512 kboe/d, representing 22% of the Group’s overall production, compared to 580 kboe/d in 2010 and 613 kboe/d in 2009.

In Denmark, TOTAL has owned since June 2010 an 80% stake in and the operatorship for licenses 1/10 (Nordjylland) and 2/10 (Nordsjaelland, formerly Frederoskilde). These onshore licenses, the shale gas potential of which has yet to be assessed, cover areas of 3,000 km2 and 2,300 km2, respectively. Following geoscience surveys on license 1/10 in 2011, the decision was made to drill a well during the second half of 2012. Geoscience surveys are ongoing on license 2/10.

In France, the Group’s production was 18 kboe/d in 2011, compared to 21 kboe/d in 2010 and 24 kboe/d in 2009. TOTAL’s major assets are the Lacq (100%) and Meillon (100%) gas fields, located in the southwest part of the country.

On the Lacq field, operated since 1957, a carbon capture and storage pilot was commissioned in January 2010, and carbon injection is expected to continue until 2013. In connection with this project, a boiler has been modified to operate in an oxy-fuel combustion environment and the carbon dioxide emitted is captured and re-injected in the depleted Rousse field. As part of TOTAL’s sustainable development policy, this project will allow the Group to assess one of the technological possibilities for reducing carbon dioxide emissions.

Agreements were signed in December 2011 for the sale of the Itteville, Vert-le-Grand, Vert-le-Petit, La Croix Blanche, Dommartin Lettrée and Vic-Bilh assets. Operatorship and production rights for these assets were transferred in January 2012.

The Montélimar exclusive exploration license, awarded to TOTAL in March 2010 (100%) to assess, in particular, the

 

 

28


Table of Contents

shale gas potential of the area, was revoked by the government in October 2011. This revocation stemmed from the law of July 13, 2011, prohibiting the exploration and extraction of hydrocarbons by drilling followed by hydraulic fracturing. The Group had, however, submitted the required report to the government, in which it undertook not to use hydraulic fracturing in light of the current prohibition. An appeal has therefore been filed in December 2011 with the administrative court requesting that the judge cancel the revocation of the license.

In Italy, the Tempa Rossa field (75%, operator), discovered in 1989 and located on the unitized Gorgoglione concession (Basilicate region), is one of TOTAL’s principal assets in the country.

In 2011, Total Italia acquired an additional 25% in the Tempa Rossa field, bringing its stake to 75%, as well as shares in two exploration licenses.

Site preparation work started in early August 2008, but the proceedings initiated by the Prosecutor of the Potenza Court against Total Italia led to a freeze in the preparation work (for additional information, see “Item 8. Financial Information — Legal or arbitration proceedings — Italy”). New calls for tenders were launched related to certain contracts that had been cancelled. Drilling of the Gorgoglione 2 appraisal well that started in June 2010 reached its final depth, confirming the results of the other wells. It is expected to be tested in 2012. The extension plan for the Tarente refinery export system, needed for the development of the Tempa Rossa field, was submitted to the Italian authorities in May 2010 and approved at the end of 2011. Site preparation work began and start-up of production is expected in 2015 with a capacity of 55 kboe/d.

In Norway, where the Group has had operations since the mid-1960s, TOTAL has equity stakes in eighty production licenses on the Norwegian continental shelf, seventeen of which it operates. Norway is the largest single-country contributor to the Group’s production, with volumes of 287 kboe/d in 2011, compared to 310 kboe/d in 2010 and 327 kboe/d in 2009.

 

 

In the Norwegian North Sea, where numerous development projects have recently been launched, the Group’s production was 205 kboe/d in 2011. The most substantial contribution to production, for the most part non-operated, comes from the Greater Ekofisk Area (Ekofisk, Eldfisk, Embla, etc.).

 

   

Several projects are underway on the Greater Ekofisk Area, located in the south. The Group owns a 39.9% stake in the Ekofisk and Eldfisk

   

fields. The Ekofisk South and Eldfisk 2 projects were launched in June 2011 following approval of the development and operation plans by the authorities. The project relating to the construction and installation of the new Ekofisk living quarters and utilities platform is now in its second year.

   

On the Greater Hild Area, located in the north and in which the Group has a 51% stake (operator), the Hild development scheme was selected at the end of 2010. The development and operation plan has been submitted to the authorities in early 2012. Approval is expected in 2012, with production start-up scheduled for 2016.

   

A number of successful exploration and appraisal activities were carried out in the North Sea in the 2009-2011 period. These activities have led to the launch of several development projects, which are already underway or for which approval by the authorities is expected in 2012:

  ¡   

In the central section of the North Sea, on license PL102C (40%, operator), a fast-track development project has been launched for the Atla field (formerly known as David), which was discovered in 2010. Start-up of gas production is expected in late 2012.

  ¡   

Gas production on the Beta West field (a satellite of Sleipner, 10%), located in the central section of the North Sea, started in April 2011.

  ¡   

In the Visund area of the Nordic North Sea on license PL120 (7.7%), the Visund South fast-track development project for the Pan/Pandora discoveries is underway. Start-up of production is expected in 2012.

  ¡   

The Stjerne project was launched in 2011 to develop the Katla structure discovered in 2009, located on license PL104 (10%) south of Oseberg in the Nordic North Sea. Start-up of oil production is expected in 2013.

  ¡   

The fast-track development project for the Vigdis North East structure (PL089, 5.6%), discovered in 2009 and located south of Snorre, was launched in 2011. It will also allow for enhanced hydrocarbon recovery from the nearby Vigdis East field. Start-up of oil production is expected in late 2012.

  ¡   

A positive appraisal well was drilled in 2010 on the southern slope of the Dagny-Ermintrude structure (6.54%) north of Sleipner. Approval of the development project is expected at the end of 2012 and production is scheduled to start in late 2016.

 

 

29


Table of Contents
 

In the Norwegian Sea, the Haltenbanken area includes the Tyrihans (23.2%), Mikkel (7.7%) and Kristin (6%) fields as well as the Åsgard (7.7%) field and its satellites Yttergryta (24.5%) and Morvin (6%). Morvin started up in August 2010 as planned, with two producing wells. In 2011, the Group’s production in the Haltenbanken area was 63 kboe/d.

The partners decided to go ahead with the Åsgard sub-sea compression project, which will increase hydrocarbon recovery on the Åsgard and Mikkel fields, and the development and operation plan has been submitted to the authorities.

In 2011, TOTAL successfully drilled an exploration well on the Alve North structure on license PL127 (50%, operator) near the Norne field.

 

 

In the Barents Sea, LNG production on Snøhvit (18.4%) started in 2007. This project includes development of the Snøhvit, Albatross and Askeladd natural gas fields, as well as the construction of the associated liquefaction facilities. Due to design problems, the plant experienced reduced capacity during the start-up phase. A number of maintenance turnarounds were scheduled to address the issue and the plant is now operating at its design capacity (4.2 Mt/y). In 2011, the Group’s production was 19 kboe/d.

In 2011, TOTAL drilled a positive exploration well on the Norvarg structure in the Barents Sea on license PL535 (40%, operator), which was awarded during the twentieth licensing round.

The Group improved its asset portfolio in Norway by obtaining new licenses and divesting a number of non-strategic assets:

 

 

In 2011, TOTAL obtained four new exploration licenses during licensing round APA 2010 (Awards in Predefined Areas), including one as operator. The Group also acquired in 2011 a 40% stake and the role of operator of license PL554, north of Visund. Drilling of an exploration well is expected on the license in 2012. At the beginning of 2012, during licensing round APA 2011, TOTAL obtained eight new licences, including five as operator.

 

In 2010, the Group divested its stake in the Valhall/Hod fields.

 

In June 2011, TOTAL announced that it had signed an agreement for the planned sale of its entire stake in Gassled (6.4%) and the associated entities. The sale was effective at the end of 2011.

In the Netherlands, TOTAL has had natural gas exploration and production operations since 1964 and

currently owns twenty-four offshore production licenses, including twenty that it operates, and two offshore exploration licenses, E17c (16.92%) and K1c (30%). In 2011, the Group’s production was 38 kboe/d, compared to 42 kboe/d in 2010 and 45 kboe/d in 2009.

 

 

The K5CU development project (49%, operator) was launched in 2009 and production started up in early 2011. This development includes four wells supported by a platform that was installed in 2010 and connected to the K5A platform by a 15 km gas pipeline.

 

The K4Z development project (50%, operator) began in 2011. This development is comprised of two sub-sea wells connected to the existing production and transport facilities. Start-up of production is expected in early 2013.

In late 2010, TOTAL disposed of 18.19% of its equity stake in the NOGAT gas pipeline and decreased its stake to 5%.

In Poland, at the end of March 2011, TOTAL signed an agreement to acquire a 49% stake in the Chelm and Werbkowice exploration concessions in order to assess their shale gas potential. On the Chelm license, drilling has taken place, the well has been tested and the results from the well are being examined.

In the United Kingdom, where TOTAL has had operations since 1962, the Group’s production was 169 kboe/d in 2011, compared to 207 kboe/d in 2010 and 217 kboe/d in 2009. Around 90% of this production comes from operated fields located in two major zones: the Alwyn zone in the northern North Sea, and the Elgin/Franklin zone in the Central Graben.

 

 

On the Alwyn zone, start-up of satellite fields or new reservoir compartments allowed production to be maintained. The N52 well drilled on Alwyn (100%) in a new compartment of the Statfjord reservoir came onstream in February 2010 with initial production of 15 kboe/d (gas and condensates). The N53 well was also drilled on Alwyn on the same type of reservoir in 2011 and came onstream in September 2011 with initial production of 4 kboe/d (gas and condensates).

The development project for Islay (100%), a gas and condensates discovery made in 2008 located south of Alwyn, was approved in July 2010. Development is underway and production start-up is expected in the first half of 2012 with a production capacity of 15 kboe/d.

In 2010, TOTAL signed an agreement to divest its stake in the Otter field; its holding fell from 81% to 50% in 2011 and was completely disposed of in February 2012.

 

 

30


Table of Contents
 

In the Central Graben, the development of the Elgin (46.2%, operator) and Franklin (46.2%, operator) fields, in production since 2001, contributed substantially to the Group’s presence in the United Kingdom. At the end of 2011, TOTAL acquired the remaining 22.5% of Elgin Franklin Oil & Gas (EFOG), a company through which it holds a stake in the Elgin and Franklin fields. On the Elgin field, a first infill well came onstream in October 2009 with production of 18 kboe/d. A second infill well started up in May 2010 with production of 12 kboe/d.

Following a gas leak on the Elgin field on March 25, 2012, the production on the Elgin, Franklin and West Franklin fields was stopped and the personnel of the site were evacuated. Investigations are ongoing to determine the causes and the remediation of the gas leak. The Group is actively monitoring the situation (situation as of March 26, 2012).

Additional development of West Franklin through a second phase (drilling of three additional wells and installation of a new platform connected to Elgin) was approved in November 2010. Start-up of production is expected at year-end 2013. The decision was made in 2011 to install a new well platform on the Elgin field. This new platform will be installed in parallel with the West Franklin project and will enable the drilling of new wells on the Elgin field as of 2014.

 

 

In addition to Alwyn and the Central Graben, a third area, West of Shetland, is undergoing development. TOTAL increased its equity stake to 80% in the Laggan and Tormore fields in early 2010.

The decision to develop the Laggan/Tormore fields was made in March 2010 and production is scheduled to start in 2014 with an expected capacity of 90 kboe/d. The joint development scheme selected by TOTAL and its partner includes sub-sea production facilities and off-gas treatment (gas and condensates) at a plant located near the Sullom Voe terminal in the Shetland Islands. The gas would then be exported to the Saint-Fergus terminal via a new pipeline connected to the Frigg gas pipeline (FUKA).

In 2010, the Group’s stake in the P967 license (operator), which includes the Tobermory gas discovery, increased to 50% from 43.75%. This license is located north of Laggan/Tormore.

In early 2011, a gas and condensate discovery was made on the Edradour license (75%, operator), near Laggan and Tormore. The development of Edradour using the infrastructures in place is being examined.

TOTAL has stakes in ten assets operated by third parties, the most important in terms of reserves being the Bruce (43.25%) and Alba (12.65%) fields. The Group disposed of its stake in the Nelson field (11.5%) in 2010.

Middle East

In 2011, TOTAL’s production in the Middle East was 570 kboe/d, representing 24% of the Group’s overall production, compared to 527 kboe/d in 2010 and 438 kboe/d in 2009.

In the United Arab Emirates, where TOTAL has had operations since 1939, the Group’s production was 240 kboe/d in 2011, compared to 222 kboe/d in 2010 and 214 kboe/d in 2009. The increase in production in 2011 was mainly due to higher production by Abu Dhabi Company for Onshore Oil Operations (ADCO) and Abu Dhabi Marine (ADMA).

In Abu Dhabi, TOTAL holds a 75% stake in the Abu Al Bu Khoosh field (operator), a 9.5% stake in ADCO, which operates the five major onshore fields in Abu Dhabi, and a 13.3% stake in ADMA, which operates two offshore fields. TOTAL also has a 15% stake in Abu Dhabi Gas Industries (GASCO), which produces LPG and condensates from the associated gas produced by ADCO, and a 5% stake in Abu Dhabi Gas Liquefaction Company (ADGAS), which produces LNG, LPG and condensates.

In early 2009, TOTAL signed agreements for a 20-year extension of its stake in the GASCO joint venture starting on October 1, 2008.

In early 2011, TOTAL and IPIC, a government-owned entity in Abu Dhabi, signed a Memorandum of Understanding with a view to developing projects of common interest in the upstream oil and gas sectors.

The Group has a 24.5% stake in Dolphin Energy Ltd. alongside Mubadala, a company owned by the government of the Abu Dhabi Emirate, to market gas produced primarily in Qatar to the United Arab Emirates.

The Group also owns 33.33% of Ruwais Fertilizer Industries (FERTIL), which produces urea. FERTIL 2, a new project, was launched in 2009 to build a new granulated urea unit with a capacity of 3,500 t/d (1.2 Mt/y). This project is expected to allow FERTIL to more than double production so as to reach nearly 2 Mt/y in January 2013.

In Iraq, TOTAL bid in 2009 and 2010 on the three calls for tenders launched by the Iraqi Ministry of Oil. The PetroChina-led consortium that includes TOTAL (18.75%) was awarded the development and production contract for the Halfaya field during the second call for tenders held in December 2009. This field is located in the

 

 

31


Table of Contents

province of Missan, north of Basra. The agreement became effective in March 2010 and the preliminary development plan was approved by the Iraqi authorities in September 2010. Development operations started with the shooting of the 3D seismic survey, drilling and the construction of surface facilities. A production level of 70 kb/d of oil is expected to be reached in 2012.

In Iran, the Group’s production under buy back agreements was zero in 2011, having been 2 kb/d in 2010 and 8 kb/d in 2009. For additional information on TOTAL’s operations in Iran, see “— Other Matters — Business Activities in Cuba, Iran, Sudan and Syria”.

In Oman, the Group’s production was 36 kboe/d in 2011, stable compared to 2010 and 2009. TOTAL produces oil mainly on Block 6 as well as on Block 53 and liquefied natural gas through its stakes in the Oman LNG (5.54%)/Qalhat LNG (2.04%(1)) liquefaction plant, which has a capacity of 10.5 Mt/y.

In Qatar, where TOTAL has had operations since 1936, the Group has equity stakes in the Al Khalij field (100%), the NFB Block (20%) in the North field, the Qatargas 1 liquefaction plant (10%), Dolphin (24.5%) and train 5 of Qatargas 2 (16.7%). The Group’s production was 155 kboe/d in 2011, compared to 164 kboe/d in 2010 and 141 kboe/d in 2009.

 

 

The production contract for Dolphin, signed in 2001 with state-owned Qatar Petroleum, provides for the sale of 2 Bcf/d of gas from the North Field for a 25-year period. The gas is processed in the Dolphin plant in Ras Laffan and exported to the United Arab Emirates through a 360 km gas pipeline.

 

Production from train 5 of Qatargas 2, which started in September 2009, reached its full capacity (7.8 Mt/y) at year-end 2009. TOTAL has owned an equity stake in this train since 2006. In addition, TOTAL takes part of the LNG produced in compliance with the contracts signed in 2006, which provide for the purchase of 5.2 Mt/y of LNG from Qatargas 2 by the Group.

The Group also has a 10% stake in Laffan Refinery, a condensate splitter with a capacity of 146 kb/d that started up in September 2009. Finally, since May 2011 the Group has been a partner (25%) in the offshore BC exploration license.

In Syria, TOTAL is present on the Deir Ez Zor license (100%, operated by DEZPC, 50% of which is owned by TOTAL) and through the Tabiyeh contract that became effective in October 2009. The Group’s production from these two assets was 53 kboe/d in 2011, compared to 39 kboe/d in 2010 and 20 kboe/d in 2009. In early December 2011, TOTAL ceased its activities that contribute to oil and gas production in Syria.

For additional information on TOTAL’s operations in Syria, see “— Other Matters — Business Activities in Cuba, Iran, Sudan and Syria”.

In Yemen, where TOTAL has had operations since 1987, the Group’s production was 86 kboe/d in 2011, compared to 66 kboe/d in 2010 and 21 kboe/d in 2009.

TOTAL has an equity stake in the Yemen LNG project (39.62%). As part of this project, the Balhaf liquefaction plant on the southern coast of Yemen is supplied with the gas produced on Block 18, located near Marib in the center of the country, through a 320 km gas pipeline. The two liquefaction trains were commissioned in October 2009 and April 2010, respectively. The plant has a nominal capacity of 6.7 Mt/y of LNG.

TOTAL also has stakes in the country’s two oil basins, as the operator of Block 10 (Masila Basin, East Shabwa license, 28.57%) and as a partner on Block 5 (Marib Basin, Jannah license, 15%).

TOTAL owns stakes in four onshore exploration licenses: 40% in Blocks 69 and 71, 50.1% in Block 70 (operated by TOTAL since July 2010), and 36% in Block 72 (operated by TOTAL since October 2011).

In March 2012, TOTAL acquired a 40% interest in the Block 3 exploration license, which it will operate. The acquisition is subject to the approval of Yemen’s Ministry of Oil and Mineral Resources.

 

 

 

(1) TOTAL’s indirect stake in Qalhat LNG through its stake in Oman LNG.

 

32


Table of Contents

OIL AND GAS ACREAGE

 

As of December 31,

(in thousand of acres)

  2011      2010      2009  
           Undeveloped
acreage
(a)
     Developed
acreage
     Undeveloped
acreage
(a)
     Developed
acreage
     Undeveloped
acreage
(a)
     Developed
acreage
 

Europe

   Gross     6,478         781         6,802         776         5,964         667   
     Net     3,497         185         3,934         184         2,203         182   

Africa

   Gross     110,346         1,229         72,639         1,229         85,317         1,137   
     Net     65,391         333         33,434         349         45,819         308   

Americas

   Gross     15,454         1,028         16,816         1,022         9,834         776   
     Net     5,349         329         5,755         319         4,149         259   

Middle East

   Gross     31,671         1,461         29,911         1,396         33,223         204   
     Net     2,707         217         2,324         209         2,415         97   

Asia

   Gross     40,552         930         36,519         539         29,609         397   
     Net     19,591         255         17,743         184         16,846         169   

Total

   Gross     204,501         5,429         162,687         4,962         163,947         3,181   
     Net(b)     96,535         1,319         63,190         1,245         71,432         1,015   

 

(a) Undeveloped acreage includes leases and concessions.
(b) Net acreage equals the sum of the Group’s equity stakes in gross acreage.

NUMBER OF PRODUCTIVE WELLS

 

As of December 31,

(number of wells)

         2011      2010      2009  
            Gross
productive
wells
     Net
productive
wells
(a)
     Gross
productive
wells
     Net
productive
wells
(a)
     Gross
productive
wells
     Net
productive
wells
(a)
 

Europe

   Liquids      576         151         569         151         705         166   
     Gas      358         125         368         132         328         125   

Africa

   Liquids      2,275         576         2,250         628         2,371         669   
     Gas      157         44         182         50         190         50   

Americas

   Liquids      877         247         884         261         821         241   
     Gas      2,707         526         2,532         515         1,905         424   

Middle East

   Liquids      7,829         721         7,519         701         3,766         307   
     Gas      372         49         360         49         136         32   

Asia

   Liquids      209         75         196         75         157         75   
     Gas      1,589         498         1,258         411         1,156         379   

Total

   Liquids      11,766         1,770         11,418         1,816         7,820         1,458   
     Gas      5,183         1,242         4,700         1,157         3,715         1,010   

 

(a) Net wells equal the sum of the Group’s equity stakes in gross wells.

 

33


Table of Contents

NUMBER OF NET OIL AND GAS WELLS DRILLED ANNUALLY

 

As of December 31,        2011     2010     2009  
          Net
productive
wells
drilled
(a)
    Net
dry  wells
drilled
(a)
    Total net
wells
drilled
(a)
    Net
productive
wells
drilled
(a)
    Net
dry  wells
drilled
(a)
    Total net
productive
wells
drilled
(a)
    Net
wells
drilled
(a)
    Net
dry  wells
drilled
(a)
    Total
net  wells
drilled
(a)
 

Exploratory

 

Europe

    1.5        1.7        3.2        1.7        0.2        1.9        0.4        3.7        4.1   
 

Africa

    2.9        1.5        4.4        1.6        4.3        5.9        5.9        3.2        9.1   
 

Americas

    1.2        1.3        2.5        1.0        1.6        2.6        0.8        1.6        2.4   
 

Middle East

    1.2        0.8        2.0        0.9        0.3        1.2        0.3               0.3   
 

Asia

    2.1        3.7        5.8        3.2        1.2        4.4        1.7        1.2        2.9   
   

Subtotal

    8.9        9.0        17.9        8.4        7.6        16.0        9.1        9.7        18.8   

Development

 

Europe

    7.5               7.5        5.0               5.0        5.0               5.0   
 

Africa

    24.7               24.7        18.1               18.1        27.5        0.2        27.7   
 

Americas

    113.1        82.2        195.3        135.3        112.5        247.8        31.2        104.3        135.5   
 

Middle East

    32.6        2.6        35.2        29.6        1.4        31.0        42.6        3.4        49.0   
 

Asia

    118.4               118.4        59.3               59.3        63.5        0.3        63.8   
   

Subtotal

    296.3        84.8        381.1        247.3        113.9        361.2        172.8        108.2        281.0   

Total

        305.2        93.8        399.0        255.7        121.5        377.2        181.9        117.9        299.8   

 

(a) Net wells equal the sum of the Group’s equity stakes in gross wells.

DRILLING AND PRODUCTION ACTIVITIES IN PROGRESS

 

As of December 31,         2011      2010      2009  
(number  of wells)         Gross      Net (a)      Gross      Net (a)      Gross      Net (a)  

Exploratory

 

Europe

     2         2.0         3         2.1         1         0.5   
 

Africa

     2         0.8         4         1.4         4         1.3   
 

Americas

     3         1.0         2         0.9         2         0.6   
 

Middle East

                     2         1.2         1         0.4   
 

Asia

     1         0.6         2         1.1                   
   

Subtotal

     8         4.4         13         6.7         8         2.8   

Development

 

Europe

     21         4.5         21         3.8         5         2.2   
 

Africa

     31         11.3         29         6.4         31         8.5   
 

Americas

     22         5.7         99         29.2         60         17.8   
 

Middle East

     26         3.5         20         5.1         40         4.8   
 

Asia

     11         5.1         23         9.8         12         5.5   
   

Subtotal

     111         30.1         192         54.3         148         38.8   

Total

         119         34.5         205         61.0         156         41.6   

 

(a) Net wells equal the sum of the Group’s equity stakes in gross wells.

 

34


Table of Contents

INTERESTS IN PIPELINES

The table below sets forth TOTAL’s interests in oil and gas pipelines as of December 31, 2011.

 

Pipeline(s)   Origin   Destination  

%

interest

    Operator     Liquids     Gas  

EUROPE

                                       

France

                                       

TIGF

  South West Network         100.00        x                x   

Norway

                                       
Frostpipe (inhibited)   Lille-Frigg, Froy   Oseberg     36.25                x           
Heimdal to Brae Condensate Line   Heimdal   Brae     16.76                x           
Kvitebjorn pipeline   Kvitebjorn   Mongstad     5.00                x           
Norpipe Oil   Ekofisk Treatment center   Teeside (UK)     34.93                x           
Oseberg Transport System   Oseberg, Brage and Veslefrikk   Sture     8.65                x           
Sleipner East Condensate Pipe   Sleipner East   Karsto     10.00                x           
Troll Oil Pipeline I and II   Troll B and C   Vestprosess (Mongstad refinery)     3.71                x           

The Netherlands

                                       

Nogat pipeline

  F3-FB   Den Helder     5.00                        x   

WGT K13-Den Helder

  K13A   Den Helder     4.66                        x   

WGT K13-Extension

  Markham   K13 (via K4/K5)     23.00                        x   

United Kingdom

                                       

Alwyn Liquid Export Line

  Alwyn North   Cormorant     100.00        x        x           

Bruce Liquid Export Line

  Bruce   Forties (Unity)     43.25                x           

Central Area Transmission System (CATS)

  Cats Riser Platform   Teeside     0.57                        x   

Central Graben Liquid Export Line (LEP)

  Elgin-Franklin   ETAP     15.89                x           

Frigg System : UK line

  Alwyn North, Bruce and others   St.Fergus (Scotland)     100.00        x                x   

Ninian Pipeline System

  Ninian   Sullom Voe     16.00                x           

Shearwater Elgin Area Line (SEAL)

  Elgin-Franklin, Shearwater   Bacton     25.73                        x   

SEAL to Interconnector Link (SILK)

  Bacton   Interconnector     54.66        x                x   

AFRICA

                                       

Gabon

                                       

Mandji Pipes

  Mandji fields   Cap Lopez Terminal     100.00 (a)      x        x           

Rabi Pipes

  Rabi fields   Cap Lopez Terminal     100.00 (a)      x        x           

AMERICAS

                                       

Argentina

                                       

Gas Andes

  Neuquen Basin (Argentina)   Santiago (Chile)     56.50        x                x   

TGN

  Network (Northern Argentina)         15.40                        x   

TGM

  TGN   Uruguyana (Brazil)     32.68                        x   

Bolivia

                                       

Transierra

  Yacuiba (Bolivia)   Rio Grande (Bolivia)     11.00                        x   

Brazil

                                       

TBG

  Bolivia-Brazil border   Porto Alegre via São Paulo     9.67                        x   

Colombia

                                       

Ocensa

  Cusiana   Covenas Terminal     5.20                x           

Oleoducto de Alta Magdalena

  Tenay   Vasconia     0.93                x           

Oleoducto de Colombia

  Vasconia   Covenas     9.55                x           

ASIA

                                       

Yadana

  Yadana (Myanmar)   Ban-I Tong (Thai border)     31.24        x                x   

REST OF WORLD

                                       

BTC

  Baku (Azerbaijan)   Ceyhan (Turkey, Mediterranean)     5.00                x           

SCP

  Baku (Azerbaijan)   Georgia/Turkey Border     10.00                        x   

Dolphin (International transport and network)

  Ras Laffan (Qatar)   U.A.E.     24.50                        x   

 

(a) Interest of Total Gabon. The Group has a financial interest of 58.28% in Total Gabon.

 

35


Table of Contents

Gas & Power

 

 

The Gas & Power division is primarily focused on the optimization of the Group’s gas resources. The division is active in the transport, trading and marketing of natural gas, liquefied natural gas (LNG) and electricity, LNG re-gasification and natural gas storage. It is also engaged in shipping and trading of liquefied petroleum gas (LPG), power generation from gas-fired power plants or renewable energies, and coal production, trading and marketing.

The Gas & Power division is also developing new energies that emit fewer greenhouse gases to complement hydrocarbons so as to meet the increasing global demand for energy. For this purpose, the Group has two main focuses:

 

 

the upstream/downstream integration of the solar photovoltaic channel (achieved through the acquisition of a 60% stake in SunPower in 2011);

 

the thermochemical and biochemical conversion of feedstock into fuels or chemicals.

In these fields, TOTAL pursues and strengthens R&D in solar energy, conversion processing of biomass, gas and coal, energy storage, carbon capture and storage and gas technologies.

In parallel, the Group is closely monitoring nuclear power generation and its outlook.

Liquefied natural gas

A pioneer in the LNG industry, TOTAL today ranks second worldwide among international oil companies(1) and has sound and diversified positions both in the upstream and downstream portions of the LNG chain. LNG development is key to the Group’s strategy, with TOTAL strengthening positions in most major production zones and markets.

Through its stakes in liquefaction plants located in Indonesia, Qatar, the United Arab Emirates, Oman, Nigeria, Norway and, since 2009, Yemen, TOTAL markets LNG in all worldwide markets. In 2011, TOTAL sold 13.2 Mt of LNG, an increase of 7.3% compared to 2010 LNG sales (12.3 Mt) and of 48.3% compared to 2009 sales (8.9 Mt). The start-up of the Angola LNG plant in 2012, together with the Group’s liquefaction projects in Australia, Nigeria and Russia, are expected to allow for growth to continue in the coming years.

The Gas & Power division is responsible for LNG operations downstream from liquefaction plants.(2) It is in

charge of LNG marketing to third parties on behalf of the Exploration & Production division, building up the Group’s LNG portfolio for its trading, marketing and transport operations as well as re-gasification terminals.

In Nigeria, TOTAL holds a 15% interest in the Nigeria LNG plant (NLNG). The Group signed an LNG purchase agreement, initially intended for deliveries to the United States and Europe, for an initial 0.23 Mt/y over a 23-year period starting in 2006, to which an additional 0.94 Mt/y was added when the sixth train came on stream in December 2007.

TOTAL also holds a 17% stake in the Brass LNG project, which calls for the construction of two liquefaction trains, each with a capacity of 5 Mt/y. In conjunction with this acquisition, TOTAL signed a preliminary agreement with Brass LNG Ltd setting forth the principal terms of an LNG purchase agreement for approximately one-sixth of the plant’s capacity over a 20-year period. This contract is subject to the final investment decision for the project by Brass LNG.

In Norway, as part of the Snøvhit project, in which the Group holds an 18.4% stake, TOTAL signed in 2004 a purchase agreement for 0.78 Mt/y of LNG over a 15-year period primarily intended for North America and Europe. Deliveries started in 2007.

In Qatar, TOTAL signed purchase agreements in 2006 for 5.2 Mt/y of LNG from train 5 (TOTAL, 16.7%) of Qatargas 2 over a 25-year period. This LNG is expected to be marketed mainly in France, the United Kingdom and North America. LNG production from this train started in September 2009.

In Yemen, TOTAL signed an agreement with Yemen LNG Ltd (TOTAL, 39.62%) in 2005 to purchase 2 Mt/y of LNG over a 20-year period, starting in 2009, which is initially intended for delivery in the United States and Europe. LNG production from Yemen LNG’s first and second trains started in October 2009 and April 2010, respectively.

Since 2009, part of the volume purchased by the Group pursuant to its long-term contracts related to the LNG projects mentioned above has been diverted to higher-value markets in Asia.

In Angola, TOTAL is involved in the construction of the Angola LNG liquefaction plant (TOTAL, 13.6%), which includes a 5.2 Mt/y train expected to start up in 2012. As

 

 

 

(1) Based on publicly available information; upstream and downstream LNG portfolios.
(2) The Exploration & Production division is in charge of the Group's natural gas liquefaction and production operations.

 

36


Table of Contents

part of this project, TOTAL signed in 2007 a re-gasified gas purchase agreement for 13.6% of the quantities produced over a 20-year period.

In Australia, TOTAL holds a 24% stake in the Ichthys LNG project, which calls for the construction of two LNG trains, each with a capacity of 4.2 Mt/y. In conjunction with this acquisition, TOTAL signed an LNG purchase agreement for 0.9 Mt/y over a 15-year period. The final investment decision of the partners of the Ichthys LNG project was made in January 2012.

In China, TOTAL signed in 2008 an LNG sale agreement with China National Offshore Oil Company (CNOOC). This agreement, starting in 2010 for a 15-year period, provides for the supply by TOTAL of up to 1 Mt/y of LNG to CNOOC. The gas supplied comes from the Group’s global LNG portfolio.

In South Korea, TOTAL signed an LNG sale agreement in 2011 with Kogas. Under this agreement, TOTAL will deliver up to 2 Mt/y of LNG to Kogas between 2014 and 2031. This gas will come from the Group’s global LNG portfolio.

With regard to LNG transport operations, since 2004 TOTAL has been the direct long-term charterer of the Arctic Lady, a 145,000 m3 LNG tanker that ships TOTAL’s share of production from the Snøvhit liquefaction plant in Norway. In November 2011, TOTAL signed a second long-term contract for the chartering of a 165,000 m3 LNG tanker, the Maersk Meridian, in order to strengthen its transport capacities with regards again to its lifting commitments in Norway.

The Group also holds a 30% stake in Gaztransport & Technigaz (GTT), which focuses mainly on the design and engineering of membrane cryogenic tanks for LNG tankers. At year-end 2011, out of a worldwide tonnage estimated at 386 LNG tankers(1), 258 active LNG tankers were equipped with membrane tanks built under GTT licenses.

Trading

In 2011, TOTAL continued to pursue its strategy of developing its operations downstream from natural gas and LNG production. The aim of this strategy is to optimize access for the Group’s current and future production to traditional markets (with long-term contracts) and to markets open to international competition (with short-term contracts and spot sales). In the context of deregulated markets, which allow customers to more freely access suppliers, in turn leading to new marketing arrangements

that are more flexible than traditional long-term contracts, TOTAL is developing trading, marketing and logistics businesses to offer its natural gas and LNG production directly to customers.

In parallel, the Group has operations in electricity trading and LPG as well as coal marketing.

Furthermore, in 2011 TOTAL began to market the petcoke production of the Port Arthur refinery (United States) on the international market.

The Gas & Power division’s trading teams are located in London, Houston, Geneva and Singapore and conduct most of their business through the Group’s wholly-owned subsidiaries Total Gas & Power and Total Gas & Power North America.

Gas and electricity

TOTAL has gas and electricity trading operations in Europe and North America with a view to selling the Group’s production and supplying its marketing subsidiaries.

In Europe, TOTAL marketed 1,500 Bcf (42.5 Bm3) of natural gas in 2011, compared to 1,278 Bcf (36.2 Bm3) in 2010 and 1,286 Bcf (36.5 Bm3) in 2009, including approximately 12% coming from the Group’s production. In addition, TOTAL marketed 24.2 TWh of electricity in 2011, compared to 27.1 TWh in 2010 and 35 TWh in 2009, which came mainly from external resources.

In North America, TOTAL marketed 1,694 Bcf (48 Bm3) of natural gas in 2011, compared to 1,798 Bcf (51 Bm3) in 2010 and 1,586 Bcf (45 Bm3) in 2009, supplied by its own production or external resources.

LNG

TOTAL has LNG trading operations through spot sales and fixed-term contracts as described in “— Liquefied natural gas” above. Since 2009, new purchase agreements (Qatargas 2, Yemen LNG) and new sale agreements (China, India, Thailand, South Korea and Japan) have substantially developed the Group’s LNG marketing operations, particularly in Asia’s most buoyant markets. This spot and fixed-term LNG portfolio allows TOTAL to supply gas to its main customers worldwide, while retaining a sufficient degree of flexibility to react to market opportunities.

In 2011, TOTAL purchased 99 contractual cargos and 10 spot cargos from Qatar, Yemen, Nigeria, Norway, Russia and Egypt, compared to 94 and 12, respectively, in 2010 and 23 and 12, respectively, in 2009.

 

 

 

(1) Gaztransport & Technigaz data.

 

37


Table of Contents

LPG

In 2011, TOTAL traded and sold approximately 5.7 Mt of LPG (butane and propane) worldwide, compared to 4.5 Mt in 2010 and 4.4 Mt in 2009. Approximately 28% of these quantities came from fields or refineries operated by the Group. LPG trading involved the use of 7 time-charters, representing 188 voyages in 2011, and approximately 142 spot charters.

Coal

In 2011, TOTAL marketed 7.5 Mt of coal in the international market, compared to 7.3 Mt in 2010 and 2009. Approximately 70% of this coal comes from South Africa. More than three-quarters of the volume was sold in Asia, where coal is used primarily to generate electricity, with the remaining volume marketed in Europe.

Petcoke

In 2011, TOTAL began to market the petcoke produced by the coker at the Port Arthur refinery. Approximately 0.6 Mt of petcoke was sold on the international market in 2011 to cement plants and electricity producers, mainly in Mexico, Brazil, Turkey and China.

Marketing

To unlock value from the Group’s production, TOTAL has gradually developed gas, electricity and coal marketing operations with end users in the United Kingdom, France, Spain and Germany.

In the United Kingdom, TOTAL sells gas and power to the industrial and commercial segments through its subsidiary Total Gas & Power Ltd. In 2011, volumes of gas sold amounted to 162 Bcf (4.6 Bm3), compared to 173 Bcf (4.9 Bm3) in 2010 and 130 Bcf (3.7 Bm3) in 2009. Sales of electricity totaled approximately 4.1 TWh in 2011, stable compared to 2010 and 2009.

In France, TOTAL markets natural gas through its subsidiary Total Energie Gaz (TEGAZ), the overall sales of which were 208 Bcf (5.9 Bm3) in 2011, compared to 226 Bcf (6.4 Bm3) in 2010 and 208 Bcf (5.9 Bm3) in 2009. The Group also markets coal to its French customers through its subsidiary CDF Energie, with sales of approximately 1.2 Mt in 2011, compared to 1.3 Mt in 2010 and 1 Mt in 2009.

In Spain, TOTAL markets natural gas to the industrial and commercial segments through Cepsa Gas Comercializadora, in which it holds a 35% stake. In 2011, volumes of gas sold amounted to 85 Bcf (2.4 Bm3), like in 2010 and compared to 70 Bcf (2 Bm3) in 2009.

In Germany, Total Energie created a marketing subsidiary in 2010, Total Energy Gas GmbH, which began

commercial operations in 2011, making its first sales to industrial customers and service companies.

The Group also holds stakes in the marketing companies that are associated with the Altamira and Hazira LNG re-gasification terminals located in Mexico and India, respectively.

Gas facilities

TOTAL develops and operates its natural gas transport networks, gas storage facilities (both liquid and gaseous) and LNG re-gasification terminals downstream from its natural gas and LNG production.

Transport of natural gas

In France, the Group’s transport operations located in the southwest of the country are grouped under Total Infrastructures Gaz France (TIGF), a wholly-owned subsidiary of the Group. This subsidiary operates a regulated transport network of 5,000 km of gas pipelines. As part of the development of Franco-Spanish interconnections, TOTAL decided in 2011 to complete the Euskadour (France-Spain link) project with commissioning scheduled in 2015. This decision followed the decisions made in 2010 to invest in the Artère du Béarn and Girland gas pipeline projects (reinforcement of Artère de Guyenne), with commissioning scheduled in 2013.

Another highlight of 2011 was the implementation by TIGF of the Third Energy Package adopted by the European Union in July 2009, which entails splitting network operations from production and supply operations.

In South America, TOTAL owns interests in several natural gas transport companies in Argentina, Chile and Brazil. These assets represent a total integrated network of approximately 9,500 km of pipelines serving the Argentinean, Chilean and Brazilian markets from gas-producing basins in Bolivia and Argentina, where the Group has natural gas reserves. These natural gas transport companies are challenged by a difficult operational and financial environment in Argentina stemming from the absence of an increase in transport tariffs and the restrictions imposed on gas exports. The Group successfully negotiated in 2011 financial arrangements with some of its customers, which resulted in a significant improvement in earnings for GasAndes, a company in which TOTAL holds a 56.5% stake.

Storage of natural gas and LPG

In France, the Group’s storage operations located in the southwest are grouped under TIGF. This subsidiary operates two storage units under a negotiated legal regime with a usable capacity of 92 Bcf (2.6 Bm3).

 

 

38


Table of Contents

Through its 35.5% stake in Géométhane, TOTAL owns natural gas storage in a salt cavern in Manosque with a capacity of 10.5 Bcf (0.3 Bm3). A proposed 7 Bcf (0.2 Bm3) increase in storage capacity was approved in February 2011, with commissioning scheduled in 2017-2018.

In India, TOTAL holds a 50% stake in South Asian LPG Limited (SALPG), a company that operates an underground import and storage LPG terminal located on the east coast of the country. This cavern, the first of its kind in India, has a storage capacity of 60 kt. In 2011, inbound vessels transported 850 kt of LPG, compared to 779 kt in 2010 and 606 kt in 2009.

LNG re-gasification

TOTAL has entered into agreements to obtain long-term access to LNG re-gasification capacity on the three continents that are the largest consumers of natural gas: North America (the United States and Mexico), Europe (France and the United Kingdom), and Asia (India). This diversified presence allows the Group to access new liquefaction projects by becoming a long-term buyer of a portion of the LNG produced at these plants, thereby strengthening its LNG supply portfolio.

In France, TOTAL holds a 27.6% stake in Société du Terminal Méthanier de Fos Cavaou (STMFC) and has, through its affiliate Total Gas & Power, a re-gasification capacity of 2.25 Bm3/y. The terminal received 59 vessels in 2011.

In 2011, TOTAL acquired a 9.99% stake in Dunkerque LNG (EDF 65%, operator) in order to develop a methane terminal project with a capacity of 13 Bm3/y. Trade agreements have also been signed which allow TOTAL to reserve up to 2 Bm3/y of re-gasification capacity over a 20-year period. Commissioning of the terminal is scheduled for the end of 2015.

In the United Kingdom, through its equity interest in the Qatargas 2 project, TOTAL holds an 8.35% stake in the South Hook LNG re-gasification terminal and an equivalent right of use to the terminal. Phase 2 of the terminal was commissioned in April 2010, which increased the terminal’s total capacity to 742 Bcf/y (21 Bm3/y). The terminal operates at nearly 80% of its capacity and in 2011 re-gasified nearly 100 cargoes from Qatar.

In Croatia, TOTAL is involved in the study of an LNG re-gasification terminal on Krk Island, on the northern Adriatic coast.

In Mexico, TOTAL sold in 2011 its entire stake in the Altamira re-gasification terminal. However, TOTAL retained

its 25% reservation of the terminal’s capacity, i.e., 59 Bcf/y (1.7 Bm3/y) through its 25% stake in Gas del Litoral.

In the United States, TOTAL has reserved a re-gasification capacity of approximately 353 Bcf/y (10 Bm3/y) at the Sabine Pass terminal (Louisiana) for a 20-year period ending in 2029.

In India, TOTAL holds a 26% stake in the Hazira terminal, which has a natural gas re-gasification capacity of 177 Bcf/y (5 Bm3/y). The terminal, located on the west coast of India in the Gujarat state, is a merchant terminal with operations that cover both LNG re-gasification and gas marketing. After a year of sluggish activity in 2010, the terminal’s full capacities are under contract for 2011 and 2012. The Indian market’s strong growth prospects have led to a decision to increase the terminal’s capacity to 230 Bcf/y (6.5 Bm3/y) starting in 2013.

Electricity generation

In a context of increasing global demand for electricity, TOTAL has developed expertise in the power generation sector, especially through cogeneration and combined cycle power plant projects.

The Group is also involved in power generation projects from renewable sources and is closely monitoring nuclear power generation and its outlook.

Electricity from conventional energy sources

In Abu Dhabi, the Taweelah A1 plant combines electricity generation and water desalination. It is owned by Gulf Total Tractebel Power Cy, in which TOTAL holds a 20% stake. The Taweelah A1 power plant, in operation since 2003, currently has net power generation capacity of 1,600 MW and water desalination capacity of 385,000 m3 per day. The plant’s production is sold to Abu Dhabi Water and Electricity Company (ADWEC) as part of a long-term agreement.

In Nigeria, TOTAL and its partner, the state-owned Nigerian National Petroleum Corporation (NNPC), own interests in two gas-fired power plant projects that are part of the government’s objectives to develop power generation and increase the share of natural gas production for domestic use:

 

 

The Afam VI project, part of the Shell Petroleum Development Company (SPDC) joint venture in which TOTAL holds a 10% stake, concerns the development of a 630 MW combined-cycle power plant. Commercial operations started in December 2010.

 

 

The development of a new 417 MW combined-cycle power plant near the city of Obite (Niger Delta) in

 

 

39


Table of Contents
   

connection with the OML 58 gas project, part of the joint venture between NNPC and TOTAL (40%, operator). A final investment decision is expected in the first half of 2012 and commissioning is scheduled in the first half of 2014 in open-cycle and in early 2015 in closed-cycle. The power plant will be connected to the existing power grid through a new 108 km high-voltage transmission line.

In Thailand, TOTAL owns 28% of Eastern Power and Electric Company Ltd, which operates the combined-cycle gas power plant in Bang Bo, with a capacity of 350 MW, in operation since 2003. The plant’s production is sold to the Electricity Generating Authority of Thailand under a long-term agreement.

Electricity from nuclear energy sources

In France, TOTAL partners with EDF and other players through its 8.33% interest in the second French EPR project in Penly, in the northwest of the country, for which studies are underway.

The Group is closely monitoring nuclear power generation and its outlook.

Electricity from renewable energy sources

In concentrated solar power, TOTAL, in partnership with Spanish company Abengoa Solar, won the call for tenders for the construction and 20-year operation of a 109 MW concentrated solar power plant in Abu Dhabi. The Shams project (TOTAL, 20%) is being carried out in partnership with Masdar through the Abu Dhabi Future Energy Company, which holds a 60% stake in the project. Construction work started in July 2010 and start-up is expected during the second semester of 2012. The plant’s production will be sold to ADWEC.

In wind power, TOTAL owns a 12 MW wind farm in Mardyck (near Dunkirk, France), which was commissioned in 2003.

With respect to marine energy, TOTAL holds a 26.6% share in Scotrenewables Marine Power, located in the Orkney Islands in Scotland. Tests are being conducted on a 250 kW prototype.

Solar energy

TOTAL is developing upstream operations through industrial production and downstream marketing activities in the photovoltaic sector based on crystalline silicon technology. The Group is also pursuing R&D in this field through several partnerships, as well as in the fields of thin films, transverse systems research and solar energy storage.

In 2011, TOTAL took a major step toward implementing its solar photovoltaic strategy, where the Group has been active since 1983, by acquiring a majority stake in the U.S. company SunPower.

Solar photovoltaic

SunPower

In June 2011, following a friendly takeover bid, TOTAL acquired 60% of SunPower, a U.S. company based in San Jose, California and listed on NASDAQ (NASDAQ: SPWR). TOTAL now appoints the majority of the members of SunPower’s board of directors. SunPower is an integrated player that designs, manufactures and supplies the highest-efficiency solar panels in the market. It is active throughout the solar chain, from cell production to the design and construction of turnkey large power plants.

Upstream, SunPower manufactures all of its cells in Asia (Philippines, Malaysia). In 2011, SunPower operated twelve cell manufacturing lines at its cell manufacturing plant in Melaka, Malaysia (SunPower, 50%), which has a capacity of 600 MWp/y. SunPower’s overall cell production capacity at the beginning of 2012 was 1,300 MWp/y.

Downstream, SunPower is present in most major geographic markets (United States, Europe, Australia and Asia), with operations ranging from residential roof tiles to large solar power plants.

A specific R&D agreement between TOTAL and SunPower has also been signed.

As of January 2012, TOTAL owns 66% of SunPower following the Tenesol transaction described below.

Tenesol

Tenesol is a French company that designs, manufactures, markets, installs and operates solar photovoltaic systems. In October 2011, TOTAL became the sole shareholder of Tenesol after having finalized the acquisition of its EDF partner’s shares (excluding overseas activities). Tenesol owns solar panel manufacturing plants (South Africa, France), which have a total capacity of nearly 200 MWp/y.

TOTAL and SunPower reached an agreement whereby, in 2012, Tenesol’s operations, along with the solar panel plant in Moselle, northeastern France (see “— Other assets” below), became part of SunPower.

Photovoltech

TOTAL holds a 50% interest in Photovoltech, a Belgian company specialized in manufacturing multicrystalline photovoltaic cells. In 2011, Photovoltech finalized the ramp-up of its third production line, raising the total production capacity of its plant in Tienen, Belgium to 155 MWp/y.

 

 

40


Table of Contents

Other assets

In 2011, TOTAL began the construction of a solar panel production and assembly plant in the northeastern region of Moselle in France, which is expected to begin operations in 2012 with an overall capacity of 44 MWp/y.

In addition, Tenesol’s overseas activities remain 50-50 subsidiaries of TOTAL and EDF through a new company named Sunzil.

Finally, the Group is continuing its projects to display solar application solutions as part of decentralized rural electrification projects in a number of countries, including in South Africa via Kwazulu Energy Services Company (KES) in which TOTAL holds a 35% stake. New projects are being studied in Africa and Asia.

Solar photovoltaic market context in 2011

In 2011, the photovoltaic sector was forced to cope with a difficult environment marked by excess cell production capacity and modification or cancellation of subsidy programs. This transition period is expected to result in a consolidation of the sector followed by the emergence of a competitive industry. As a clean energy, solar power has a large potential and should eventually become an indispensible part of the energy mix.

New solar technologies

TOTAL has committed to developing innovative technologies to improve its portfolio of solar projects. The Group has major R&D programs through partnerships with major laboratories and international research institutes in France and abroad.

In the upstream solar chain, TOTAL holds a 30% stake in AE Polysilicon Corporation (AEP), a U.S. company based near Philadelphia, Pennsylvania. AEP has developed a new continuous process to produce solar-grade granular polysilicon.

With respect to the production of crystalline silicon cells and panels, the Group is continuing its partnership with the Interuniversity MicroElectronics Center (IMEC) near the University of Leuven, Belgium, in an effort to increase the efficiency of solar cells.

Regarding thin-film technologies and silicon-based nano-materials, in 2009 the Group partnered with the Laboratoire de Physique des Interfaces et des Couches Minces de l’Ecole Polytechnique (LPICM) and the French National Center for Scientific Research (CNRS) to set up a joint research team in the Saclay area in France. TOTAL also entered into a research partnership with Toulouse-based Laboratoire d’analyse et d’architecture des

systèmes (LAAS) to develop associated electrical systems. The aim of these partnerships is to improve the efficiency of the photovoltaic chain in order to substantially lower costs in this sector.

In organic solar technologies, the Group acquired approximately 25% of the U.S. start-up Konarka in 2008. Since 2009, Konarka Technologies Inc has carried out research projects in cooperation with TOTAL to develop solar film on a large scale.

Regarding solar energy storage, TOTAL entered in 2009 into a research agreement with the Massachusetts Institute of Technology (MIT) in the United States to develop a new stationary battery technology.

Biotechnologies — conversion of biomass

TOTAL is exploring a number of avenues for developing biomass depending on the resource used, the nature of the target markets (e.g., fuels, lubricants, petrochemicals, specialty chemicals) and the conversion processes.

The Group has chosen to target the two primary conversion processes: biological and thermochemical.

In June 2010, TOTAL entered into a strategic partnership with Amyris Inc., a U.S. start-up specializing in biotechnologies. The Group acquired a stake in Amyris’ share capital (21.28% as of February 24, 2012) and signed a collaboration framework agreement that includes research, development, production and marketing partnerships with the creation of an R&D team. Two programs have been approved in 2011 to develop a biojet fuel as well as a biodiesel. At the end of 2011, partners agreed to create a joint-venture to produce and commercialize advanced molecules intended for the fuels, lubricants and special fluids markets.

Amyris owns a cutting-edge industrial synthetic biological platform designed to create and optimize micro-organisms (yeasts, algae, bacteria) that can convert sugars into fuels and chemicals. Amyris owns research laboratories and a pilot unit in California as well as a pilot plant and a demonstration facility in Brazil. Industrial production of farnesene began in 2011 at three partner sites (in Brazil, the United States and Spain) representing a nominal annual capacity of 50,000 m³. A fourth production site is as well under construction and shall be completed in 2012.

In addition, the Group continues to develop a network of R&D partnerships, including with the Joint BioEnergy Institute (JBEI) Novogy (United States), the University of Wageningen (Holland) and the Toulouse White Biotechnology consortium (TWB) (France) in technology segments that are complementary with Amyris’ platform: deconstruction of lignocelluloses and new biosynthesis processes.

 

 

41


Table of Contents

The Group is also assessing the potential of phototrophic processes and bio-engineering of microalgae. In December 2011, it entered into a partnership with Cellectis S.A. in exploratory research on molecules similar to petroleum products, from microalgae, for the energy and chemicals markets.

Carbochemistry

Carbon capture and storage

TOTAL is involved in a program to develop new carbon capture and storage technologies to reduce the environmental footprint of the Group’s industrial projects based on fossil energy.

In partnership with the French IFP Énergies Nouvelles (French Institute for Oil and Alternative Energies), TOTAL is involved in an R&D program related to chemical looping combustion, a new process to burn solid and gas feedstock that includes carbon capture at a very low energy cost. In 2010, this partnership resulted in the construction of a demonstration pilot at the Solaize site in France. A large-scale pilot is expected to be commissioned in 2013.

The Group is also involved in the EU-co-funded Carbolab project that intends to validate the carbon storage technology in coal seams and coalbed methane recovery.

DME

TOTAL is involved in the European “Bio-DME” project in Sweden, the goal of which is to validate a di-methyl ether

(DME) production chain through gasification of black liquor generated by a pulp mill. The pilot plant located in Pitea successfully came into production at the end of 2011. To date, three metric tons of bio-DME that meet the Group’s specifications for use as fuel have already been produced.

In addition, to support the commercial development of DME, TOTAL is involved with eight Japanese companies in a program intended to heighten consumers’ awareness of this new fuel in Japan. The 80 kt/y production plant (TOTAL, 10%), located in Niigata, started up in 2009.

Finally, via the International DME Association (IDA), TOTAL is participating in studies on the combustion of blends that include DME and in standardization efforts regarding the use of DME as fuel.

Coal production

For nearly thirty years, TOTAL has produced and exported coal from South Africa primarily to Europe and Asia. In 2011, TOTAL produced 3.8 Mt of coal.

With the start-up of production on the Dorstfontein East mine in 2011, the subsidiary Total Coal South Africa (TCSA) owns and operates five mines in South Africa. The Group continues to study other projects aimed at developing its mining resources.

The South African coal produced by TCSA or bought from third-parties’ mines is either marketed locally or exported through the port of Richard’s Bay, in which TOTAL holds a 5.7% interest.

 

 

DOWNSTREAM

 

 

The 2011 Downstream segment comprised TOTAL’s Refining & Marketing and Trading & Shipping divisions.

In October 2011, the Group announced a proposed reorganization of its Downstream and Chemicals segments. The procedure for informing and consulting with employee representatives took place and the reorganization became effective on January 1, 2012.

This led to organizational changes, with the creation of:

 

 

A Refining & Chemicals segment, a large industrial center that encompasses refining, petrochemicals,

   

fertilizers and specialty chemicals operations. This segment also includes oil trading and shipping activities.

 

 

A Supply & Marketing segment, which is dedicated to worldwide supply and marketing activities in the oil products field.

The Downstream activities described below, including the data as of December 31, 2011, are presented based on the organization in effect up to December 31, 2011.

 

 

42


Table of Contents

Refining & Marketing

 

 

TOTAL’s worldwide refining capacity was 2,088 kb/d at year end 2011, compared to 2,363 kb/d in 2010 and 2,594 kb/d in 2009. The Group’s worldwide refined products sales (including trading operations) in 2011 were 3,639 kb/d, compared to 3,776 kb/d in 2010 and 3,616 kb/d in 2009.

TOTAL is among the largest refiners/marketers in Western Europe(1), and the leading marketer in Africa(2).

Directly or via its holdings, TOTAL has a worldwide retail network of 14,819 service stations at year end 2011, compared to 17,490 in 2010 and 16,299 in 2009. Through its retail network, TOTAL provides fuels to more than 3 million customers every day. In addition, TOTAL produces a broad range of specialty products, such as lubricants, liquefied petroleum gas (LPG), jet fuel, special fluids, bitumen, heavy fuel, marine fuel and petrochemical feedstock.

The Group continues to adapt its business and improve positions in a context of growing demand worldwide, mainly in non-OECD countries, by focusing on three areas:

 

 

adapting to mature markets in Europe;

 

developing its positions in growth markets (Africa, Asia and the Middle East); and

 

developing specialty products worldwide.

In July 2011, TOTAL closed the sale to IPIC of its 48.83% stake in CEPSA as part of a public takeover bid on the entire share capital of CEPSA. With respect to Refining & Marketing operations, this sale concerns mainly four Spanish refineries (Huelva, Algeciras, Tenerife, Tarragona) and some marketing activities in Spain and Portugal.

In October 2011, TOTAL sold its network of service stations and its fuel and heating oil marketing business in the United Kingdom, the Channel Islands and the Isle of Man.

Refining

TOTAL has equity stakes in twenty refineries (including ten that it operates), located in Europe, the United States, the French West Indies, Africa and China.

In 2011, TOTAL continued its program of selective investments in Refining, which is focused on three areas: pursuing major ongoing projects (deep conversion at the Port Arthur refinery and construction of the Jubail refinery),

adapting the European refining system to structural market changes, and increasing safety and energy efficiency.

In Western Europe, TOTAL’s refining capacity was 1,792 kb/d in 2011, compared to 2,049 kb/d in 2010 and 2,282 kb/d in 2009, accounting for 85% of the Group’s overall refining capacity. The decrease in 2011 was due to the sale of the Group’s stake in CEPSA. The Group operates nine refineries in Western Europe and owns stakes in the Schwedt refinery in Germany and two refineries in Italy through its interest in TotalErg.

 

 

In France, where it owns five refineries, the Group continues to adapt its refining capacities and shift the production emphasis to diesel, in a context of structural decline in petroleum products demand in Europe and an increase in gasoline surpluses.

Since autumn 2010, TOTAL has been implementing its project to repurpose the Flanders site. The shutdown of the refining business will lead to gradually dismantling the units. The Group has commenced repurposing the site through the creation of a technical support center, a refining training school, an oil depot and business offices.

In addition, the industrial plan started in 2009 to adapt the Group’s refining base in France is ongoing. This plan is intended to reconfigure the Normandy refinery and rescale certain corporate departments at the Paris headquarters. At the Normandy refinery, the project is intended to upgrade the refinery and shift the production emphasis to diesel. For this purpose, the investments will result in the eventual reduction of the annual distillation capacity to 12 Mt from 16 Mt, upsizing the distillate hydrocracker and improving energy efficiency by lowering carbon dioxide emissions. The new structure is expected to become operational at the end of 2013.

In summer 2010, the Group divested its minority interest (40%) in the Société de la Raffinerie de Dunkerque (SRD), a company that specializes in bitumen and base oil production.

 

 

In the United Kingdom, the hydrodesulphurization (HDS) unit at the Lindsey refinery was commissioned in February 2011. The unit makes it possible to process up to 70% of high-sulphur crudes, compared to 10% previously, and increase low-sulphur diesel production. In 2010, the Group announced that it

 

 

 

(1)

Based on publicly available information, refining capacities and quantities sold.

(2) PFC Energy, based on quantities sold.

 

43


Table of Contents
   

would offer for sale its Lindsey refinery in the United Kingdom. Due to the difficult market conditions and the lack of sufficiently attractive and competitive offers, the Group decided in early 2012 to maintain the refinery within its refining network.

 

 

In Germany, an additional HDS unit designed to supply the German market with low-sulphur heating oil started up in autumn 2009 at the Leuna refinery.

 

 

In Italy, TotalErg (TOTAL, 49%) has operated the Rome refinery (100%) since October 2010 and holds a 25.9% stake in the Trecate refinery.

In the United States, TOTAL operates the Port Arthur refinery in Texas, with a capacity of 174 kb/d. In 2008, TOTAL launched an upgrading program that included the construction of a desulphurization unit commissioned in July 2010 and a vacuum distillation unit, a deep-conversion unit (or coker) and other associated units, which were successfully commissioned in April 2011. This project enables the refinery to process more heavy and high-sulphur crudes and to increase production of lighter products, in particular low-sulphur distillates.

In Saudi Arabia, TOTAL and Saudi Arabian Oil Company (Saudi Aramco) created a joint venture in 2008, Saudi Aramco Total Refining and Petrochemical Company (SATORP), to build a 400 kb/d refinery in Jubail held by Saudi Aramco (62.5%) and TOTAL (37.5%). TOTAL and Saudi Aramco each plan to retain a 37.5% interest with the remaining 25% expected to be listed on the Saudi stock exchange. The main contracts for the construction of the refinery were signed in mid-2009, concurrent with the start-up of work. Commissioning is expected in 2013.

The heavy conversion process of this refinery is designed for processing heavier crudes produced nearby and selling fuels and lighter products that meet strict specifications and are mainly intended for export. The refinery will also be integrated with petrochemical units.

In Africa, the Group has minority stakes in five refineries in South Africa, Senegal, Côte d’Ivoire, Cameroon and Gabon.

In the French West Indies, the Group has a 50% stake in the company Société Anonyme de la Raffinerie des Antilles (SARA), which owns a refinery in Martinique.

In China, TOTAL has a 22.4% stake in the WEPEC refinery, located in Dalian, in partnership with Sinochem and PetroChina.

Crude oil refining capacity

The table below sets forth TOTAL’s daily crude oil refining capacity(a):

 

As of December 31, (kb/d)    2011      2010      2009  

Refineries operated by the Group

                          

Normandy (France)

     199         199         338   

Provence (France)

     158         158         158   

Flanders (France)

                     137   

Donges (France)

     230         230         230   

Feyzin (France)

     117         117         117   

Grandpuits (France)

     101         101         101   

Antwerp (Belgium)

     350         350         350   

Leuna (Germany)

     230         230         230   

Rome (Italy)(b)

                     64   

Lindsey — Immingham (United Kingdom)

     221         221         221   

Vlissingen (Netherlands)(c)

     82         81         81   

Port Arthur, Texas (United States)

     174         174         174   

Subtotal

     1,862         1,861         2,201   

Other refineries in which the Group has equity stakes(d)

     226         502         393   

Total

     2,088         2,363         2,594   

 

(a) For refineries not 100% owned by TOTAL, the capacity shown is TOTAL’s equity share of the site’s overall refining capacity.
(b) TOTAL’s stake was 71.9% until September 30, 2010.
(c) TOTAL’s stake is 55%.
(d) TOTAL has equity stakes ranging from 12% to 50% in ten refineries (five in Africa, two in Italy, one in Germany, one in Martinique and one in China). TOTAL divested its stake in the Indeni refinery in Zambia in 2009. Since October 2010, the amounts include the Group’s share in the Rome and Trecate refineries through its stake in TotalErg. TOTAL divested its stake in CEPSA (four refineries) in 2011.

Refined products

The table below sets forth by product category TOTAL’s net share of refined quantities produced at the Group’s refineries(a):

 

(kb/d)    2011      2010      2009  

Gasoline

     350         345         407   

Aviation fuel(b)

     158         168         186   

Diesel and heating oils

     804         775         851   

Heavy fuels

     179         233         245   

Other products

     335         359         399   

Total

     1,826         1,880         2,088   

 

(a) For refineries not 100% owned by TOTAL, the production shown is TOTAL’s equity share of the site’s overall production.
(b) Avgas, jet fuel and kerosene.
 

 

44


Table of Contents

Utilization rate

The tables below set forth the utilization rate of the Group’s refineries:

 

      2011     2010     2009  

On crude and other feedstock(a)(b)

                        

France

     91     64     77

Rest of Europe (excluding CEPSA and TotalERG)

     77     85     88

Americas

     81     83     77

Asia

     67     81     80

Africa

     80     76     77

CEPSA and TotalERG(c)

     83     94     93

Average

     83     77     83

 

(a)    Including equity share of refineries in which the Group has a stake.

(b)    Crude + crackers’ feedstock/capacity and distillation at the beginning of the year.

(c)    For CEPSA in 2011: calculation of the utilization rate based on production and capacity prorated on the first seven months of the year.

 

       

        

        

      2011     2010     2009  

On crude(a)(b)

                        

Average

     78     73     78

 

(a) Including equity share of refineries in which the Group has a stake.
(b) Crude/capacity and distillation at the beginning of the year.

Marketing

TOTAL is one of the leading marketers in Western Europe.(1) The Group is also the largest marketer in Africa, with a market share of nearly 14%.(2)

TOTAL markets a wide range of specialty products produced from its refineries and other facilities. TOTAL is among the leading companies in the specialty products market, in particular for lubricants, LPG, jet fuel, special fluids, bitumen, heavy fuels and marine fuels, with products marketed in approximately 150 countries(3).

Europe

In Europe, TOTAL has a network of more than 9,400 service stations in France, Belgium, the Netherlands, Luxembourg and Germany, as well as in Italy through its share in TotalErg (49%).

TOTAL also operates a network of 615 AS24-branded service stations dedicated to commercial transporters.

TOTAL is among the leaders in Europe for fuel-payment cards, with approximately 3.5 million cards issued in twenty-seven European countries.

In Western Europe, TOTAL continued to optimize its Marketing business in 2011.

 

 

In France, the network benefits from a wide number of service stations and a diverse selection of products (such as the Bonjour convenience stores and car washes). Nearly 2,000 TOTAL-branded service stations and 270 Elf-branded service stations are operated in France. TOTAL also markets fuels at nearly 1,800 Elan-branded service stations, generally located in rural areas.

In October 2011, TOTAL launched Total access, a new service station concept combining low prices with TOTAL brand fuel and service quality. The Total access network will be made up of around 600 service stations in France, including the 270 Elf-branded service stations that will be rebranded as Total access. The project is expected to be fully implemented by 2014.

At the end of 2011, TOTAL finished implementing the project to adapt oil logistics operations announced in January 2010. The Pontet and Saint Julien oil depots were closed in October 2010. Operatorship of the Hauconcourt depot was transferred to a third party in October 2010. In July 2011, operatorship of the Le Mans oil depot was transferred to a third party and the Ouistreham oil depot was divested. In January 2010, TOTAL also divested half of its stake (reduced from 50% to 25%) in Dépôts Pétroliers de La Corse and transferred operatorship. Dyneff and TOTAL’s logistics assets in Port La Nouvelle were pooled in December 2011 under the umbrella of new company Entrepôt Pétrolier de Port La Nouvelle, which was created in July 2011.

In 2012, TOTAL is expected to complete the adaptation of oil logistics operations by implementing the project announced in September 2011. In the first half of 2012, the Brive and Chambéry depots are expected to be closed, and operatorship of the Lorient and Lyon depots is expected to be transferred to third parties. At the same time, TOTAL is expected to divest 24% of its current 50% stake in Entrepôt Pétrolier de Lyon. The Honfleur depot, which belongs to wholly-owned TOTAL subsidiary BTT, is expected to be closed in the second half of 2012.

 

 

 

(1) Based on publicly available information, quantities sold.
(2) Market share for the markets where the Group operates, based on publicly available information, quantities sold.
(3) Including via national distributors.

 

45


Table of Contents
 

In Italy, as part of the optimization of the Group’s downstream portfolio in Europe, TotalErg (TOTAL, 49%) was created in autumn 2010 through the merger of Total Italia and ERG Petroli. TotalErg has become the third largest operator in the Italian market with a network market share of nearly 13%(1) and more than 3,350 service stations.

 

 

In the United Kingdom, TOTAL announced in June 2011 that it had signed an agreement to sell its network of service stations and its fuel and heating oil marketing business in the United Kingdom, the Channel Islands and the Isle of Man. This sale was closed in October 2011. TOTAL continues to operate in specialty products in the United Kingdom, particularly lubricants and aviation fuel.

In Northern, Central and Eastern Europe, the Group is developing its positions primarily in the specialty products market. In 2011, TOTAL continued to expand its direct presence in the growing markets of Eastern Europe, in particular for lubricants. The Group intends to accelerate the growth of its specialty products business in Russia, Ukraine and the Balkans through the development of its direct presence in these markets since 2008.

AS24, which is active in twenty-six European countries, continued to expand its network, exceeding the milestone of 600 service stations and opening new outlets in two new countries, Ukraine (2011) and Georgia (early 2012). The AS24 network is expected to continue to grow, mainly through expansion in the Mediterranean Basin and Russia, by strengthening its position in strategic countries and through its toll payment card service, which covers more than seventeen countries.

Africa & the Middle East

TOTAL is the leading marketer of petroleum products on the African continent, with a market share of 14%.(2) Following the acquisition of marketing and logistics assets in Kenya and Uganda in 2009, the Group runs more than 3,500 service stations in more than forty countries and operates major networks in South Africa, Nigeria, Kenya and Morocco. As part of the optimization of its portfolio, the Group divested its subsidiary in Benin in late 2010.

TOTAL also has a large presence in Turkey and Lebanon, and is developing a network of large service stations in Jordan.

In the Middle East, the Group is active mainly in the specialty products market and is pursuing its growth strategy in the region, notably through the production and marketing of lubricants.

Asia-Pacific

At year-end 2011, TOTAL was present in nearly twenty countries in the Asia-Pacific region, primarily in the specialty products market. The Group is developing its position as a fuel marketer in the region, in particular in China. TOTAL operates service stations in Pakistan, the Philippines, Cambodia, Indonesia, and is a significant player in the Pacific Islands.

In China, the Group operated nearly 160 service stations at year-end 2011 through two TOTAL/Sinochem joint ventures.

In India, TOTAL is expected to open in early 2012 its first lubricants, bitumen, special fluids and additives technical support center outside Europe.

In Vietnam, TOTAL continues to strengthen its position in the specialty products market. The Group has become one of the leaders in the Vietnamese lubricants market due to the acquisitions of assets at year-end 2009.

Americas

In Latin America and the Caribbean, TOTAL is active in nearly twenty countries, primarily in the specialty products market. In the Caribbean, the Group holds a significant position in the fuel distribution business, which was strengthened by the acquisition in 2008 of marketing and logistics assets in Puerto Rico, Jamaica and the Virgin Islands.

In North America, TOTAL markets specialty products, mainly lubricants, and is continuing to grow with the acquisition at year-end 2009 of lubricant assets in the province of Quebec in Canada.

Sales of refined products

The table below sets forth TOTAL’s sales of refined products by region:

 

(kb/d)    2011      2010      2009  

France

     740         725         808   

Europe, excluding France(a)

     1,108         1,204         1,245   

United States

     47         65         118   

Africa

     304         292         281   

Rest of the World

     225         209         189   

Total excluding Trading

     2,424         2,495         2,641   

Trading

     1,215         1,281         975   

Total including Trading

     3,639         3,776         3,616   

 

(a) Including TOTAL’s share in CEPSA (up to end of July 2011) and, as from October 1, 2010, in TotalErg.
 

 

 

(1) PFC Energy, Unione Petrolifera, based on quantities sold.
(2) Market share in the countries where the Group operates, based on 2011 publicly available information, quantities sold.

 

46


Table of Contents

Service stations

The table below sets forth the number of service stations of the Group:

 

As of December 31,    2011      2010      2009  

France(a)

     4,046         4,272         4,606   

Europe, excluding France

     5,375         7,790         6,219   

of which TotalErg

     3,355         3,221           

of which CEPSA

             1,737         1,734   

Africa

     3,464         3,570         3,647   

Rest of the World

     1,934         1,858         1,827   

Total

     14,819         17,490         16,299   

 

(a) Total-, Elf- and Elan-branded service stations.

Biofuels

TOTAL is active in the biodiesel and biogasoline sectors. In 2011, TOTAL produced and blended 494 kt of ethanol(1) in gasoline at its European refineries(2) and several oil depots (compared to 464 kt in 2010 and 510 kt in 2009) and 1,859 kt of VOME(3) in diesel at its European refineries(4) and several oil depots (compared to 1,737 kt in 2010 and 1,655 kt in 2009).

TOTAL, in partnership with the leading companies in this area, is developing second generation biofuels derived from biomass. TOTAL is also working with leading worldwide public and private scientific partners on

biochemical and thermochemical biomass conversion.

The Group is thus participating in French, European and international bioenergy development programs. As part of this, TOTAL is involved in two demonstration projects:

 

 

BioTfueL, which aims to develop technology to convert biomass into biodiesel; and

 

Futurol, an R&D project for cellulosic bioethanol, which intends to develop and promote on an industrial scale a production process for bioethanol by fermentation of non-food lignocellulosic biomass.

Hydrogen and electric mobility

TOTAL is continuing its hydrogen fueling demonstrations as part of the Clean Energy Partnership in Germany. A new prototype station is being built in the center of Berlin and is scheduled to open in February 2012. TOTAL is also involved in the “H2 Mobility” study underway in Germany, which aims to identify the business model that would enable the creation of an infrastructure in light of the potential marketing of fuel cell vehicles between 2015 and 2020.

The number of prototype electric vehicle fueling stations (fast charge) is increasing. TOTAL now has twelve charging stations in Belgium. In France, two stations have been completed in the Paris area as part of the SAVE project, and six are being built in the Netherlands.

 

 

Trading & Shipping

 

 

The Trading & Shipping division:

 

 

sells and markets the Group’s crude oil production;

 

provides a supply of crude oil for the Group’s refineries;

 

imports and exports the appropriate petroleum products for the Group’s refineries to be able to adjust their production to the needs of local markets;

 

charters appropriate ships for these activities; and

 

undertakes trading on various derivatives markets.

 

The Trading & Shipping division’s main focus is serving the Group. In addition, the division’s expertise allows it to extend its scope of activities beyond its primary focus.

Trading & Shipping’s worldwide activities are conducted through various wholly-owned subsidiaries, including TOTSA Total Oil Trading S.A., Total International Ltd, Socap International Ltd, Atlantic Trading & Marketing Inc., Total Trading Asia Pte, Total Trading and Marketing Canada L.P., Total Trading Atlantique S.A. and Chartering & Shipping Services S.A.

 

 

 

(1) Including ethanol from ETBE (Ethyl-Tertio-Buthyl-Ether) and biomethanol from MTBE (Methyl-Tertio-Butyl-Ether).
(2) CEPSA’s refineries and oil depots are not included in 2011, 2010 and 2009 figures.
(3) VOME: Vegetable-Oil-Methyl-Ester. Including HVO (Hydrotreated Vegetable Oil).
(4) Including Total Erg’s Rome and Trecate refineries in Italy. CEPSA’s refineries and oil depots are not included in 2011, 2010 and 2009 figures.

 

47


Table of Contents

 

(1) Contango is a term used to describe an energy market in which the anticipated value of the spot price in the future is higher than the current spot price. The reverse situation is described as backwardation.

 

Trading

TOTAL is one of the world’s largest traders of crude oil and refined products on the basis of volumes traded. The table below sets forth selected information with respect to the worldwide sales and sources of supply of crude oil and sales of refined products for the Group’s Trading division for each of the last three years.

Trading of physical volumes of crude oil and refined products amounted to 4.4 Mb/d in 2011.

Trading division’s supply and sales of crude oil and sales of refined products(a)

 

(kb/d)    2011      2010      2009  

Group’s worldwide liquids production

     1,226         1,340         1,381   

Purchased by the Trading division from the Group’s Exploration & Production division

     960         1,044         1,054   

Purchased by the Trading division from external suppliers

     1,833         2,084         2,351   

Total of Trading division’s supply

     2,793         3,128         3,405   

Sales by Trading division to Group Refining & Marketing division

     1,524         1,575         1,752   

Sales by Trading division to external customers

     1,269         1,553         1,653   

Total of Trading division’s sales

     2,793         3,128         3,405   

Total sales of refined products

     1,632         1,641         1,323   

 

(a) Including condensates.

 

The Trading division operates extensively on physical and derivatives markets, both organized and over the counter. In connection with its trading activities, TOTAL, like most other oil companies, uses derivative energy instruments (futures, forwards, swaps, options) to adjust its exposure to fluctuations in the price of crude oil and refined products. These transactions are entered into with various counterparties.

For additional information concerning Trading & Shipping’s derivatives, see Notes 30 (Financial instruments related to

commodity contracts) and 31 (Market risks) to the Consolidated Financial Statements.

All of TOTAL’s trading activities are subject to strict internal controls and trading limits.

In 2011, the oil market tightened; as a result, the oil price rise accelerated and the structure of crude oil prices flipped from contango to backwardation(1).

 

 

             2011      2010      2009      min 2011     max 2011  

Brent ICE — 1st Line(a)

     ($/b     110.91         80.34         62.73         93.33         (Jan. 07     126.65         (Apr. 08

Brent ICE — 12th Line(b)

     ($/b     108.12         84.61         70.43         94.20         (Jan. 07     121.74         (Apr. 29

Contango/Backwardation time structure (12th-1st)

     ($/b     -2.79         4.27         7.70         -9.55         (Oct. 14     2.65         (Feb. 07

Gasoil ICE — 1st Line(a)

     ($/t     933.30         673.88         522.20         767.75         (Jan. 01     1,053.00         (Apr. 08

 

(a) 1st line: Average quotation on ICE Futures for first nearby month delivery.
(b) 12th Line: Average quotation on ICE Futures for twelfth nearby month delivery.

 

The oil markets had ended 2010 significantly up, driven by the very strong upturn in demand for oil (+2.8 Mb/d). The outbreak of war in Libya in February 2011 quickly deprived the oil market of 1.6 Mb/d of crude supply. On the international markets, the shutdown of Libyan crude production was aggravated by production losses in Nigeria (through attacks on oil infrastructure and diversion of the oil), Angola (with technical problems on several fields), Yemen (through attacks on oil infrastructure) and Syria (due to the embargo). The resulting crude oil deficit was offset mainly by Saudi Arabia, Kuwait and the United Arab Emirates, which all increased their production

considerably, thereby reducing the surplus available production capacity. Production in Libya gradually started up again from September 2011 and reached around 0.9 Mb/d at the end of 2011.

Overall in 2011, OPEC crude oil production was estimated to be slightly down compared to 2010 (-0.1 Mb/d), as was non-OPEC crude production (-0.2 Mb/d). The production of other liquids in 2011 (LPG, LNG, biofuels) rose (+0.5 Mb/d).

With regard to demand, the significant price rise and generally weaker economic growth than in 2010 slowed

 

 

48


Table of Contents

growth in oil demand, which fell from +2.8 Mb/d in 2010 to +0.5 Mb/d in 2011.

In this environment, crude oil prices, which started rising at the beginning of the year, increased from an average of approximately $96/b (ICE Brent 1st Line) in January 2011 to $123/b in April 2011 while the market adjusted to the loss of Libyan supply. Prices fell slightly in the second half of 2011, particularly under the effect of the IEA’s emergency stock release (60 Mb offered, 35 Mb delivered) and the partial resumption of Libyan production. Crude oil prices remained high however, reaching an annual average in 2011 of $110.91/b.

As a result of the backwardation in the price structure on the crude oil market for almost the entire year, 2011 was also marked by a sharp fall in OECD oil industry inventories through October 2011 (year-on-year, crude -70 Mb and products -46 Mb), which diminished in the last 2 months of the year with the rise in Libyan crude production (December 2011 year-on-year, crude -26 Mb and

products -36 Mb).

2011 also saw a widening of the price differential between WTI crude (confined to the central United States) and Brent crude (delivered in the North Sea and accessible internationally). While Brent was experiencing upward pressure due to the balance of crude oil on the international market, WTI was under downward pressure from a continuous rise in local production and exports from Canada, the combination of which exceeded local refining capacity requirements and potential exports outside the region. The price of WTI thus rose less quickly than Brent, increasing the gap to almost -$28/b in mid-October (at the height of the upward pressure on Brent).

The gap was more than halved at the end of the year, particularly with the announcement of the planned reversal of the Seaway pipeline, which should ease the pressure from the surplus of crude weighing down markets in the central United States.

 

 

Shipping

 

TOTAL’s Shipping division arranges the transportation of crude oil and refined products necessary to develop the Group’s activities. These needs are met through transactions on the spot market and the development of a balanced time charter policy. It has a rigorous safety policy that is due mainly to the strict selection of the vessels the division charters. Like a certain number of other oil companies and shipowners, the Group uses freight rate derivative contracts in its shipping activity to adjust its exposure to freight rate fluctuations.

In 2011, TOTAL’s Shipping division chartered approximately 3,000 voyages to transport approximately 110 Mt of crude oil and refined products. As of December 31, 2011, it employed a fleet of fifty vessels chartered under long-term or medium-term agreements (including eight LPG carriers), of which none is single-hulled. The fleet has an average age of approximately five years.

 

 

Freight rates average of three representative routes for crude transportation

 

             2011      2010      2009      min 2011     max 2011  

VLCC Ras Tanura Chiba — BITR(a)

     ($/t     11.99         13.41         10.43         9.32         (Oct. 10     18.54         (Feb. 15

Suezmax Bonny Philadelphia-BITR

     ($/t     13.86         14.50         12.75         10.23         (Jan. 20     19.85         (Mar. 22

Aframax Sullom Voe Wilhemshaven-BITR

     ($/t     6.51         6.39         5.20         5.04         (Jan. 17     9.46         (Mar. 4

 

(a) VLCC: Very Large Crude Carrier. BITR: Baltic International Tanker Routes.

 

2011 was a particularly eventful and difficult period for oil shipping activities.

During the first half of 2011, events in Japan and North Africa had a strong impact on crude oil imports. Requirements in Japan fell suddenly and very markedly, but were quickly restored and returned to almost pre-crisis levels by the end of 2011. In the end, the impact on demand for shipping was relatively limited. In the Mediterranean, the shutdown of Libyan production resulted in the rebalancing of demand for long-haul VLCC shipments: imports, particularly to Europe, were offset by supply from further away, thus increasing the demand for transportation.

On a more global level, the market was buoyed by demand from China, which is still growing strongly, and to a lesser extent the United States.

Despite this generally favorable demand structure, the freight market operated at overcapacity for most of 2011. Very few ships were decommissioned and 2011 saw a steady stream of new vessels being delivered as a result of the many orders placed by shipowners in 2007 and 2008.

This situation severely damaged the fundamentals of the freight market for crude oil transport. Following the extremely cold weather at the beginning of 2011, which sustained rates for a time, there was a collapse in the

 

 

49


Table of Contents

second quarter that left the market at a historic low. With regard to the product tanker market, the situation remains

poor worldwide, with transatlantic traffic to the United States particularly slow.

 

 

CHEMICALS

 

 

The 2011 Chemicals segment included the Base Chemicals (petrochemicals and fertilizers businesses) and Specialty Chemicals (elastomer processing, adhesives and electroplating chemistry businesses) divisions. TOTAL is one of the world’s largest integrated chemical producers.(1)

In October 2011, the Group announced a proposed reorganization of its Downstream and Chemicals segments. The procedure for informing and consulting with employee representatives took place and the reorganization became effective on January 1, 2012.

This led to organizational changes, with the creation of:

 

 

A Refining & Chemicals segment, a large industrial center that encompasses refining, petrochemicals, fertilizers and specialty chemicals operations. This

   

segment also includes oil trading and shipping activities.

 

 

A Supply & Marketing segment, which is dedicated to worldwide supply and marketing activities in the oil products field.

The Chemicals activities described below, including the data as of December 31, 2011, are presented based on the organization in effect up to December 31, 2011.

Base Chemicals

The Base Chemicals division includes TOTAL’s petrochemicals and fertilizers activities.

In 2011, the Base Chemicals division’s sales were 12.7 billion, compared to 10.7 billion in 2010 and 8.7 billion in 2009.

 

 

Petrochemicals

BREAKDOWN OF TOTAL’S MAIN PRODUCTION CAPACITIES

 

(in thousands of tons)    2011      2010      2009  
   Europe      North America      Asia and Middle
East
(a)
     Worldwide      Worldwide      Worldwide  

Olefins(b)

     4,695         1,195         1,460         7,350         7,190         6,895   

Aromatics

     2,500         940         770         4,210         4,195         4,195   

Polyethylene

     1,180         440         520         2,140         2,140         2,040   

Polypropylene

     1,315         1,175         345         2,835         2,780         2,780   

Styrenics(c)

     1,150         1,260         730         3,140         2,950         3,090   

 

(a) Including minority interests in Qatar and 50% of Samsung-Total Petrochemicals capacities.
(b) Ethylene, propylene and butadiene.
(c) Styrene and polystyrene.

 

The petrochemicals business includes base petrochemicals (olefins and aromatics) and their polymer derivatives (polyolefins and styrenics).

In Europe, the main petrochemical sites are located in Belgium, in Antwerp (steam crackers, polyethylene) and Feluy (polypropylene, polystyrene), and in France, in Carling (steam cracker, polyethylene, polystyrene), Feyzin (steam cracker), Gonfreville (steam crackers, styrene, polyolefins, polystyrene) and Lavéra (steam cracker, polypropylene).

In the United States, the main petrochemical sites are located in Carville, Louisiana (styrene, polystyrene), and in

Texas, in Bayport (polyethylene), La Porte (polypropylene) and Port Arthur (steam cracker, butadiene).

In Asia, TOTAL owns, in partnership with Samsung, a 50% interest in the petrochemical site located in Daesan, South Korea (steam cracker, styrene, paraxylene, polyolefins). The Group is also active through its polystyrene plants located in Singapore and Foshan (China).

In Qatar, the Group holds interests in two steam crackers and several polyethylene lines.

Most of these sites are either adjacent to or connected by pipelines to Group refineries. As a result, most of TOTAL’s petrochemical operations are integrated within refining operations.

 

 

 

(1) Based on publicly available information, consolidated sales.

 

50


Table of Contents

TOTAL continues to strengthen its leadership positions in the industry by focusing on the following three main strategic areas:

 

 

In Europe, TOTAL is improving the competitiveness of its long-established sites notably through cost management, better energy efficiency at its facilities and increased flexibility in the choice of feedstock.

In an increasingly competitive environment, the Group launched two reorganization plans mainly for the Carling (eastern France) and Gonfreville (northwestern France) sites:

 

   

The first plan, launched in 2006, called for the closure of one of the steam crackers and the styrene plant at Carling and the construction of a new world-class(1) styrene plant at Gonfreville to replace the plant closed in late 2008. The reorganization plan was completed in the first quarter of 2009.

 

   

The second plan, launched in 2009, is a consolidation project to improve the sites’ competitiveness. This project includes a plan to upgrade the Group’s most efficient units by investing approximately 230 million over three years to increase energy efficiency and competitiveness of the steam cracker and the high-density polyethylene unit in Gonfreville, and to consolidate polystyrene production at the Carling facility. It also includes the shutdown of structurally loss-making units, effective from the end of 2009: two low-density polyethylene lines, one in Carling and one in Gonfreville, and a polystyrene line in Gonfreville. This reorganization plan also impacted the support services at both sites and the central services at Total Petrochemicals France.

Following its sole customer’s termination of the supply contract for the secondary butyl alcohol produced at the Notre-Dame-de-Gravenchon facility in Normandy, this dedicated facility had to be closed in the second half of 2010.

At the end of 2011, TOTAL signed an agreement relating to the acquisition of 35% of ExxonMobil’s stake in Fina Antwerp Olefins, Europe’s second largest base petrochemicals (monomers) production plant. Following approval by the relevant authorities, the transaction was finalized in February 2012 and TOTAL became the sole shareholder in Fina Antwerp Olefins on March 1, 2012. The acquisition will open new

opportunities to strengthen the competitiveness of the assets and to pursue integration which is one of the foundations of Total’s strategy.

In the United States, TOTAL and BASF purchased in 2011 Shell’s stake in Sabina, one of the largest butadiene production plants in the world. TOTAL and BASF are now the only two shareholders in Sabina, with stakes of 40% and 60%, respectively. This new structure will allow for increased synergies with the TOTAL refinery and the jointly-owned steam cracker (TOTAL 40%, BASF 60%) located on the same site in Port Arthur, Texas.

 

 

TOTAL is continuing to expand in growth areas.

In Asia, the Samsung-Total Petrochemicals Co. Ltd joint venture (TOTAL, 50%) completed in mid-2011 the first debottlenecking phase of the units at the Daesan site in South Korea, with the aim of bringing them to full capacity. This first phase included increasing the capacity of the steam cracker to 1 Mt/y and the polyolefin units to 1,150 kt/y.

The second phase is expected to take place in September 2012 and involves increasing the capacity of the paraxylene unit to 700 kt/y.

In addition, to keep up with growth on the Asian markets, two major investments have been approved for planned start-up in 2014: a new 240 kt/y EVA(2) unit and a new aromatic unit with a capacity of 1.5 Mt/y of paraxylene and benzene, the feedstock of which will be supplied by a condensate splitter that will also produce jet fuel and diesel. As a result, the site’s paraxylene production capacity will be increased to 1.8 Mt/y.

In the Middle East, the 700 kt/y paraxylene unit at the Jubail refinery in Saudi Arabia is under construction. This world-class unit is mainly intended to supply the Asian market. Start-up is scheduled for 2013.

 

 

TOTAL is developing sites in countries with favorable access to raw materials.

In Qatar, through its interest in Qatofin and Qapco, TOTAL holds a 49% interest in a world-class linear low-density polyethylene plant with a capacity of 450 kt/y in Mesaieed. This unit, operated by Qatofin,

started up in 2009. The Group also holds a 22% interest in an ethane-based steam cracker in Ras Laffan designed for processing 1.3 Mt/y of ethylene. The steam cracker started up in March 2010. In

 

 

 

(1) Facilities ranking among the first quartile for production capacities based on publicly available information.
(2) Ethylene Vinyl Acetate.

 

51


Table of Contents

addition, construction of a 300 kt/y low-density polyethylene line has started at Qapco, in which TOTAL holds a 20% interest, with start-up scheduled for the second quarter of 2012.

In China, TOTAL and China Power Investment signed in November 2010 an agreement to study a project to build a coal-to-olefins plant and a polyolefins plant. TOTAL will bring to this partnership its expertise in the methanol-to-olefins (MTO) and olefin cracking process (OCP) technologies tested extensively at its plant in Feluy, Belgium.

Base petrochemicals

Base petrochemicals includes olefins and aromatics (monomers) produced by the steam cracking of petroleum cuts, naphtha and LPG, or of gas as well as propylene and aromatics manufactured in the Group’s refineries. The economic environment for these activities is strongly influenced by the balance between supply and demand and changes in feedstock prices, especially naphtha.

The market was buoyant in the first half of 2011, followed by a significant slowing in volumes and falling margins, mainly in Europe and the United States, in the second half. Over 2011 as a whole, TOTAL’s production volumes remained stable.

TOTAL is expanding its positions in Asia and the Middle East with the start-up of the Ras Laffan steam cracker in 2010 in Qatar and continued investments to increase capacities in South Korea. In Europe and the United States, TOTAL is improving energy efficiency at its sites, strengthening synergies with refining and increasing the flexibility of the steam cracker feedstock.

Polyolefins

TOTAL’s strategy for polyolefins (polyethylene, polypropylene) is based on lowering the breakeven point of its plants in Europe and the United States and continuing to differentiate its range of products, while meeting new market requirements for sustainable development. The Group is also continuing to expand its activities in growth areas, mainly through its stakes in joint ventures in South Korea and Qatar.

Polyethylene: Polyethylene is a plastic resulting from the polymerization of ethylene produced by the Group’s steam crackers. It is primarily intended for the packaging, automotive, food, cable and pipe markets. Margins are strongly influenced by the level of demand and the price of ethylene. In Europe, margins are impacted by competition from expanding production in the Middle East, which benefits from favorable access to ethane, the raw material used in ethylene production.

2011 was marked by a slowdown in growth in demand in all geographical areas and by falling margins, more particularly in the second half. Europe was most affected by this deterioration in the market environment.

The Group’s sales volumes increased by 2% in 2011.

Polypropylene: Polypropylene is a plastic resulting from the polymerization of propylene produced by the Group’s steam crackers and refineries. It is primarily intended for the automotive, packaging, carpet, household appliances, fibers and hygiene markets. Margins are mainly influenced by the level of demand and the availability and price of propylene.

As with polyethylene, 2011 saw a slowdown in growth in worldwide demand and falling margins in the second half of the year.

TOTAL’s sales volumes decreased by 2.5% compared to 2010.

Styrenics

This business activity includes the production of styrene and polystyrene. Most of the styrene manufactured by the Group is used to produce polystyrene, a plastic principally used in food packaging, insulation, refrigeration, domestic appliances and electronic devices. Margins are strongly influenced by the level of polystyrene demand and the price of benzene, which is styrene’s principal raw material.

The worldwide styrenics market increased by approximately 2% in 2011, driven by Asia, while the markets in Europe and the United States remained practically stable. Margins were low on the highly competitive European and Asian markets, but remained high in the United States.

TOTAL’s polystyrene sales volumes increased by 4% in 2011.

The Group continues to expand its styrenics business. In Feluy, Belgium, TOTAL is building a new-generation expandable polystyrene manufacturing plant. Start-up is scheduled for early 2013. The expandable polystyrene is intended for the insulation market, which is experiencing strong growth. In China, TOTAL doubled the capacity of the Foshan compact polystyrene plant to 200 kt/y in early 2011.

Fertilizers

Through its French subsidiary GPN, TOTAL manufactures and markets nitrogen fertilizers made from natural gas. Margins are strongly influenced by the price of natural gas.

 

 

 

52


Table of Contents

In 2010 and 2011, GPN’s production was affected by a number of manufacturing incidents that resulted in long shutdowns for maintenance of the Grandpuits and Rouen ammonia plants in France and reduced production at the downstream plants (nitric acid, urea and ammonium nitrate). These incidents adversely affected the results of GPN, which could not take advantage of favorable global market conditions.

GPN’s plans were strengthened through two major investments: the construction of a nitric acid plant in Rouen, which started up in the second half of 2009, and a urea plant in Grandpuits, the start-up of which was ongoing in March 2012. This additional urea production will enable GPN to position itself in the growing markets of products that contribute to reducing nitrogen oxide emissions(1): DeNOx® for industrial applications and Adblue® for transportation applications. An Adblue unit has been maintained at Oissel waiting for the start-up of the Grandpuits plant.

In France, three obsolete nitric acid units in Rouen and Mazingarbe were closed in 2009 and 2010.

GPN’s mines and quarries business at the Mazingarbe site was divested in January 2011. Sales for the divested lines of business were 30 million in 2010.

In November 2011, the Group initiated the process of divesting its stake (50%) in Pec-Rhin. Having exercised its pre-emptive right on its partner’s 50%, GPN signed an agreement for the complete divestment of Pec-Rhin. Following approval by the relevant authorities, the disposal was finalized in January 2012. These actions are intended to improve the competitiveness of GPN by regrouping its operations at two sites that have production capacity greater than the European average.

Specialty Chemicals

TOTAL’s Specialty Chemicals division includes elastomer processing (Hutchinson), adhesives (Bostik) and electroplating chemistry (Atotech). It serves the automotive, construction, electronics, aerospace and convenience goods markets, for which marketing, innovation and customer service are key drivers. TOTAL markets specialty products in more than sixty countries and intends to develop by combining organic growth and targeted acquisitions. This development is focused on high-growth markets and the marketing of innovative products with high added value that meet the Group’s sustainable development approach.

 

The Hutchinson consumer goods business (Mapa® and Spontex®) was divested in spring 2010. Sales for the divested lines of business were 530 million in 2009.

The Cray Valley coating resins and Sartomer photocure resins businesses were divested in July 2011. Sales for the divested lines of business were 860 million in 2010. The structural and hydrocarbon resins business lines were kept and have been incorporated into the Petrochemicals division.

Specialty Chemicals enjoyed a favorable climate in the first three quarters of 2011 due to the resilience of the European and North American markets and continued growth in the emerging countries. The situation deteriorated in the fourth quarter. In this context and on a like-for-like basis (excluding Mapa Spontex and Resins), 2011 sales were 5.3 billion, a 9% increase compared to 2010.

Elastomer processing

Hutchinson manufactures and markets products derived from elastomer processing that are principally intended for the automotive, aerospace and defense industries.

Hutchinson, among the industry’s leaders worldwide(2), provides its customers with innovative solutions in the areas of fluid transfer, air and fluid seals, anti-vibration, sound and thermal insulation, and transmission and mobility.

Hutchinson has eighty production sites worldwide, including fifty-two in Europe, fifteen in North America, seven in South America, five in Asia and one in Africa.

Hutchinson’s sales were 2.99 billion in 2011, up 10% compared to 2010. Sales for the automotive business increased 11% due to stable sales on the European and North American markets and increased sales on the Latin American and Chinese markets. On the industrial markets, sales increased at a lower rate because of the decline in the business planes, helicopters and defense markets, while sales on other industrial markets (e.g., civil aviation, railway, and offshore) saw similar rises to the automotive business.

To strengthen its position in the aerospace industry, in late 2008 Hutchinson acquired Strativer, a French company specialized in the growing composite materials market, and, in early 2011, Hutchinson acquired Kaefer, a German company specialized in aircraft interior equipment (insulation, ventilation ducts, etc.). In the automotive sector, in April 2011 Hutchinson acquired Keum-Ah, a South Korean company specialized in fluid transfer systems.

 

 

 

(1) Nitrogen oxide emissions are noxious to the environment and subject to regulation.
(2) Based on publicly available information, consolidated sales.

 

53


Table of Contents

Hutchinson continues to develop in expanding markets, primarily Eastern Europe, South America and China, relying notably on the Brasov (Romania), Lodz (Poland), Sousse (Tunisia) and Suzhou (China) sites and on the Casa Branca site (Brazil) opened in 2011.

Adhesives

Bostik is one of the world leaders in the adhesive sector(1) and has significant positions on the industrial, hygiene and construction markets, complemented by both consumer and professional distribution channels.

Bostik has forty-six production sites worldwide, including twenty-one in Europe, nine in North America, seven in Asia, six in Australia and New Zealand, two in Africa and one in South America.

In 2011, sales were 1.43 billion, up 3% compared to 2010.

Bostik continues to strengthen its technological position in the construction and industrial sectors, pursue its program for innovation focused on sustainable development, keep up with its expansion in high-growth countries and improve its operational performance.

2011 saw the start-up of two new production units in Egypt and Vietnam and the opening of a new regional technology center for Asia in Shanghai. In addition, Bostik plans to commission a third production unit in Changshu, China in 2012, which is expected to be Bostik’s largest plant worldwide. In the United States, Bostik acquired StarQuartz in 2011, increasing its range of construction adhesives.

Finally, Bostik continued to rationalize its industrial base with the closure of the Ibos site in France, which came into effect at year-end 2011.

Electroplating

Atotech is the second largest company in the electroplating sector based on worldwide sales(1). It is active on the markets for electronics (printed circuits, semiconductors) and general metal finishing (automotive, construction, furnishing).

Atotech has sixteen production sites worldwide, including seven in Asia, six in Europe, two in North America and one in South America.

Atotech’s sales were 0.89 billion in 2011, up 14% compared to 2010 due to favorable conditions on all of its markets and a significant increase in equipment sales on the electronics market.

In order to strengthen its position on the electronics market, in 2011 Atotech started up a new production unit aimed at the semiconductors market in Neuruppin (Germany) and acquired adhesive technologies (molecular interfaces) in the nanotechnology sector in the United States.

Atotech successfully pursued its strategy designed to differentiate its products through a comprehensive service provided to its customers in terms of equipment, processes, design and chemical products and through the development of green, innovative technologies to reduce the environmental footprint. This strategy relies on global coverage provided by its technical centers located near customers.

Atotech intends to continue to develop in Asia, which represents almost 60% of its global sales.

 

 

OTHER MATTERS

 

 

Various factors, including certain events or circumstances discussed below, have affected or may affect TOTAL’s business and results.

Exploration and production legal considerations

TOTAL’s exploration and production operations are conducted in various countries and are therefore subject to a broad range of regulations. These cover virtually all aspects of exploration and production operations,

including leasehold rights, production rates, royalties, environmental protection, exports, taxes and foreign exchange rates. The terms of the concessions, licenses, permits and contracts governing the Group’s ownership of oil and gas interests vary from country to country. These concessions, licenses, permits and contracts are generally granted by or entered into with a government entity or a state-owned company and are sometimes entered into with private owners. These arrangements usually take the form of concessions or production sharing contracts.

 

 

 

(1) Based on publicly available information, consolidated sales.

 

54


Table of Contents

 

The oil concession agreement remains the traditional model for agreements entered into with States: the oil company owns the assets and the facilities and is entitled to the entire production.

In exchange, the operating risks, costs and investments are the oil company’s responsibility and it agrees to remit to the relevant State, usually the owner of the subsoil resources, a production-based royalty, income tax, and possibly other taxes that may apply under local tax legislation.

The production sharing contract (PSC) involves a more complex legal framework than the concession agreement: it defines the terms and conditions of production sharing and sets the rules governing the cooperation between the company or consortium in possession of the license and the host State, which is generally represented by a state-owned company. The latter can thus be involved in operating decisions, cost accounting and production allocation.

The consortium agrees to undertake and finance all exploration, development and production activities at its own risk. In exchange, it is entitled to a portion of the production, known as “cost oil”, the sale of which should cover all of these expenses (investments and operating costs). The balance of production, known as “profit oil”, is then shared in varying proportions, between the company or consortium, on the one hand, and with the State or the state-owned company, on the other hand.

In some instances, concession agreements and PSCs coexist, sometimes in the same country. Even though there are other contractual models, TOTAL’s license portfolio is comprised mainly of concession agreements.

In every country, the authorities of the host State, often assisted by international accounting firms, perform joint venture and PSC cost audits and ensure the observance of contractual obligations.

In some countries, TOTAL has also signed contracts called “risked service contracts”, which are similar to production sharing contracts. However, the profit oil is replaced by risked monetary remuneration, agreed by contract, which depends notably on the field performance. Thus, the remuneration under the Iraqi contract is based on an amount calculated per barrel produced.

Oil and gas exploration and production activities are subject to authorization granted by public authorities (licenses), which are granted for specific and limited periods of time and include an obligation to return a large portion, or the entire portion in case of failure, of the area covered by the license at the end of the exploration period.

TOTAL pays taxes on income generated from its oil and gas production and sales activities under its concessions, production sharing contracts and risked service contracts, as provided for by local regulations. In addition, depending on the country, TOTAL’s production and sales activities may be subject to a number of other taxes, fees and withholdings, including special petroleum taxes and fees. The taxes imposed on oil and gas production and sales activities may be substantially higher than those imposed on other industrial or commercial businesses.

The legal framework of TOTAL’s exploration and production activities, established through concessions, licenses, permits and contracts granted by or entered into with a government entity, a state-owned company or, sometimes, private owners, is subject to certain risks that, in certain cases, can reduce or challenge the protections offered by this legal framework.

Industrial and environmental considerations

TOTAL’s operations involve certain industrial and environmental risks which are inherent in handling, processing and use of products that are flammable, explosive, polluting or toxic.

The broad scope of TOTAL’s activities, which include drilling, oil and gas production, on-site processing, transportation, refining and petrochemical activities, storage and distribution of petroleum products, and production of base and specialty chemicals, involve a wide range of operational risks. Among these risks are those of explosion, fire, leakage of toxic products, and pollution. In the transportation area, the type of risk depends not only on the hazardous nature of the products transported, but also on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road), the volumes involved, and the sensitivity of the regions crossed (quality of infrastructure, population density, environmental considerations).

Most of these activities also involve environmental risks related to emissions into the air, water or soil and the production of waste, and also require environmental site remediation and closure and decommissioning after production is discontinued.

The industrial events that can have the most significant impact are primarily a major industrial accident (fire, explosion, leakage of highly toxic products) or large-scale accidental pollution.

All the risks described correspond to events that could potentially cause injury or death, damage property and business activities, cause environmental damage or harm human health. TOTAL employees, contractors, residents

 

 

55


Table of Contents

living near the facilities or customers can suffer injuries. Property damage can involve TOTAL’s facilities as well as the property of third parties. The seriousness of the consequences of these events varies according to the vulnerability of the people, ecosystems and business activities impacted, on the one hand, and the number of people in the impact area and the location of the ecosystems and business activities in relation to TOTAL’s facilities or to the trajectory of the products after the event, on the other hand.

Moreover, oil and gas exploration and production activities are particularly exposed to risks related to the physical characteristics of an oil or gas field. These risks include eruptions of crude oil or natural gas, which notably could result from drilling into abnormally pressurized hydrocarbon pockets.

TOTAL conforms to the REACH regulation, which purpose is to protect health and safety of products and chemical substances producers and users notably by providing detailed information through safety data sheets (SDS/ESDS). Like most other industrial groups, TOTAL is concerned by reports of occupational illnesses, in particular those caused by asbestos exposure. Asbestos exposure has been subject to close monitoring at all of the Group’s business units. As of December 31, 2011, the Group estimates that the ultimate cost of all asbestos-related claims paid or pending is not likely to have a material impact on the Group’s financial situation.

TOTAL’s entities actively monitor regulatory developments to comply with local and international rules and standards for the evaluation and management of industrial and environmental risks. In case of operations being stopped, the Group’s environmental contingencies and asset retirement obligations are addressed in “Asset retirement obligation” and “Provisions for environmental contingencies” in Note 19 to the Consolidated Financial Statements. Future expenses related to asset retirement obligations are accounted for in accordance with the principles described in paragraph Q of Note 1 to the Consolidated Financial Statements.

Health, safety and environment regulations

TOTAL is subject to extensive and increasingly strict health, safety and environmental (“HSE”) regulations in the European Union (“EU”), the United States and the rest of the world.

The following is a non-exhaustive list of HSE regulations and directives that affect TOTAL’s operations and products in the EU:

 

 

The Industrial Emissions Directive (“IED”) entered into force on January 6, 2011, and must be transposed

   

into national legislation by EU Member States by January 7, 2013. This Directive replaced a number of existing industrial emission directives, including the Integrated Pollution Prevention and Control Directive (2008/1/EC — “IPPC”) and the Large Combustion Plant Directive (2001/80/EC).

By imposing the reduction of emissions from industrial installations, the IED will progressively result in stricter emission limits on some of TOTAL’s facilities by making compulsory certain rules described in BREFs (Reference documents on Best Available Techniques).

 

 

The Air Quality Framework Directive (2008/50/CE) and related directives on ambient air quality assessment and management, among other things, limit emissions of sulphur dioxide, nitrogen dioxide and oxides of nitrogen, particulate matter, lead, carbon monoxide, benzene and ozone.

 

 

Existing directives controlling and limiting exhaust emissions from cars and other motor vehicles are expected to continue to become more stringent over time. Since 2009, a maximum sulphur content of 10 ppm is mandatory throughout the EU.

 

 

The Sulphur Content Directive (1999/32/EC, as amended) limits sulphur in diesel fuel to 0.1% (since January 2008) and limits sulphur in heavy fuel oil to 1% (since January 2003), with certain exceptions for combustion plants provided that local air quality standards are met.

 

 

The 1996 Major Hazards Directive (Seveso II) requires emergency planning, public disclosure of emergency plans, assessment of hazards and effective emergency management systems. A revision process is currently pending to strengthen rules on the control of major accident hazards involving chemicals. The revision will align the legislation to changes in EU chemicals law and will clarify and update other provisions, including introducing stricter inspection standards and improving the level and quality of information available to the public in the event of an accident. The new directive is expected to apply from June 1, 2015.

In October 2011, the European Commission proposed a regulation on the safety of offshore oil and gas activities. The regulation introduces rules for the effective prevention of and response to a major accident that would be immediately applicable to new installations and with transitional periods for existing installations.

 

 

Numerous directives regulate the classification, labeling and packaging of chemical substances and

 

 

56


Table of Contents
   

their preparation, as well as restrict and ban the use of certain chemical substances and products.

On the one hand, the EU Parliament and Council adopted a regulation in December 2008 (now in force) on the Classification, Labelling and Packaging of Substances and Mixtures that incorporates the classification criteria and labelling rules agreed at the UN level (the so-called Globally Harmonized System of Classification and Labelling of Chemicals (GHS)).

On the other hand, the EU Member States, the European Commission and the European Chemical Agency are in the process of implementing the regulation adopted in 2006 for the Registration, Evaluation and Authorization of Chemicals (REACH) that replaces or complements the existing rules in this area. REACH required the pre-registration of chemical substances manufactured and imported into the EU by December 1, 2008, to qualify for full registration under a phase in during the period 2010-2018. This regulation requires the registration and identification of chemical substances manufactured or imported in EU Member States, and can result in restrictions on the sales or uses of such substances. GHS and REACH will require us to evaluate the hazards of our chemicals and products and may result in future changes to warning labels and material safety data sheets.

 

 

The Framework Directive on Waste Disposal is intended to ensure that waste is recovered or disposed of without endangering human health and without using processes or methods that could unduly harm the environment. Numerous related directives regulate specific categories of waste. In November 2008, the Framework Directive on Waste Disposal was partially modified by the Directive on Waste 2008/98, which features more precise definitions and stronger provisions. Transposition of this Directive in France occurred with the Ordinance of December 17, 2010.

 

 

A number of Maritime Safety Directives were passed in the wake of the Erika and Prestige spills, and implemented in France by Ordinance n° 2011-635 dated June 9, 2011. Those regulations, found in the three Maritime Safety Packages, require that tankers have double hulls and that ship owners acquire improved insurance coverage, mandate improvements to traffic monitoring, accident investigations and in-port vessel inspection (Port State Control: objective of 100% inspection in the EU), and further regulate organizations that inspect and confirm conformity to applicable regulations (Classification Societies). The last package will enter into force in 2012.

 

Numerous directives impose water quality standards based on the various uses of inland and coastal waters, including ground water, by setting limits on the discharges of many dangerous substances and by imposing information gathering and reporting requirements.

Adopted and effective since 2000, a comprehensive Water Framework Directive is progressively replacing numerous existing directives with a comprehensive set of requirements, including additional regulations obligating member countries to classify all water courses according to their biological, chemical and ecological quality, and to completely ban the discharges of approximately thirty toxic substances by 2017.

The law n° 2011-835 was adopted in France in July 2011 to prohibit the exploration and operation of shale gas by hydro-fracking technique and to repeal the exclusive research permits for projects using this technique. Consequently, the exclusive research permits issued to TOTAL at Montelimar (in the south of France) were repealed by the French Government. An administrative procedure is currently pending against this repeal.

 

 

In March 2004, the EU adopted a Directive on Environmental Liability (2004/35/EC). The Directive seeks to implement a strict liability approach for damage to water resources, soils and protected species and habitats by authorized industrial activities.

 

 

Directives implementing the Aarhus Convention of June 25, 1998, concerning public information rights and certain public participation rights in a variety of activities affecting the environment were adopted in January and May 2003, respectively. French regulations on public inquiry and impact assessment were adopted in 2011 and will enter into force on June 2012. These regulations aim to reinforce public participation and information rights concerning projects that could affect the environment.

 

 

In November 2008, the EU adopted a directive on the protection of the environment through criminal law that obliges EU Member States to provide for criminal penalties in respect of serious infringements of EC law (Directive 2008/99/EC). This directive was transposed in France in January 2012.

 

 

With respect to the climate change issue, numerous initiatives in the EU are pending or currently being revised, including:

 

   

A 2003 Directive implementing the Kyoto Protocol within the EU established an emissions trading

 

 

57


Table of Contents
   

scheme effective as of January 2005 for greenhouse gas (“GHG”) emissions quotas. On the basis of this directive, carbon dioxide emissions permits are then delivered. This trading scheme required Member States to prepare, under the supervision of the EU Commission, national allocation plans identifying a global amount of quotas to be shared and delivered for free by the governments to each industrial installation for specific sectors, in particular the energy intensive installations that have to surrender quotas with respect to their annually verified carbon dioxide emissions. In accordance with the 2009 revision of the aforementioned directive, a progressive quota auctioning mechanism is scheduled to be set up in 2013 together with transitional Community-wide rules for harmonized free allocation up to a level based on benchmarks for sectors exposed to international carbon leakage. These changes will end the free allocations for electricity production and have an expanded scope covering additional commercial sectors and emissions. When this system is established, TOTAL’s industrial facilities may incur capital and operating costs to comply with such legislation including the partial acquisition of emissions allowances.

   

The first period of the Kyoto Protocol is reaching an end in 2012. The Cancun UN conference at the end of 2010 reaffirmed the principles of Kyoto, but did not result in the adoption of any new legally binding agreement with respect to the continuation of the Kyoto Protocol. The Durban conference of November 2011 resulted in the Kyoto principles being extended post-2012 to permit the possible adoption by 2015 of another legally-binding international agreement to be signed by the negotiating countries as well as by the United States together with China, India and certain other developing nations.

   

The Climate Action and Renewable Energy Package imposes an EU objective referred to as “3 x 20”, which commits EU Member States by 2020 to reduce overall GHG emissions to at least 20% below 1990 levels, to improve energy efficiency by 20% and to increase renewable energy usage by 20%. In 2011, the European Commission published its “Roadmap for moving to a competitive low-carbon economy in 2050” to look beyond these 2020 objectives and to set out a plan to meet the long-term target of reducing domestic emissions by 80 to 95% by mid-century. The sectors most responsible for emissions in the

   

EU (i.e., power generation, industry, transport, buildings and construction, as well as agriculture) are charged with making the transition to a low-carbon economy over the coming decades and these issues could affect TOTAL’s operations in the future.

   

The 2009 Directive on Carbon Capture and Storage (CCS) was transposed in France in 2010. This legal framework forms the basis for developing CCS projects that are expected to serve as one of the most valuable solutions for the reduction of carbon dioxide emissions. Such regulations will have technical and financial impacts, including on TOTAL’s projects.

With respect to biodiversity issues, this subject is increasingly taken into consideration. Following the 2010 Nagoya summit, the UN’s 65th General Assembly decided to form the IPBES (Intergovernmental Science-Policy Platform on Biodiversity) to share knowledge and future policies on biodiversity and ecosystem services. The next UN Conference on Sustainable Development (“Rio +20”) is expected to be held in Rio in June 2012 and will focus on two themes: a green economy in the context of sustainable development and poverty eradication, and the institutional framework for sustainable development.

In the United States, where TOTAL’s operations are less extensive than in Europe, TOTAL is also subject to significant HSE regulations at both the state and federal levels. Of particular relevance to TOTAL’s lines of business are:

 

 

The Clean Air Act and its regulations, which require, among other measures: stricter phased-in fuel specifications and sulfur reductions; enhanced emissions controls and monitoring at major sources of volatile organic compounds, nitrogen oxides, and other designated hazardous and non-hazardous air pollutants; GHG regulation; stringent pollutant emission limits; construction and operating permits for major air emission sources at chemical plants, refineries, marine and distribution terminals and other facilities; and risk management plans for the handling and storage of hazardous substances.

 

The Clean Water Act, which regulates the discharge of wastewater and other pollutants from both onshore and offshore operations and, among other measures, requires industrial facilities to obtain permits for most wastewater and surface water discharges, install control equipment and treatment systems, implement operational controls, and preventative measures, including spill prevention and control plans and practices to control storm water runoff.

 

 

58


Table of Contents
 

The Resource Conservation and Recovery Act, which regulates the generation, storage, handling, treatment, transportation and disposal of hazardous waste and imposes corrective action requirements on regulated facilities requiring investigation and remediation of potentially contaminated areas at these facilities.

 

The Comprehensive Environmental Response, Compensation, and Liability Act (also known as CERCLA or Superfund), under which waste generators, former and current site owners and operators, and certain other parties can be held jointly and severally liable for the entire cost of remediating active, abandoned or non-operating sites contaminated by releases of hazardous substances regardless of fault or the amount or share of hazardous substances sent by a party to a site. The U.S. Environmental Protection Agency (“EPA”) has authority under Superfund to order responsible parties to clean up contaminated sites and may seek recovery of the government’s response costs from responsible parties. States have similar legal authority to compel site investigations and cleanups and to recover costs from responsible parties. The U.S. government and states may also sue responsible parties under CERCLA for damage to natural resources (e.g., rivers and wetlands) arising from contamination.

 

National and international maritime oil spill laws, regulations and conventions, including the Oil Pollution Act of 1990, impose significant oil spill prevention requirements, spill response planning and training obligations, ship design requirements (including phased in double hull requirements for tankers), operational restrictions, spill liability for tankers and barges transporting oil, offshore oil platform facilities and onshore terminals and establishes an oil liability spill fund paid for by taxes on imported and domestic oil.

 

In the wake of the Deepwater Horizon accident, the Bureau of Ocean Energy Management, Regulation and Enforcement was replaced by the Bureau of Ocean Energy Management, which is responsible for managing development of offshore resources, and the Bureau of Safety and Environmental Enforcement (“BSEE”), which is responsible for safety and environmental oversight of offshore oil and gas operations. The BSEE has implemented more stringent permitting requirements and oversight of offshore drilling. Among other changes, well design, casing and cementing standards have been upgraded and compliance must be certified by a professional engineer. In addition, plans must describe containment resources available in case of an underwater blowout

   

and worst case discharge, and operators in the Gulf of Mexico are required to develop and implement a Safety and Environmental Management Systems program.

 

Other significant U.S. environmental legislation includes the Toxic Substances Control Act, which regulates the development, testing, import, export and introduction of new chemical products into commerce, and the Emergency Planning and Community Right-to-Know Act, which requires emergency planning and spill notification as well as public disclosure of chemical usage and emissions.

TOTAL’s facilities in the United States are also subject to extensive workplace safety regulations promulgated by the Occupational Safety and Health Administration (“OSHA”). Most notable among OSHA regulations is the Process Safety Management of Highly Hazardous Chemicals, a comprehensive regulatory program that requires major industrial sources, including petroleum refineries and chemical manufacturing facilities, to undertake significant hazard assessments during the design of new industrial processes and modifications to existing processes, as well as a comprehensive and continual monitoring and management process for these chemicals.

The EPA’s regulation of GHG emissions from industrial sources under the Clean Air Act’s Prevention of Significant Deterioration and Title V operating permit programs formally commenced on January 2, 2011. The authority to regulate GHG emissions under the Clean Air Act is the culmination of several EPA rulemakings promulgated in 2009 and 2010 as a result of the 2007 U.S. Supreme Court decision in Massachusetts v. EPA confirming the authority of EPA to regulate GHG emissions under the Clean Air Act. Each of these rulemakings is under legal challenge. The EPA may issue future regulations requiring additional industry sectors to report GHG emissions and has indicated its intention to phase in GHG permitting for smaller industrial sources. Various state and regional requirements also govern GHG emissions and additional measures can be expected in the future. Depending upon the outcome of legal challenges and the content of future GHG regulations, TOTAL subsidiaries in the United States may incur additional capital and operating costs to comply with control technology and/or facility upgrade requirements for reducing GHG emissions.

TOTAL has investments in the United States in unconventional gas plays that utilize hydraulic fracturing, or “fracking,” a process that involves pumping a mixture of water, sand and chemicals underground at high pressure to fracture rock formations and release natural gas and

 

 

59


Table of Contents

liquids that are otherwise inaccessible. Currently, regulation of these practices occurs at the state level, although there are a number of federal legislative proposals that could alter the regulatory framework. In addition, various state initiatives could result in stricter regulation of fracking. Increased regulation could affect TOTAL’s operating costs, profitability and future investments in these unconventional gas plays.

Proceedings instituted by governmental authorities are pending or known to be contemplated against certain U.S.-based subsidiaries of TOTAL under applicable environmental laws that could result in monetary sanctions in excess of $100,000. No individual proceeding is, nor are the proceedings as a whole, expected to have a material adverse effect on TOTAL’s consolidated financial position or profitability.

Management and monitoring of industrial and environmental risks

TOTAL policies regarding health, safety and the environment

TOTAL has developed a “Health Safety Environment Quality Charter” which sets out the basic principles applicable within the Group regarding the protection of people, property and the environment. This charter is rolled out at several levels within the Group by means of management systems.

Along these lines, TOTAL has developed efficient organizations as well as safety, environmental and quality management systems, which it makes every effort to have certified or assessed (standards such as the International Safety Rating System, ISO 14001 and ISO 9001). For example, in 2010, TOTAL received ISO 9001 certification for “development and management of the database of technical businesses” in exploration and production.

Assessment

As part of its policy, TOTAL systematically assesses risks and impacts in the areas of industrial safety (particularly technological risks), the environment and the protection of workers and local residents:

 

 

prior to approving new projects, investments, acquisitions and disposals;

 

 

periodically during operations (safety studies, environmental impact studies, health impact studies and risk prevention plan in France as part of the 2003 legislation on the prevention of major technological risks);

 

 

prior to introducing new substances to the market (toxicological and ecotoxicological studies and life cycle analyses); and

 

based on the regulatory requirements of the countries where these activities are carried out and generally accepted standards.

In countries where prior administrative authorization and supervision is required, projects are not undertaken without the authorization of the relevant authorities and are developed according to the studies provided to the authorities.

In particular, TOTAL has developed common methodologies for analyzing technological risks which must gradually be applied to all activities carried out by the Group’s companies.

Management

TOTAL develops risk management measures based on risk and impact assessments. These measures involve facility and structure design, the reinforcement of safety devices and remedies of environmental degradations.

In addition to developing organizations and management systems as described above, TOTAL strives to minimize industrial and environmental risks inherent in its operations by conducting thorough inspections and audits, training personnel and raising awareness among all those involved, and implementing an active investment policy.

In addition, performance indicators (in the areas of HSE) and risk monitoring have been put in place, objectives have been set and action plans have been implemented to achieve these objectives.

Although the emphasis is on preventing risks, TOTAL takes regular steps to prepare for crisis management based on the risk scenarios identified.

In particular, TOTAL has developed emergency plans and procedures to respond to an oil spill or leak. These plans and procedures are specific to each TOTAL affiliate and adapted to its organization, activities and environment, and are consistent with the Group plan. They are reviewed regularly and tested through exercises.

At the Group level, TOTAL has set up the alert scheme PARAPOL (Plan to Mobilize Resources Against Pollution) to facilitate crisis management and provide assistance by mobilizing both internal and external resources in the event of pollution of marine, coastal or inland waters, without geographical restriction. The PARAPOL procedure is made available to TOTAL affiliates and its main goal is to facilitate access to internal experts and physical response resources.

Furthermore, TOTAL and its affiliates are currently members of certain oil spill cooperatives that are able to provide expertise, resources and equipment in all

 

 

60


Table of Contents

geographic areas where TOTAL has operations, including in particular Oil Spill Response, CEDRE (Center of documentation, research and experimentation on accidental water pollution) and Clean Caribbean and Americas.

Following the blow-out on the Macondo well in the Gulf of Mexico in 2010 (concerning which the Group was not involved), TOTAL created three Task Forces in order to analyze risks and provide recommendations.

In Exploration & Production, Task Force No. 1 reviewed the safety aspects of deep offshore drilling operations (wells architecture, design of blow-out preventers, training of personnel based on lessons learned from the serious accidents that occurred recently in the industry). Its efforts have led to the implementation of even more stringent controls and audits on drilling operations.

Task Force No. 2, coordinated with the Global Industry Response Group (GIRG) created by the OGP (International Association of Oil and Gas Producers), is studying deep offshore oil capture and containment operations in case of a pollution event in deep waters. In the short term, capture devices will be available in several regions of the world where TOTAL has a strong presence in exploration-production (North Sea, Gulf of Guinea).

Task Force No. 3 related to plans to fight accidental spills in order to strengthen the Group’s ability to respond to a major accidental pollution, such as a blow out or a total loss of containment from an FPSO (Floating Production, Storage and Offloading facility). This initiative has led, in particular, to a sharp increase in the volume of dispersants available within the Group.

The Group believes that it is impossible to guarantee that the contingencies or liabilities related to the above mentioned health, safety and environmental concerns will not have a material impact on its business, assets and liabilities, consolidated financial situation, cash flow or income in the future.

Oil and gas exploration and production operations

Oil and gas exploration and production require high levels of investment and are associated with particular risks and opportunities. These activities are subject to risks related specifically to the difficulties of exploring underground, the characteristics of hydrocarbons and the physical characteristics of an oil or gas field. Of risks related to oil and gas exploration, geologic risks are the most important. For example, exploratory wells may not result in the discovery of hydrocarbons, or may result in amounts that

would be insufficient to allow for economic development. Even if an economic analysis of estimated hydrocarbon reserves justifies the development of a discovery, the reserves can prove lower than the estimates during the production process, thus adversely affecting the economic development.

Almost all the exploration and production operations of TOTAL are accompanied by a high level of risk of loss of the invested capital due to the risks related to economic or political factors detailed hereafter. It is impossible to guarantee that new resources of crude oil or of natural gas will be discovered in sufficient amounts to replace the reserves currently being developed, produced and sold to enable TOTAL to recover the capital it has invested.

The development of oil and gas fields, the construction of facilities and the drilling of production or injection wells require advanced technology in order to extract and exploit fossil fuels with complex properties over several decades. The deployment of this technology in such a difficult environment makes cost projections uncertain. TOTAL’s operations can be limited, delayed or canceled as a result of a number of factors, including administrative delays, in particular as part of the host states’ approval processes for development projects, shortages, late delivery of equipment and weather conditions, including the risk of hurricanes in the Gulf of Mexico. Some of these risks may also affect TOTAL’s projects and facilities further down the oil and gas chain.

Economic or political factors

The oil sector is subject to domestic regulations and the intervention of governments, directly or through state-owned companies, in such areas as:

 

 

the award of exploration and production interests;

 

authorizations by governments or by a state-controlled partner, in particular for development projects, annual programs or the selection of contractors or suppliers;

 

the imposition of specific drilling obligations;

 

environmental protection controls;

 

control over the development, exploitation and abandonment of a field causing restrictions on production;

 

calculating the costs that may be recovered from the relevant authority and what expenditures are deductible from taxes;

 

cases of expropriation, nationalization or reconsideration of contractual rights.

The oil industry is also subject to the payment of royalties and taxes, which may be higher than those applicable to other commercial businesses and which may be subject to material changes by the governments of certain countries.

 

 

 

61


Table of Contents

Substantial portions of TOTAL’s oil and gas reserves are located in certain countries that may be considered as politically and economically unstable. Such oil and gas reserves and related operations are subject to certain additional risks, including:

 

 

the implementation of production and export quotas;

 

the compulsory renegotiation of contracts;

 

the expropriation or nationalization of assets;

 

risks related to changes of local governments or the resulting changes in business customs and practices;

 

payment delays;

 

currency exchange restrictions;

 

depreciation of assets due to the devaluation of local currencies or other measures taken by governments that might have a significant impact on the value of activities; and

 

losses and decreased activity due to armed conflicts, civil unrest, the actions of terrorist groups or sanctions that target activities or parties of certain countries.

TOTAL, like other major international oil companies, has a geographically diverse portfolio of reserves and operational sites, which allows it to conduct its business and financial affairs so as to reduce its exposure to such political and economic risks. However, there can be no assurance that such events will not adversely affect the Group.

Business Activities in Cuba, Iran, Sudan and Syria

Provided in this section is certain information relating to TOTAL’s activities in Cuba, Iran, Sudan and Syria.

For more information on U.S. and EU restrictions relevant to our activities in these jurisdictions, see “Item 3. Key Information — Risk Factors”.

Cuba

In 2011, TOTAL’s Refining & Marketing division had limited marketing activities for the sale of specialty products to non-state entities in Cuba and paid taxes on such activities. In addition, TOTAL’s Trading & Shipping division purchased hydrocarbons pursuant to spot contracts from a state-controlled entity for approximately 40 million.

Iran

TOTAL’s Exploration & Production division historically had been active in Iran through buyback contracts. Under such contracts, the contractor is responsible for and finances development operations. Once development is completed, operations are handed over to the national oil company, which then operates the field. The contractor receives payments in cash or in kind to recover its expenditures as

well as a remuneration based on the field’s performance. Furthermore, upon the national oil company’s request, a technical services agreement may be implemented in conjunction with a buyback contract to provide qualified personnel and services until full repayment of all amounts due to the contractor.

TOTAL entered into such buyback contracts between 1995 and 1999 with respect to the development of four fields: Sirri, South Pars 2 & 3, Balal and Dorood. For all of these contracts, development operations have been completed and TOTAL retains no operational responsibilities. A technical services agreement for the Dorood field expired in December 2010. As TOTAL is no longer involved in the operation of these fields, TOTAL has no information on the production from these fields. Some payments are yet to be reimbursed to TOTAL with respect to South Pars 2 & 3, Balal and Dorood. Since 2011, TOTAL has no production in Iran corresponding to such payments in kind, compared to 2 kboe/d in 2010 and 8 kboe/d in 2009. No royalties or fees are paid by the Group in connection with these buyback and service contracts. In 2011, TOTAL made non-material payments to the Iranian administration with respect to certain taxes and social security.

With respect to TOTAL’s Refining & Marketing division’s 2011 activities in Iran, Beh Total, a company held 50/50 by Behran Oil and Total Outre-Mer, a subsidiary of the Group, produced and marketed small quantities of lubricants (20,000 tons) for sale to domestic consumers in Iran. In 2011, revenue generated from Beh Total’s activities was 43.5 million and cash flow was 4.6 million. Beh Total paid approximately 1 million in taxes. TOTAL does not own or operate any refineries or chemicals plants in Iran. In 2011, Beh Total paid 5.6 million of dividends for fiscal year 2010 (share of TOTAL: 2.3 million).

In 2011, TOTAL’s Trading & Shipping division purchased in Iran pursuant to a mix of spot and term contracts approximately forty-nine million barrels of hydrocarbons from state-controlled entities for approximately 3.7 billion. Prior to January 23, 2012, TOTAL’s Trading & Shipping division ceased its purchase of Iranian hydrocarbons.

Sudan

Since the independence of the Republic of South Sudan on July 9, 2011, TOTAL is not present in Sudan. TOTAL holds an interest in Block B in what was, prior to July 9, 2011, the southern region of Sudan.

TOTAL disbursed in Sudan between January 1, 2011 and July 8, 2011, approximately $0.7 million as scholarships and social development contributions, as well as contributions to the construction of social infrastructure,

 

 

62


Table of Contents

schools and water wells along with non-governmental organizations and other stakeholders involved in southern Sudan.

For more information on TOTAL’s activities in the Republic of South Sudan, see “Item 4. Business Overview — Republic of South Sudan”.

Syria

In 2011, TOTAL had two contracts relating to oil and gas exploration & production activities: a Production Sharing Agreement entered into in 1988 (“PSA 1988”) for an initial period of twenty years and renewed at the end of 2008 for an additional 10-year period, and the Tabiyeh Gas Project risked Service Contract (the “Tabiyeh contract”) effective from the end of October 2009. TOTAL owns 100% of the rights and obligations under PSA 1988, and operated until early December 2011 on various oil fields in the Deir Ez Zor area through a dedicated non-profit operating company owned equally by the Group and the state-owned General Petroleum Corporation (“GPC”) (the successor to the Syrian Petroleum Company).

The main terms of PSA 1988 are similar to those normally used in the oil and gas industry. The Group’s revenues derived from PSA 1988 are made up of a combination of “cost oil” and “profit oil”. “Cost oil” represents the reimbursement of operating and capital expenditures and is accounted for in accordance with normal industry practices. The Group’s share of “profit oil” depends on the total annual production level. TOTAL receives its revenues in cash payments made by GPC. TOTAL pays to the state-owned Syrian company SCOT a transportation fee equal to $2/b for the oil produced in the area, as well as non-material payments to the Syrian government related to PSA 1988 for such items as withholding taxes and Syrian social security.

The Tabiyeh contract, signed with GPC, may be considered as an addition to PSA 1988 as production, costs and revenues for the oil and part of the condensates coming from the Tabiyeh field are governed by the contractual terms of PSA 1988. This project is designed to enhance liquids and gas output from the Tabiyeh field through the drilling of “commingled” wells and through process modifications in Deir Ez Zor Gas Plant operated by the Syrian Gas Company. Until early December 2011, TOTAL financed and implemented the Tabiyeh Gas Project and operated the Tabiyeh field.

In 2011, technical production for PSA 1988 and the Tabiyeh contract taken together amounted to 63 kboe/d, of which 53 kboe/d were accounted for as the Group’s

share of production. The amount identified as technical production under the agreements, minus the amount accounted for as the Group’s share of production, does not constitute the total economic benefit accruing to Syria under the terms of the agreements since Syria retains a margin on a portion of the Group’s production and receives certain production taxes.

In addition, TOTAL and GPC entered into a Cooperation Framework Agreement in 2009, which provides for the co-development of oil projects in Syria.

Since early December 2011, TOTAL has ceased its activities that contribute to oil and gas production in Syria.

In 2011, TOTAL’s Trading & Shipping division purchased in Syria pursuant to a mix of spot and term contracts nearly eleven million barrels of hydrocarbons from state-controlled entities for approximately 824 million. Since early September 2011, the Group has ceased to purchase hydrocarbons from Syria.

Competition

TOTAL is subject to competition from other oil companies in the acquisition of assets and licenses for the exploration and production of oil and natural gas as well as for the sale of manufactured products based on crude and refined oil. TOTAL’s competitors are comprised of national oil companies and international oil companies.

In this regard, the major international oil companies in competition with TOTAL are ExxonMobil, Royal Dutch Shell, Chevron and BP. As of December 31, 2011, TOTAL ranked fifth among these companies in terms of market capitalization.(1)

Insurance and risk management

Organization

TOTAL has its own insurance and reinsurance company, Omnium Insurance and Reinsurance Company (OIRC). OIRC is integrated with the Group’s insurance management and is used as a centralized global operations tool for covering the Group’s risks. It allows the Group’s worldwide insurance program to be implemented in compliance with the specific requirements of local regulations applicable in the countries where the Group operates.

Some countries may require the purchase of insurance from a local insurance company. If the local insurer accepts to cover the subsidiary of the Group in compliance with its worldwide insurance program, OIRC requests a retrocession of the covered risks from the local insurer. As

 

 

 

(1) Source: Reuters.

 

63


Table of Contents

a result, OIRC negotiates reinsurance contracts with the subsidiaries’ local insurance companies, which transfer most of the risk to OIRC. When a local insurer covers the risks at a lower level than that defined by the Group, OIRC provides additional coverage so as to standardize coverage throughout the Group.

At the same time, OIRC negotiates a reinsurance program at the Group level with mutual insurance companies for the oil industry and commercial reinsurers. OIRC permits the Group to better manage price variations in the insurance market by taking on a greater or lesser amount of risk corresponding to the price trends in the insurance market.

In 2011, the net amount of risk retained by OIRC after reinsurance was a maximum of $75 million per third-party liability insurance claim and $75 million per property damage and/or business interruption insurance claim. Accordingly, in the event of any loss giving rise to an aggregate insurance claim, the effect on OIRC would be limited to its maximum retention of $150 million per event.

Risk and insurance management policy

In this context, the Group risk and insurance management policy is to work with the relevant internal department of each subsidiary to:

 

 

define scenarios of major disaster risks (estimated maximum loss);

 

assess the potential financial impact on the Group should a catastrophic event occur;

 

help to implement measures to limit the probability that a catastrophic event occurs and the financial consequences if such event should occur; and

 

manage the level of risk from such events to be either covered internally by the Group or transferred to the insurance market.

Insurance policy

The Group has worldwide third-party liability and property insurance coverage for all its subsidiaries. These programs are contracted with first-class insurers (or reinsurers and mutual insurance companies of the oil industry through OIRC).

The amounts insured depend on the financial risks defined in the disaster scenarios and the coverage terms offered by the market (available capacities and price conditions).

More specifically for:

 

 

Third-party liability insurance: since the maximum financial risk cannot be evaluated by a systematic approach, the amounts insured are based on market conditions and industry practice, in particular, the oil industry. In 2011, the Group’s third-party liability

   

insurance for any liability (including potential accidental environmental liabilities) was capped at $850 million.

 

Property damage and business interruption: the amounts insured vary by sector and by site and are based on the estimated cost of and reconstruction under maximum loss scenarios and on insurance market conditions. The Group subscribed for business interruption coverage in 2011 for its main refining and petrochemical sites.

For example, for the Group’s highest risks (platforms in the North Sea and main refineries and petrochemical plants in Europe), in 2011 the Group’s share of insurance limit was approximately $1.65 billion for the Downstream segment and approximately $1.5 billion dollars for the Upstream segment.

Deductibles for property damage and third-party liability fluctuate between 0.1 million and 10 million depending on the level of risk and liability, and are borne by the relevant subsidiary. For business interruption, coverage begins sixty days after the event giving rise to the interruption.

Other insurance contracts are bought by the Group in addition to property damage and third-party liability coverage, mainly for car fleets, credit insurance and employee benefits. These risks are entirely underwritten by outside insurance companies.

The above-described policy is given as an example of past practice over a certain period of time and cannot be considered as representative of future conditions. The Group’s insurance policy may be changed at any time depending on the market conditions, specific circumstances and on management’s assessment of the risks incurred and the adequacy of their coverage.

While TOTAL believes its insurance coverage is in line with industry practice and sufficient to cover normal risks in its operations, it is not insured against all possible risks. In the event of a major environmental disaster, for example, TOTAL’s liability may exceed the maximum coverage provided by its third-party liability insurance. The loss TOTAL could suffer in the event of such disaster would depend on all the facts and circumstances and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster. The Group cannot guarantee that it will not suffer any uninsured loss and there can be no guarantee, particularly in the case of a major environmental disaster or industrial accident, that such loss would not have a material adverse effect on the Group.

 

 

64


Table of Contents

Competition law

Competition laws apply to the Group’s companies in the vast majority of countries in which it does business. Violations of competition laws carry fines and expose the Group and its employees to criminal sanctions and civil suits. Furthermore, it is now common for persons or corporations allegedly injured by violations of competition laws to sue for damages.

The broad range of activities and countries in which the Group operates requires local analysis, by business segment, of the legal risks in terms of competition law. Some of the Group’s business segments have already been implementing competition law conformity plans for a long time. Moreover, a Group-wide policy designed to coordinate risk management measures and competition law conformity plans has been under development since the beginning of 2012.

Organizational Structure

TOTAL S.A. is the parent company of the TOTAL Group. As of December 31, 2011, there were 870 consolidated subsidiaries, of which 783 were fully consolidated and 87 were accounted for under the equity method. For a list of the principal subsidiaries of the Company, see Note 35 to the Consolidated Financial Statements.

Property, Plants and Equipment

TOTAL has freehold and leasehold interests in numerous countries throughout the world, none of which is material to TOTAL. See “— Business Overview — Upstream” for a description of TOTAL’s reserves and sources of oil and gas.

 

 

ITEM 4A. UNRESOLVED STAFF COMMENTS

None.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

 

This section is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Consolidated Financial Statements included elsewhere in this Annual Report. The Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the IASB and IFRS as adopted by the European Union.

This section contains forward-looking statements which are subject to risks and uncertainties. For a list of important factors that could cause actual results to differ materially from those expressed in the forward-looking statements, see “Cautionary Statement Concerning Forward-Looking Statements” on page vi.

 

 

OVERVIEW

 

 

TOTAL’s results are affected by a variety of factors, including changes in crude oil and natural gas prices as well as refining and marketing margins, which are all generally expressed in dollars, and changes in exchange rates, particularly the value of the euro compared to the dollar. Higher crude oil and natural gas prices generally have a positive effect on the income of TOTAL, since its Upstream oil and gas business benefits from the resulting increase in revenues realized from production. Lower crude oil and natural gas prices generally have a corresponding negative effect. The effect of changes in crude oil prices on TOTAL’s Downstream activities depends upon the speed at which the prices of refined petroleum products adjust to reflect such changes. In the past several years, crude oil and natural gas prices have varied greatly. As TOTAL reports its results in euros, but conducts its operations mainly in dollars, the effect of an

increase in crude oil and natural gas prices is partly offset by the effect of the variation in exchange rates during periods of weakening of the dollar relative to the euro and strengthened during periods of strengthening of the dollar relative to the euro. TOTAL’s results are also significantly affected by the costs of its activities, in particular those related to exploration and production, and by the outcome of its strategic decisions with respect to cost reduction efforts. TOTAL’s results are also affected by general economic and political conditions and changes in governmental laws and regulations, as well as by the impact of decisions by OPEC on production levels. However, the Euro zone’s turbulences during the fiscal year 2011 did not affect the Group significantly. For more information, see “Item 3. Key Information — Risk Factors” and “Item 4. Information on the Company — Other Matters”.

 

 

65


Table of Contents

The year 2011 witnessed a number of geopolitical events that put pressure on market supplies. Despite the economic slowdown, demand for oil products continued to rise, fuelled by the growth of emerging markets. Pressure on supply, plus rising demand, resulted in a sharp increase in the price of crude oil. The average price of Brent in 2011 was $111/b, compared with $80/b in 2010.

Gas spot prices continued to rise in Europe and Asia in 2011, mainly due to increased demand on Asian markets. Spot prices for gas in the United States remained very low, due to the continued rise in production, driven by the development of non-conventional gases.

Despite the gradual adjustment of refining capacity, the overcapacity that has existed in the European refining market since 2009 continued into 2011, due to low demand in Europe. Refining margins dropped to an average of $17/t in 2011, compared with $27/t in 2010(1). In the first half of 2011, the Chemicals segment enjoyed a globally favorable environment, which has deteriorated since then. In the second half of the year, the Base Chemicals and Specialty Chemicals divisions saw their margins shrink due to the drop in demand caused by the economic slowdown.

In this environment, TOTAL’s net income (Group share) amounted to 12.3 billion, up 16% compared to 10.6 billion in 2010. This result essentially reflects a better Upstream environment, while the Downstream and Chemicals segments were faced with more difficult conditions than in 2010. The Upstream segment’s 2011 adjusted net operating income of 10.4 billion was up 21% compared with 8.6 billion in 2010 due to rising prices, but was also negatively impacted by the -$ exchange rate. The Downstream segment’s adjusted net operating income dropped by 7% to 1.1 billion in 2011 compared to 1.2 billion in 2010. This result can be explained in particular by the impact of reduced refining margins and the sale of the Group’s stake in CEPSA, which were partially offset by an improvement in operational performance. The Chemicals segment’s adjusted net operating income dropped by 10% to 775 million in 2011 from 857 million in 2010, due to the more difficult market environment at the end of the year and the asset sales in 2011 (resins, CEPSA).

The year 2011 saw numerous acquisitions and asset sales, reflecting the Group’s ambition to optimize its portfolio by creating value from certain mature assets and by developing its Upstream assets with high potential for growth.

TOTAL benefited from the rise in its operational cash flow and the 8 billion inflows from asset sales in 2011 to fund the increase in its investment program, while maintaining a dividend of 2.28 per share, which will be submitted for approval to the Shareholders’ meeting on May 11, 2012. The balance sheet remained strong, with a net-debt-to- equity ratio(2) of 23% at the end of 2011, compared with 22% at the end of 2010.

In terms of operations, 2011 saw the continued improvement of safety performance, with a 15% drop in the Group-wide TRIR(3) compared with 2010.

In the Upstream segment, three major discoveries in Azerbaijan, Bolivia and French Guiana were the first results of the Group’s bolder exploration strategy. The year 2011 also witnessed the successful start-up of the Pazflor deep-offshore platform in Angolan waters, a project operated by TOTAL that illustrates the Group’s expertise in the development of major projects. Five new major projects, including the Ichthys LNG project in Australia (TOTAL, 24%), were also launched, in order to secure growth in the years to come.

Still in the Upstream segment, 2011 also saw the announcement of the acquisition of a 14.09% stake in the Russian company Novatek and an increase of the Group’s stakes in the Fort Hills project in Canada and in Tempa Rossa in Italy. At the end of 2011, the Group announced its entry into the Utica shale gas and condensates deposit in the United States. The Group continued to extend its oil and gas acreage by acquiring stakes in promising exploration areas, such as the pre-salt blocks in the Kwanza basin in Angola, and by acquiring stakes in deposits that have already been discovered, such as the Yamal LNG project in Russia.

At the same time, in 2011, TOTAL disposed of certain mature or non-strategic Upstream assets, including its exploration-production subsidiary in Cameroon and its stakes in pipelines in Colombia.

In the realm of new energies, TOTAL acquired in 2011 a 60% stake (now, 66%) in the U.S. company SunPower, to become one of the leaders in the solar industry. Although currently in the consolidation phase, this industry offers opportunities for strong growth.

In the Downstream and Chemicals segments, TOTAL deployed its strategy of increasing the competitive performance of its activities, scaling down its exposure to mature zones, mainly Europe, and bolstering its presence

 

 

 

(1) Based on TOTAL’s “European Refining Margin Indicator” (ERMI).
(2) Net-debt-to-equity ratio = net debt (i.e., the sum of current borrowings, other current financial liabilities and non-current financial debt, net of current financial assets, hedging instruments on non-current financial debt and cash and cash equivalents) divided by the sum of shareholders’ equity and non-controlling interests after expected dividends payable.
(3) Total Recordable Injury Rate.

 

66


Table of Contents

in high-growth areas. Consequently, 2011 saw the start-up of the deep-conversion unit (or coker) in Port Arthur in the United States, the continued modernization of the refinery and the petrochemicals platform in Normandy, France, and the construction of the Jubail refinery in Saudi Arabia. The Group also continued to scale down its refining capacity in Europe, by selling off its stake in the Spanish company CEPSA.

On the Marketing front, in 2011, the Group continued its optimization drive by selling off its distribution activities in the United Kingdom and launching a program to modernize part of its service station network in France with the Total access program. In the Specialty Chemicals division, the Group sold part of its Resins activity.

A restructuring of the Downstream and Chemicals sectors was announced in October 2011. The deployment of this project led to organizational changes on January 1, 2012, with the creation of:

 

 

a Refining & Chemicals segment, a large industrial base that encompasses refining, petrochemicals, fertilizers and specialty chemicals operations. This segment also includes oil trading and shipping activities.

 

a Supply & Marketing segment, which is dedicated to worldwide supply and marketing activities in the oil products field.

The process initiated in 2004 to increase R&D budgets continued with expenditures in 2011 of 776 million, up 9% compared to 2010, with the aim of, in particular, the continued improvement of the Group’s technological expertise in the development of oil and gas resources and the development of solar, biomass, carbon capture and storage technologies in order to contribute to changes in the global energy mix.

Finally, in 2011, TOTAL reasserted the priority on safety and the environment as part of its operations throughout its business. For all of its projects conducted in a large number of countries, the Group puts an emphasis on corporate social responsibility (CSR) challenges and the development of the local economies.

Outlook

In 2012, TOTAL intends to consolidate its drivers for growth and enhance the priority given to safety, reliability and acceptability of its operations.

The 2012 net investment budget is $20 billion (approximately 14.3 billion(1)). TOTAL intends to continue

to actively manage its asset portfolio with, in particular, a program of non-strategic asset sales. The 2012 budget for organic investments (i.e., net investments excluding acquisitions and asset sales) is $24 billion (approximately 17.1 billion).

Capital expenditures will mostly be focused on the Upstream segment with an allocation of $20 billion (approximately 14.3 billion), or more than 80% of the Group’s organic capital expenditure budget. About 30% of the investment in the Upstream segment is expected to be dedicated to producing assets while 70% is expected to be assigned to developing new projects. Downstream organic capital expenditures in the Refining & Chemicals and Supply & Marketing segments are expected to amount to $3 billion (approximately 2.1 billion) and $1 billion (approximately 714 million), respectively, in 2012. In line with the strategy to develop a number of major integrated platforms in order to stimulate growth and improve competitive performance, the main projects in the Refining & Chemicals segment in 2012 will be the upgrading of the Normandy refinery and petrochemical plant, the building of the Jubail refinery in Saudi Arabia and the expansion of the Daesan platform in South Korea. Wherever it operates, TOTAL will continue to make capital expenditure in the maintenance and safety of its facilities a top priority.

The Group also confirms its commitment with respect to R&D with a budget increasing to about $1.2 billion (approximately 857 million) in 2012.

In the Upstream segment, TOTAL will deploy its strategy intended to speed up growth of its production, while improving the profitability of its portfolio of assets. The year 2012 should see the launch of numerous projects. In 2012, TOTAL plans to bring eight new major projects on-stream, which will contribute to expected growth in output in 2012 and achieving the target rate of average annual production growth of 2.5% between 2010 and 2015: Usan and OML 58 Upgrade in Nigeria, Islay in the UK North Sea, Angola LNG in Angola, Bongkot South in Thailand, Halfaya in Iraq, Sulige in China and Kashagan in Kazakhstan. The Group will also continue to evaluate numerous other projects, in particular in Western Africa, Russia and Canada. The anticipated launch of these projects during the course of the next two years should improve visibility on growth in output after 2015. With an exploration budget that stands at $2.5 billion (approximately 1.8 billion), up 20% compared to 2011, the Group will continue to pursue an ambitious and diversified strategy.

 

 

 

(1) All euro figures in this section converted at a rate of $1.40/.

 

67


Table of Contents

In the Downstream sector, with a new organization that will allow it to take up the challenges specific to each activity of that sector, the Group should start to reap the first benefits of an integrated Refining & Chemicals segment and Supply & Marketing segment, each of which is closer to its markets. TOTAL will strive to improve its competitiveness by adapting its activities in Europe and seeking to enhance its operational efficiency and synergies between its operations. The year 2012 will see continued development in high-growth zones, with the expected start-up of a new polyethylene production unit in Qatar and the completion

of the first step of the expansion of its Daesan platform in South Korea.

In 2012, TOTAL can rely on its solid balance sheet and on the start-up and ramp-up of new projects that should contribute to the growth of operating cash flow. Moreover, in 2012, TOTAL will continue to develop its new projects through an ambitious capital expenditure program, while maintaining a target for the net-debt-to-equity ratio of between 20-30% and a dividend policy based on an average pay-out ratio of 50% of adjusted fully-diluted earnings per share(1).

 

 

CRITICAL ACCOUNTING POLICIES

 

 

A summary of the Group’s accounting policies is included in Note 1 to the Consolidated Financial Statements. Management believes that the application of these policies on a consistent basis enables the Group to report useful and reliable information about the Group’s financial condition and results of operations.

The Company has changed its method for reserve estimates due to the adoption of the Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosures, effective for annual reporting periods ended on or after December 31, 2009.

The preparation of financial statements in accordance with IFRS requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of preparation of the financial statements and reported income and expenses for the period. Management reviews these estimates and assumptions on an ongoing basis, by reference to past experience and various other factors considered as reasonable which form the basis for assessing the book value of assets and liabilities. Actual results may differ significantly from these estimates, if different assumptions or circumstances apply.

Lastly, where the accounting treatment of a specific transaction is not addressed by any accounting standards or interpretation, management applies its judgment to define and apply accounting policies that will lead to relevant and reliable information, so that the financial statements:

 

 

give a true and fair view of the Group’s financial position, financial performance and cash flows;

 

reflect the substance of transactions;

 

are neutral;

 

are prepared on a prudent basis; and

 

are complete in all material aspects.

The following summary provides further information about the critical accounting policies that involve significant elements of management judgment, and which could have a significant impact on the results of the Group. It should be read in conjunction with Note 1 to the Consolidated Financial Statements.

The assessment of critical accounting policies below is not meant to be an all-inclusive discussion of the uncertainties in financial results that can occur from the application of the full range of the Company’s accounting policies. Materially different financial results could occur in the application of other accounting policies as well. Likewise, materially different results can occur upon the adoption of new accounting standards promulgated by the various rule-making bodies.

Successful efforts method of oil and gas accounting

The Group follows the successful efforts method of accounting for its oil and gas activities. The Group’s oil and gas reserves are estimated by the Group’s petroleum engineers in accordance with industry standards and SEC regulations. In December 2008, the SEC published a revised set of rules for the estimation of reserves. These revised rules were used for the year-end estimation of reserves beginning in 2009. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic

 

 

 

(1) For the adjusted fully-diluted earnings per share, see the Consolidated Financial Statements included elsewhere herein, Note 4) Business segment information — A) Information by business segment.

 

68


Table of Contents

methods are used for the estimation. These estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on available reservoir data and prices and costs in the accounting period during which the estimate is made and are subject to future revision. The Group reassesses its oil and gas reserves at least once a year on all its properties.

Exploration leasehold acquisition costs are capitalized when acquired. During the exploration phase, management exercises judgment on the probability that prospects ultimately would partially or fully fail to find proved oil and gas reserves. Based on this judgmental approach, a leasehold impairment charge may be recorded. This position is assessed and adjusted throughout the contractual period of the leasehold based in particular on the results of exploratory activity and any impairment is adjusted prospectively.

When a discovery is made, exploratory drilling costs continue to be capitalized pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. The length of time necessary for this determination depends on the specific technical or economic difficulties in assessing the recoverability of the reserves. If a determination is made that the well did not encounter oil and gas in economically viable quantities, the well costs are expensed and are reported in exploration expense.

Exploratory drilling costs are temporarily capitalized pending determination of whether the well has found proved reserves if both of the following conditions are met:

 

 

the well has found a sufficient quantity of reserves to justify, if appropriate, its completion as a producing well, assuming that the required capital expenditure is made; and

 

satisfactory progress toward ultimate development of the reserves is being achieved, with the Company making sufficient progress assessing the reserves and the economic and operating viability of the project.

The Company evaluates the progress made on the basis of regular project reviews which take into account the following factors:

 

 

First, if additional exploratory drilling or other exploratory activities (such as seismic work or other significant studies) are either underway or firmly planned, the Company deems there is satisfactory progress. For these purposes, exploratory activities are considered firmly planned only if they are included in the Company’s three-year exploration plan/budget.

 

In cases where exploratory activity has been completed, the evaluation of satisfactory progress takes into account indicators such as the fact that

   

costs for development studies are incurred in the current period, or that governmental or other third-party authorizations are pending or that the availability of capacity on an existing transport or processing facility awaits confirmation.

The successful efforts method requires, among other things, that the capitalized costs for proved oil and gas properties (which include the costs of drilling successful wells) be amortized on the basis of reserves that are produced in a period as a percentage of the total estimated proved reserves. The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining book value of the asset over the expected future production. If proved reserve estimates are revised downward, earnings could be affected by higher depreciation expense or an immediate write-down of the property’s book value. Conversely, if the oil and gas quantities were revised upwards, future per-barrel depreciation and depletion expense would be lower.

Valuation of long-lived assets

In addition to oil and gas assets that could become impaired under the application of successful efforts accounting, other assets could become impaired and require write-down if circumstances warrant. Conditions that could cause an asset to become impaired include lower-than-expected commodity sales prices, changes in the Group’s business plans or a significant adverse change in the local or national business climate. The amount of an impairment charge would be based on estimates of the higher of the value in use or the fair value minus cost to sell compared with its book value. The value in use is based on the present value of expected future cash flow using assumptions commensurate with the risks involved in the asset group. The expected future cash flow used for impairment reviews is based on judgmental assessments of future production volumes, prices and costs, considering information available at the date of review.

Asset retirement obligations and environmental remediation

When legal and contractual obligations require it, the Group, upon application of International Accounting Standard (IAS) 37 and IAS 16, records provisions for the future decommissioning of production facilities at the end of their economic lives. Management makes judgments and estimates in recording liabilities. Most of these removal obligations are many years in the future and the precise requirements that will have to be met when the removal event actually occurs are uncertain. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public expectations.

 

 

69


Table of Contents

The Group also makes judgments and estimates in recording costs and establishing provisions for environmental clean-up and remediation costs, which are based on current information on costs and expected plans for remediation. For environmental provisions, actual costs can differ from estimates because of changes in laws and regulations, public expectations, discovery and analysis of site conditions and changes in clean-up technology.

Pensions and post-retirement benefits

Accounting for pensions and other post-retirement benefits involves judgments about uncertain events, including estimated retirement dates, salary levels at retirement, mortality rates, rates of return on plan assets, determination of discount rates for measuring plan obligations, healthcare cost-trend rates and rates of utilization of healthcare services by retirees. These assumptions are based on the environment in each country. The assumptions used are reviewed at the end of each year and may vary from year-to-year, based on the evolution of the situation, which will affect future results of operations. Any differences between these assumptions and the actual outcome will also impact future results of operations.

The significant assumptions used to account for pensions and other post-retirement benefits are determined as follows.

Discount rates primarily reflect the rates of high quality corporate bonds. Inflation rates reflect market conditions observed on a country-by-country basis.

Salary increase assumptions (when relevant) are determined by each entity. They reflect an estimate of the actual future salary levels of the individual employees involved, including future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority, promotion and other factors.

Healthcare cost trend assumptions (when relevant) reflect an estimate of the actual future changes in the cost of the healthcare-related benefits provided to the plan participants and are based on past and current healthcare cost trends including healthcare inflation, changes in healthcare utilization, and changes in health status of the participants.

Demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for the individual employees involved, based principally on available actuarial data.

Determination of expected rates of return on pension plan assets is made through compound averaging. For each plan, the distribution of investments among bonds, equities and cash and the expected rates of return on bonds,

equities and cash are taken into account. A weighted-average rate is then calculated.

The effect pensions had on results of operations, cash flow and liquidity is fully set out in Note 18 to the Consolidated Financial Statements. Net employee benefit expense in 2011 amounted to 315 million and the Company’s contributions to pension plans were 347 million.

Differences between projected and actual costs and between the projected return and the actual return on plan assets routinely occur and are called actuarial gains and losses.

The Group applies the corridor method to amortize its actuarial losses and gains. This method amortizes the net cumulative actuarial gains and losses that exceed 10% of the greater of (i) the present value of the defined benefit obligation, and (ii) the fair value of plan assets, over the average expected remaining working lives of the employees participating in the plan.

The unrecognized actuarial losses of pension benefits as of December 31, 2011, were 1,713 million compared to 1,170 million for 2010. The increase in unrecognized actuarial losses is explained by actuarial losses due to a decrease in discount rates in 2011 and due to a decrease in the value of plan assets. As explained above, pension accounting principles allow that such actuarial losses be deferred and amortized over future periods, in the Company’s case a period of fifteen years.

The Company is considering a decreased weighted-average expected rate of return on pension plan assets of 5.35% for 2012 compared to the 2011 rate of 5.90%. The Company does not believe, based on currently available information, that it will be significantly modifying its discount rate in 2012 or the near future.

The Company’s estimates indicate that a 1% increase or decrease in the expected rate of return on pension plan assets would have caused a 62 million decrease or increase, respectively, in the 2011 net periodic pension cost. The estimated impact on net periodic pension cost of the amortization of the unrecognized actuarial losses of pension benefits of 1,713 million as of December 31, 2011, is 102 million for 2012, compared to the actual impact of 46 million for 2011.

Income tax computation

The computation of the Group’s income tax expense requires the interpretation of complex tax laws and regulations in many taxing jurisdictions around the world, the determination of expected outcomes from pending litigation, and the assessment of audit findings that are performed by numerous taxing authorities. Actual income tax expense may differ from management’s estimates.

 

 

70


Table of Contents

RESULTS 2009-2011

 

 

As of and for the year ended December 31, (M, except per share data)    2011      2010      2009  

Non-Group sales

     184,693         159,269         131,327   

Net income (Group share)

     12,276         10,571         8,447   

Diluted earnings per share

     5.44         4.71         3.78   

 

Group Results 2011 vs. 2010

The year 2011 witnessed a number of geopolitical events that put pressure on market supplies. Despite the economic slowdown, demand for oil products continued to rise, fueled by the growth of emerging markets. Pressure on supply, plus rising demand, resulted in a sharp increase in the price of crude oil.

In the Upstream segment, the 2011 oil market environment was marked by a 40% increase in the average Brent price to $111.3/b from $79.5/b in 2010. In 2011, TOTAL’s average liquids price realization(1) increased by 38% to $105.0/b from $76.3/b in 2010, in line with the increase in the average Brent price of oil. TOTAL’s average natural gas price realization(1) increased by 27% to $6.53/MBtu in 2011 from $5.15/MBtu in 2010. The average euro-dollar exchange rate was 1.39 $/ in 2011 compared to 1.33 $/ in 2010.

In the Downstream segment, the Group’s European Refining Margin Indicator (ERMI) fell to $17.4/t in 2011 from $27.4/t in 2010. Despite the gradual reduction of refining capacity, the overcapacity that has existed in the European refining market since 2009 continued into 2011, due to low demand in Europe.

In the first half of 2011, the Chemicals segment enjoyed a globally favorable environment, which has since deteriorated. In the second half of the year, Petrochemicals and Specialty Chemicals saw their margins shrink due to the drop in demand caused by the economic slowdown.

Consolidated sales of TOTAL were 184.7 billion in 2011, an increase of 16% from 159.3 billion in 2010, as a result of an increase in non-Group sales in the Upstream, Downstream and Chemicals segments of 26%, 15% and 11%, respectively.

Net income (Group share) in 2011 increased by 16% to 12,276 million from 10,571 million in 2010, mainly due to the impact of the increase in hydrocarbon prices on the Upstream segment’s results. The after-tax inventory valuation effect (as defined below under “— Business

Segment Reporting”) had a positive impact on net income (Group share) of 834 million in 2011 and a positive impact of 748 million in 2010, in each case essentially due to the increase in oil prices. As from January 1, 2011, the Group accounts for changes in fair value of trading inventories and storage contracts (as defined below under “— Business Segment Reporting”). Changes in fair value of these items had a positive impact on net income (Group share) of 32 million in 2011. Special items had a negative impact on net income (Group share) of 14 million in 2011, comprised mainly of 1,014 million of impairments (essentially impairments on European refining and renewable energy assets) and 1,538 million of gains on asset sales. Special items had a negative impact on net income (Group share) of 384 million in 2010, comprised essentially of asset impairments that had a negative impact of 1,224 million (essentially impairments on European refining assets) and gains on asset sales that had a positive impact of 1,046 million. Effective July 1, 2010, the Group no longer accounts for its interest in Sanofi as an equity affiliate, but treats such interest as a financial asset available for sale in the line “Other investments” of the balance sheet. In 2010, the Group’s share of adjustment items related to Sanofi had a negative impact on net income (Group share) of 81 million.

In 2011, income taxes amounted to 14,073 million, an increase of 38% compared to 10,228 in 2010, primarily as a result of the increase in taxable income. The increase in the effective tax rate from 49% in 2010 to 53% in 2011 was mainly due to an increase in the portion of the Group’s income before tax attributable to entities with a local tax rate much higher than the French tax rate (36.10%). The portion of the Upstream income before tax represented 89% in 2011, unchanged from 2010.

The Group did not buy back shares in 2011. The number of fully-diluted shares at December 31, 2011, was 2,263.8 million compared to 2,249.3 million at December 31, 2010.

Fully-diluted earnings per share, based on 2,257 million weighted-average shares, was 5.44 in 2011 compared to 4.71 in 2010, an increase of 15%.

 

 

 

(1) Consolidated subsidiaries, excluding fixed margin and buyback contracts.

 

71


Table of Contents

Group Results 2010 vs. 2009

In 2010, the oil and gas market environment was characterized by increased demand for oil and natural gas products. Crude oil prices were relatively stable during 2010, with an average Brent oil price of $79.5/b, an increase of 29% compared to $61.7/b in 2009. In 2010, TOTAL’s average liquids price realization increased 31% to $76.3/b from $58.1/b in 2009, in line with the increase in the average Brent price of oil. TOTAL’s average natural gas price realization(1) decreased to $5.15/MBtu in 2010 from $5.17/MBtu in 2009. The average euro-dollar exchange rate was 1.33 $/ on average in 2010 compared to 1.39 $/ in 2009.

Refining margins rebounded in 2010 from historically low levels in 2009. For the full year 2010, the Group’s ERMI was $27.4/t, an increase of 54% compared to $17.8/t in 2009.

For the full year 2010, the Chemicals segment benefited from a strong rebound in demand and margins in the Base Chemicals division’s market, as well as an increase in demand in the Specialties Chemicals division’s market.

Consolidated sales of TOTAL were 159.3 billion in 2010, an increase of 21% from 131.3 billion in 2009, as a result of an increase in non-Group sales in the Upstream, Downstream and Chemicals segments of 15%, 23% and 19%, respectively.

Reported net income (Group share) in 2010 increased by 25% to 10,571 million from 8,447 million in 2009, mainly due to the increase in hydrocarbon prices and production, as well as a rebound in the Chemicals segment. The after-tax impact of prices on inventory valuation accounted for in the Downstream and Chemicals segments had a positive impact on net income (Group share) of 748 million in 2010 and a positive impact of 1,533 million in 2009, in each case due to the increase in oil prices. For a discussion of the impact of prices on inventory valuation in the Downstream and Chemicals segments see “— Business Segment Reporting” below. Special items had a negative impact on net income (Group share) of 384 million in 2010, comprised essentially of asset impairments that had a negative impact of 1,224 million and gains on asset sales that had a positive impact of 1,046 million. Special items had a negative impact of 570 million in 2009. Effective July 1, 2010, the Group no longer accounts for its interest in Sanofi as an equity affiliate, but treats such interest as a financial asset available for sale in the line “Other investments” of the balance sheet. The Group’s share of adjustment items

related to Sanofi had a negative impact on net income (Group share) of 81 million in 2010 (six months) and a negative impact of 300 million in 2009 (full year).

In 2010, income taxes amounted to 10,228 million, an increase of 32% compared to 7,751 in 2009, primarily as a result of the increase in taxable income. The increase in the effective tax rate from 47% in 2009 to 49% in 2010 was mainly due to an increase in the portion of the Group income before tax attributable to entities with a local tax rate much higher than the French tax rate (34.43%). The portion of the Upstream income before tax represented 89% in 2010 compared with 82% in 2009, with a corresponding impact on the Group effective tax rate.

The Group did not buy back shares in 2010. The number of fully-diluted shares at December 31, 2010, was 2,249.3 million compared to 2,243.7 million at December 31, 2009.

Fully-diluted earnings per share, based on 2,244.5 million weighted-average shares, was 4.71 in 2010, compared to 3.78 in 2009, an increase of 25%.

Business Segment Reporting

The financial information for each business segment is reported on the same basis as that used internally by the chief operating decision maker in assessing segment performance and the allocation of segment resources. Due to their particular nature or significance, certain transactions qualified as “special items” are excluded from the business segment figures. In general, special items relate to transactions that are significant, infrequent or unusual. However, in certain instances, certain transactions such as restructuring costs or asset disposals, which are not considered to be representative of the normal course of business, may be qualified as special items although they may have occurred in prior years or are likely to recur in following years.

In accordance with IAS 2, the Group values inventories of petroleum products in the financial statements according to the FIFO (First-In, First-Out) method and other inventories using the weighted-average cost method. Under the FIFO method, the cost of inventory is based on the historic cost of acquisition or manufacture rather than the current replacement cost. In volatile energy markets, this can have a significant distorting effect on the reported income. Accordingly, the adjusted results of the Downstream segment and Chemicals segment are presented according to the replacement cost method in order to facilitate the comparability of the Group’s results

 

 

 

(1) Consolidated subsidiaries, excluding fixed margin and buyback contracts.

 

72


Table of Contents

with those of its competitors and to help illustrate the operating performance of these segments excluding the impact of oil price changes on the replacement of inventories. In the replacement cost method, which approximates the LIFO (Last-In, First-Out) method, the variation of inventory values in the statement of income is, depending on the nature of the inventory, determined using either the month-end prices differential between one period and another or the average prices of the period. The inventory valuation effect is the difference between the results under the FIFO and replacement cost methods.

As from January 1, 2011, the effect of changes in fair value presented as an adjustment item reflects, for trading inventories and storage contracts, differences between internal measures of performance used by TOTAL’s management and the accounting for these transactions under IFRS. IFRS requires that trading inventories be recorded at their fair value using period-end spot prices. In order to best reflect the management of economic exposure through derivative transactions, internal indicators used to measure performance include valuations of trading inventories recorded at their fair value based on forward prices. Furthermore, TOTAL, in its trading activities, enters into storage contracts, the future effects of which are recorded at fair value in the Group’s internal economic performance. IFRS, by requiring accounting for storage contracts on an accrual basis, precludes recognition of this fair value effect.

Until June 30, 2010, the Group also adjusted for its equity share of adjustment items related to Sanofi. As of July 1, 2010, Sanofi is no longer accounted for as an equity affiliate (but is instead treated as a financial asset available for sale in the line “Other investments” of the balance sheet).

The adjusted business segment results (adjusted operating income and adjusted net operating income) are defined as replacement cost results, adjusted for special items, excluding the effect of changes in fair value as from January 1, 2011. For further information on the adjustments affecting operating income on a segment-by-segment basis, and for a reconciliation of segment figures to figures reported in the Company’s audited consolidated financial statements, see Note 4 to the Consolidated Financial Statements.

The Group measures performance at the segment level on the basis of net operating income and adjusted net operating income. Net operating income comprises operating income of the relevant segment after deducting the amortization and the depreciation of intangible assets other than leasehold rights, translation adjustments and gains or losses on the sale of assets, as well as all other income and expenses related to capital employed (dividends from non-consolidated companies, income from equity affiliates and capitalized interest expenses) and after income taxes applicable to the above. The income and expenses not included in net operating income that are included in net income are interest expenses related to long-term liabilities net of interest earned on cash and cash equivalents, after applicable income taxes (net cost of net debt and non-controlling interests). Adjusted net operating income excludes the effect of the adjustments (special items and the inventory valuation effect) described above. For further discussion of the calculation of net operating income and the calculation of return on average capital employed (ROACE)(1), see Note 2 to the Consolidated Financial Statements.

 

 

Upstream results

 

(M)    2011     2010     2009  

Non-Group sales

     23,298        18,527        16,072   

Operating income(a)

     22,444        17,450        12,858   

Equity in income (loss) of affiliates and other items

     1,596        1,533        846   

Tax on net operating income

     (13,506     (10,131     (7,486

Net operating income(a)

     10,534        8,852        6,218   

Adjustments affecting net operating income

     (129     (255     164   

Adjusted net operating income(b)

     10,405        8,597        6,382   

Investments

     21,689        13,208        9,855   

Divestments

     2,656        2,067        398   

ROACE

     20%        21%        18%   

 

(a) For the definition of operating income and net operating income, see Note 2 to the Consolidated Financial Statements.
(b) Adjusted for special items. See Notes 2 and 4 to the Consolidated Financial Statements.

 

 

(1) ROACE = adjusted net operating income divided by average capital employed.

 

73


Table of Contents

2011 vs. 2010

Upstream segment sales (excluding sales to other segments) increased by 26% to 23,298 million in 2011 from 18,527 million in 2010, reflecting essentially the impact of higher hydrocarbon prices.

Oil and gas production averaged 2,346 kboe/d in 2011, compared to 2,378 kboe/d in 2010. This 1.3% decrease was due essentially to the result of normal decline, net of production ramp-ups on new projects (-1.5%), security conditions, mainly in Libya (-1.5%) and the price effect(1) (-2%), partially offset by changes in the portfolio (+2.5%; integrating the net share of Novatek production and the impact of the sale of interests in CEPSA) and the end of OPEC reductions (+1%).

Proved reserves based on SEC rules were 11,423 Mboe at December 31, 2011 (Brent at $110.96/b), compared to 10,695 Mboe at December 31, 2010 (Brent at $79.02/b). Based on the 2011 average rate of production, reserve life is thirteen years.

See “Item 4. Information on the Company — Exploration & Production — Reserves” for a discussion of proved reserves and “Supplemental Oil and Gas Information (Unaudited)” contained elsewhere herein for additional information on proved reserves, including tables showing changes in proved reserves by region.

Upstream net operating income in 2011 amounted to 10,534 million (for 2010, 8,852 million) from operating income of 22,444 million (for 2010, 17,450 million), with the difference between net operating income and operating income resulting primarily from taxes on net operating income of 13,506 million (for 2010, 10,131 million), partially offset by income from equity affiliates and other items of 1,596 million (for 2010, 1,533 million). The increase in net operating income in 2011 compared to 2010 was due primarily to the impact of higher hydrocarbon prices.

Adjusted net operating income for the Upstream segment was 10,405 million in 2011 compared to 8,597 million in 2010, an increase of 21%, essentially due to the impact of higher hydrocarbon prices partially offset by the impact of the mix effect, changes in foreign exchange rates and increased costs, exploration expenses and taxes. Technical costs for consolidated subsidiaries, in accordance with ASC 932(2) were $18.9/boe(3) in 2011, compared to $16.6/boe in 2010, mainly due to

depreciation, depletion and amortization (DD&A) charges related notably to the start-up of new projects and increased operating expenses per barrel.

Adjusted net operating income for the Upstream segment excludes special items. In 2011, the exclusion of special items had a negative impact of 129 million on adjusted net operating income for the Upstream segment and a negative impact of 255 million in 2010, in both cases comprised principally of capital gains on asset sales partially offset by asset impairments.

The Upstream segment’s total capital expenditures increased by 64% to 21,689 million in 2011 from 13,208 million in 2010. Capital expenditures excluding acquisitions in 2011 mainly included projects in the following countries: Angola, Nigeria, Norway, Australia, Kazakhstan, the United Kingdom, Canada, Indonesia, Gabon, the Republic of the Congo and the United States.

ROACE for the Upstream segment decreased to 20% in 2011 from 21% in 2010. The decrease was mainly due to the increase in capital employed in 2011.

2010 vs. 2009

Upstream segment sales (excluding sales to other segments) increased by 15% to 18,527 million in 2010 from 16,072 million in 2009, reflecting essentially the impact of higher hydrocarbon prices and production growth.

Oil and gas production averaged 2,378 kboe/d in 2010, compared to 2,281 kboe/d in 2009. This 4.3% increase was essentially the result of production ramp-ups on new projects, net of the normal decline, and a lower level of turnarounds (+3%), changes in the portfolio (+2%), lower OPEC reductions and an increase in gas demand (+1.5%) and improved security conditions in Nigeria (+1%), partially offset by the price effect (-3%).

Proved reserves based on SEC rules were 10,695 Mboe at December 31, 2010 (Brent at $79.02/b), compared to 10,483 Mboe at December 31, 2009 (Brent at $59.91/b). At the 2010 average rate of production, reserve life was more than twelve years.

See “Item 4. Information on the Company — Exploration & Production — Reserves” for a discussion of proved reserves and “Supplemental Oil and Gas Information (Unaudited)” contained elsewhere herein for additional information on proved reserves, including tables showing changes in proved reserves by region.

 

 

 

(1) The “price effect” refers to the impact of hydrocarbon prices on entitlement volumes from production sharing and buyback contracts. For example, as the price of oil or gas increases above certain pre-determined levels, TOTAL’s share of production normally decreases.
(2) Accounting Standards Codification Topic 932, Extractive industries — Oil and Gas.
(3) Excluding IAS 36 (impairment of assets).

 

74


Table of Contents

Upstream net operating income in 2010 amounted to 8,852 million (for 2009, 6,218 million) from operating income of 17,450 million (for 2009, 12,858 million), with the difference between net operating income and operating income resulting primarily from taxes on net operating income of 10,131 million (for 2009, 7,486 million), partially offset by income from equity affiliates and other items of 1,533 million (for 2009, 846 million). The increase in net operating income in 2010 compared to 2009 was due primarily to the impact of higher hydrocarbon prices and production growth.

Over the full year 2010, adjusted net operating income for the Upstream segment was 8,597 million compared to 6,382 million in 2009, an increase of 35%, essentially due to hydrocarbon prices (+2.3 billion). Technical costs for consolidated subsidiaries, in accordance with ASC 932 were $16.6/boe in 2010, compared to $15.4/boe in 2009, mainly due to depreciation, depletion and amortization (DD&A) charges related notably to the start-up of new projects and increased operating expenses per barrel.

Adjusted net operating income for the Upstream segment excludes special items. In 2010, the exclusion of special items (comprised principally of capital gains on asset sales partially offset by asset impairments) had a negative impact of 255 million on adjusted net operating income for the Upstream segment compared to a positive impact of 164 million in 2009 (comprised principally of asset impairments and other elements).

The Upstream segment’s total capital expenditures increased by 34% to 13,208 million in 2010 from 9,855 million in 2009. The capital expenditures in 2010 mainly included projects in the following countries: Angola, the United States, Nigeria, Canada, Norway, Kazakhstan, Australia, the United Kingdom, Indonesia, the Republic of the Congo, Libya, Gabon and Thailand.

ROACE for the Upstream segment increased to 21% in 2010 from 18% in 2009. The increase was mainly due to the adjusted net operating income having increased, principally due to increased hydrocarbon prices and production.

 

 

Downstream results

 

(M)    2011     2010     2009  

Non-Group sales

     141,907        123,245        100,518   

Operating income(a)

     1,694        982        2,237   

Equity in income (loss) of affiliates and other items

     401        141        169   

Tax on net operating income

     (409     (201     (633

Net operating income(a)

     1,686        922        1,773   

Adjustments affecting net operating income

     (603     246        (820

Adjusted net operating income(b)

     1,083        1,168        953   

Investments

     1,870        2,343        2,771   

Divestments

     3,235        499        133   

ROACE

     7%        8%        7%   

 

(a) For the definition of operating income and net operating income, see Note 2 to the Consolidated Financial Statements.
(b) Adjusted for special items and the inventory valuation effect. See Notes 2 and 4 to the Consolidated Financial Statements.

 

2011 vs. 2010

For the full year 2011, the Group’s European Refining Margin Indicator (ERMI) was $17.4/t, a decrease of 36% compared to 2010.

Downstream segment sales (excluding sales to other segments) were 141,907 million in 2011 compared to 123,245 million in 2010, an increase of 15% essentially due to the impact of higher hydrocarbon prices.

Refined product sales (including trading operations) were 3,639 kb/d in 2011, a decrease of 4% compared to 3,776 kb/d in 2010. Refinery throughput in 2011 was 1,863 kb/d, a 7% decrease compared to 2,009 kb/d in 2010 essentially due to the sale of the Group’s interest in CEPSA and a higher level of major turnarounds than in

2010. In 2011, major turnarounds took place in the Antwerp, Grandpuits, Leuna, Lindsey and Port Arthur refineries. For the full year 2011, the refinery utilization rate based on crude throughput was 78% (83% for crude and other feedstock) compared to 73% in 2010 (77% for crude and other feedstock). In 2010, the utilization rate was impacted by the shutdown of the Dunkirk refinery and a distillation unit at the Normandy refinery as well as impacts from strikes in France.

In 2011, Downstream net operating income increased to 1,686 million (for 2010, 922 million) from operating income of 1,694 million (for 2010, 982 million), with the difference between net operating income and operating income resulting primarily from taxes on net operating income of 409 million (for 2010, 201 million), partially

 

 

75


Table of Contents

offset by income from equity affiliates and other items of 401 million (for 2010, 141 million). The increase in net operating income in 2011 compared to 2010 was due primarily to the impact of higher hydrocarbon prices, gains on asset sales and lower impairment charges.

The Downstream segment’s adjusted net operating income in 2011 was 1,083 million compared to 1,168 million in 2010. The decrease was essentially due to the negative impact of the deterioration in refining margins in 2011.

Adjusted net operating income for the Downstream segment excludes any after-tax inventory valuation effect and special items. The adjustment for the inventory valuation effect had a negative impact on Downstream adjusted net operating income in 2011 of 859 million compared to a negative impact of 640 million in 2010. The exclusion of special items (comprised essentially of impairments on European refining assets (as described below), partially offset by gains on asset sales) in 2011 had a positive impact of 256 million on adjusted net operating income. In 2010, the exclusion of special items (comprised essentially of impairments on European refining assets partially offset by gains on asset sales) had a positive impact of 886 million on adjusted net operating income.

The persistence of an unfavorable economic environment for refining, affecting Europe in particular, led the Group to recognize an impairment in the Downstream segment on European refining assets in the third and fourth quarters of 2011 in the amount of 700 million in operating income and 478 million in net income. These elements have been treated as adjustment items.

Investments by the Downstream segment were 1,870 million in 2011, a decrease of 20% compared to 2,343 million in 2010. Divestments by the Downstream segment were 3,235 million in 2011, comprised essentially of the Group’s stake in CEPSA and certain distribution activities in the United Kingdom, compared to 499 million in 2010.

ROACE for the Downstream segment was 7% in 2011 compared to 8% in 2010.

2010 vs. 2009

For the full year 2010, the Group’s ERMI was $27.4/t, an increase of 54% compared to 2009.

Downstream segment sales (excluding sales to other segments) were 123,245 million in 2010, an increase of 23% from 100,518 million in 2009.

Refined product sales (including trading operations) were 3,776 kb/d in 2010, an increase of 4% compared to 3,616 kb/d in 2009. Refinery throughput in 2010 was 2,009 kb/d, a 7% decrease compared to 2,151 kb/d in

2009. For the full year 2010, the refinery utilization rate based on crude throughput was 73% (77% for crude and other feedstock) compared to 78% in 2009 (83% for crude and other feedstock), reflecting essentially the shutdown of the Dunkirk refinery and a distillation unit at the Normandy refinery as well as impacts from strikes in France. In 2010, the level of scheduled turnarounds for refinery maintenance was low, with turnaround activity expected to increase notably in 2011.

In 2010, Downstream net operating income decreased to 922 million (for 2009, 1,773 million) from operating income of 982 million (for 2009, 2,237 million), with the difference between net operating income and operating income resulting primarily from taxes on net operating income of 201 million (for 2009, 633 million), partially offset by income from equity affiliates and other items of 141 million (for 2009, 169 million). The decrease in net operating income in 2010 compared to 2009 was due primarily to the impairment charge for French and UK refining assets referred to below.

The Downstream segment’s adjusted net operating income in 2010 was 1,168 million compared to 953 million in 2009. The increase was essentially due to the positive impact of the refining margin improvement, which was partially offset by lower throughput and reliability of the Group’s refineries in 2010 and less favorable conditions for supply optimization.

Adjusted net operating income for the Downstream segment excludes any after-tax inventory valuation effect and special items. The adjustment for the inventory valuation effect had a negative impact on Downstream adjusted net operating income in 2010 of 640 million compared to a negative impact of 1,285 million in 2009. The exclusion of special items (comprised essentially of impairments on European refining assets (as described below), partially offset by gains on asset sales) in 2010 had a positive impact of 886 million on adjusted net operating income. In 2009, the exclusion of special items (relating mainly to refining asset impairments and other elements) had a positive impact of 465 million on adjusted net operating income.

The persistence of an unfavorable economic environment for refining, affecting Europe in particular, led the Group to recognize an impairment in the Downstream segment, essentially on French and UK refining assets, in the fourth quarter 2010 in the amount of 1,192 million in operating income and 913 million in net operating income. These elements have been treated as adjustment items.

Investments by the Downstream segment were 2,343 million in 2010, compared to 2,771 million in 2009.

ROACE for the Downstream segment was 8% in 2010 compared to 7% in 2009.

 

 

76


Table of Contents

Chemicals results

 

(M)    2011     2010     2009  

Non-Group sales

     19,477        17,490        14,726   

Operating income(a)

     658        964        553   

Equity in income (loss) of affiliates and other items

     471        215        (58

Tax on net operating income

     (225     (267     (92

Net operating income(a)

     904        912        403   

Adjustments affecting net operating income

     (129     (55     (131

Adjusted net operating income(b)

     775        857        272   

Investments

     847        641        631   

Divestments

     1,164        347        47   

ROACE

     10%        12%        4%   

 

(a) For the definition of operating income and net operating income, see Note 2 to the Consolidated Financial Statements.
(b) Adjusted for special items and the inventory valuation effect. See Notes 2 and 4 to the Consolidated Financial Statements.

 

2011 vs. 2010

For the full year 2011, Chemicals segment sales, excluding intra-Group sales, were 19,477 million, an increase of 11% compared to 17,490 million for 2010, reflecting essentially the globally favorable environment in the first half 2011, which has since deteriorated.

In 2011, net operating income for the Chemicals segment was 904 million (for 2010, 912 million) from an operating income of 658 million (for 2010, 964 million), with the difference between net operating income and operating income resulting primarily from income from equity affiliates and other items of 471 million (for 2010, income of 215 million) offset by taxes on net operating income of 225 million (for 2010, a tax loss of 267 million). The decrease in 2011 in net operating income compared to 2010 was due primarily to the sale of the Group’s stake in CEPSA and a portion of the Resins activities.

The adjusted net operating income for the Chemicals segment in 2011 was 775 million compared to 857 million in 2010, due essentially to the impact of the sale of the Group’s interest in CEPSA and a portion of the Resins activities. The adjusted net operating income for the Base Chemicals division decreased from 393 million in 2010 to 373 million in 2011. Globally, for the full-year 2011, the Base Chemicals division benefited from ramp-ups in its activities in Qatar and South Korea, but suffered from deteriorating margins in the second half of the year in Europe and in the United States. The Specialty Chemicals division, excluding the effect of changes in the portfolio, maintained results at a level close to the 2010 level, with an adjusted net operating income in 2011 of 426 million compared to 475 million in 2010.

Adjusted net operating income for the Chemicals segment excludes any after-tax inventory valuation effect and special items. The exclusion of the inventory valuation effect had a negative impact on Chemicals adjusted net operating income of 10 million in 2011, compared to a

negative impact of 113 million in 2010. In 2011, the exclusion of special items had a negative impact on Chemicals adjusted net operating income of 119 million, where special items consisted essentially of gains on asset sales. In 2010, the exclusion of special items had a positive impact on Chemicals adjusted net operating income of 58 million.

Investments by the Chemicals segment increased 32% to 847 million in 2011 compared to 641 million in 2010. Divestments by the Chemicals segment were 1,164 million in 2011, comprised essentially of the sale of the Group’s stake in CEPSA and certain Resins activities, compared to 347 million in 2010.

ROACE for the Chemicals segment was 10% in 2011 compared to 12% in 2010, due essentially to a decrease in adjusted net operating income in 2011 compared to 2010.

2010 vs. 2009

For the full year 2010, Chemicals segment sales, excluding intra-Group sales, were 17,490 million, an increase of 19% compared to 2009.

In 2010, net operating income for the Chemicals segment was 912 million (for 2009, 403 million) from an operating income of 964 million (for 2009, 553 million), with the difference between net operating income and operating income resulting primarily from income from equity affiliates and other items of 215 million (for 2009, a loss of 58 million) offset by a loss from taxes on net operating income of 267 million (for 2009, a tax loss of 92 million).

The adjusted net operating income for the Chemicals segment in 2010 was 857 million compared to 272 million in 2009. The adjusted net operating income for the Base Chemicals division increased by 377 million from 2009 to 2010, due to an improved environment and the ramp-up of new production units in Qatar. In 2010, the Specialties Chemicals division benefited from strong operational performance and good positioning in growth markets.

 

 

77


Table of Contents

Adjusted net operating income for the Chemicals segment excludes any after-tax inventory valuation effect and special items. The exclusion of the inventory valuation effect had a negative impact on Chemicals adjusted net operating income of 113 million in 2010, compared to a negative impact of 254 million in 2009. In 2010, the exclusion of special items had a positive impact on Chemicals adjusted net operating income of 58 million. In 2009, the exclusion of special items (comprised primarily of

asset impairments and other elements) had a positive impact on Chemicals adjusted net operating income of 123 million.

Investments by the Chemicals segment increased to 641 million in 2010 compared to 631 million in 2009.

ROACE for the Chemicals segment was 12% in 2010 compared to 4% in 2009 due principally to the significant increase in adjusted net operating income.

 

 

LIQUIDITY AND CAPITAL RESOURCES

 

 

(M)    2011     2010     2009  

Cash flow from operating activities

     19,536        18,493        12,360   

Including (increase) decrease in working capital

     (1,739     (496     (3,316

Cash flow used in investing activities

     (15,963 )      (11,957 )      (10,268 ) 

Total expenditures

     (24,541     (16,273     (13,349

Total divestments

     8,578        4,316        3,081   

Cash flow used in financing activities

     (4,309 )      (3,348 )      (2,868 ) 

Net increase (decrease) in cash and cash equivalents

     (736 )      3,188        (776 ) 

Effect of exchange rates

     272        (361     117   

Cash and cash equivalents at the beginning of the period

     14,489        11,662        12,321   

Cash and cash equivalents at the end of the period

     14,025        14,489        11,662   

 

TOTAL’s cash requirements for working capital, capital expenditures, acquisitions and dividend payments over the past three years were financed primarily by a combination of funds generated from operations, borrowings and divestments of non-core assets. In the current environment, TOTAL expects its external debt to be principally financed from the international debt capital markets. The Group continually monitors the balance between cash flow from operating activities and net expenditures. In the Company’s opinion, its working capital is sufficient for its present requirements.

Capital expenditures

The largest part of TOTAL’s capital expenditures in 2011 was made up of additions to intangible assets and property, plant and equipment (approximately 73%), with the remainder attributable to equity-method affiliates and to acquisitions of subsidiaries. In the Upstream segment, as described in more detail under “Supplemental Oil and Gas Information (Unaudited) — Costs incurred in oil and gas property acquisition, exploration and development activities”, capital expenditures in 2011 were principally development costs (approximately 50%, mainly for construction of new production facilities), exploration expenditures (successful or unsuccessful, approximately 5%) and acquisitions of proved and unproved properties (approximately 40%). In the Downstream segment, about 55% of capital expenditures in 2011 were related to refining activities (essentially 70% for existing units including maintenance and major turnarounds and 30% for

new construction), the balance being related to marketing/retail activities and information systems. In the Chemicals segment, capital expenditures related to all activities in 2011 and were split between Base Chemicals (approximately 60%) and Specialties Chemicals (approximately 40%). For information on expenditures by business segment, please refer to the discussion of TOTAL’s results for each segment above.

Cash flow

Cash flow from operating activities was 19,536 million in 2011 compared to 18,493 million in 2010 and 12,360 million in 2009. The 1,043 million increase in cash flow from operating activities from 2010 to 2011 was due in part to higher net income (Group share), which increased by 1,705 million over the same period. The cash flow from operating activities was also affected by the effect of changes in oil and oil product prices on the Group’s working capital requirement. As IFRS rules require TOTAL to account for inventories of petroleum products according to the FIFO method, an increase in oil and oil product prices at the end of the relevant period compared to the beginning of the same period generates, all other factors remaining equal, an increase in inventories and accounts receivable net of an increase in accounts payable, resulting in an increase in working capital requirements. Similarly, a decrease in oil and oil products prices generates a decrease in working capital requirements. In 2011, the Group’s working capital requirement increased by 1,739 million, due primarily to

 

 

78


Table of Contents

the increase in oil and oil products prices over the course of the year. In 2010, the increase was of 496 million.

Cash flow used in investing activities was 15,963 million in 2011 compared to 11,957 million in 2010 and 10,268 million in 2009. The increase from 2010 to 2011 was due essentially to the higher level of acquisitions made in 2011 as well as to the larger portfolio of upstream projects that were under development in 2011.

Total expenditures were 24,541 million in 2011, up 51% from 16,273 million in 2010, after having increased 22% from 13,349 million in 2009. During 2011, 88% of the expenditures were made by the Upstream segment (as compared to 81% in 2010 and 74% in 2009), 8% by the Downstream segment (as compared to 14% in 2010 and 21% in 2009) and 3% by the Chemicals segment (as compared to 4% in 2010 and 5% in 2009). The main source of funding for these expenditures has been cash from operating activities. For additional information on expenditures, please refer to the discussions in “— Overview” and “— Results 2009-2011”.

Divestments, based on selling price and net of cash sold, were 8,578 million in 2011, compared to 4,316 million in 2010 and 3,081 million in 2009. In 2011, the Group’s principal divestments were asset sales of 7,705 million, consisting mainly of the Group’s interests in CEPSA, of its Marketing assets in the United Kingdom, of its photocure and coatings resins businesses, of its interests in Total E&P Cameroun and of Sanofi shares. In 2010, the Group’s principal divestments were asset sales of 3,452 million, consisting mainly of Sanofi shares and the Group’s interests in the Valhall/Hod fields in Norway and in Block 31 in Angola. In 2009, the Group’s principal divestments were asset sales of 2,663 million, consisting mainly of Sanofi shares.

Cash flow used in financing activities was 4,309 million in 2011, compared to 3,348 million in 2010 and 2,868 million in 2009. The increase in cash flow used in financing activities in 2011 compared to 2010 was due primarily to a higher decrease in current borrowings ((3,870) million in 2011 compared to (731) million in 2010), partly offset by a higher issuance of non-current financial debt (4,069 million in 2011 compared to 3,789 million in 2010) and an increase in current financial assets and liabilities (896 million in 2011 compared to (817) million in 2010).

Indebtedness

TOTAL’s non-current financial debt was 22,557 million at year-end 2011 compared to 20,783 million at year-end 2010 and 19,437 million at year-end 2009. For further information on the Company’s level of borrowing and the type of financial instruments, including maturity profile of debt and currency and interest rate structure, see Note 20

to the Consolidated Financial Statements. For further information on the Company’s treasury policies, including the use of instruments for hedging purposes and the currencies in which cash and cash equivalents are held, see “Item 11. Quantitative and Qualitative Disclosures About Market Risk”.

Cash and cash equivalents were 14,025 million at year-end 2011 compared to 14,489 million at year-end 2010 and 11,662 million at year-end 2009.

Shareholders’ equity

Shareholders’ equity was 69,389 million at December 31, 2011, compared to 61,271 million at year-end 2010 and 53,539 million at year-end 2009. Changes in shareholders’ equity in 2011 were primarily due to the addition of net income and translation adjustments, which were only partially offset by the payment of dividends. Changes in shareholders’ equity in 2010 were primarily due to the addition of net income and translation adjustments, which were only partially offset by the payment of dividends. Changes in shareholders’ equity in 2009 were primarily due to the addition of net income, which was only partially offset by the payment of dividends and translation adjustments. TOTAL did not repurchase any of its own shares during the years 2009, 2010 and 2011.

Net-debt-to-equity

As of December 31, 2011, TOTAL’s net-debt-to-equity ratio, which is net debt (i.e., the sum of current borrowings, other current financial liabilities and non-current financial debt, net of current financial assets, hedging instruments on non-current financial debt and cash and cash equivalents) divided by the sum of shareholders’ equity and non-controlling interests after expected dividends payable, was 23%, compared to 22% and 27% at year-ends 2010 and 2009, respectively. Over the 2009-2011 period, TOTAL used its net cash flow (cash flow from operating activities less investments plus divestments) to maintain this ratio generally in its targeted range of around 25% to 30%, primarily by managing net debt, while net income increased shareholders’ equity and dividends paid throughout the period decreased shareholders’ equity. As of December 31, 2011, TOTAL S.A. had $10,139 million of long-term confirmed lines of credit, of which $10,096 million were unused.

In 2012, based on the Group’s capital expenditures budget and after payment of dividends, the Company expects to maintain its net debt-to-equity ratio in the target range of around 20% to 30% in a $100 per barrel market environment. For information on the Group’s capital expenditures budget, please refer to the discussion in “— Overview”.

 

 

79


Table of Contents

GUARANTEES AND OTHER OFF-BALANCE SHEET ARRANGEMENTS

 

 

As part of certain project financing arrangements, Total S.A. provided in 2008 guarantees in connection with the financing of the Yemen LNG project for an amount of 1,208 million, presented under “Guarantees given against borrowings” in Note 23 to the Consolidated Financial Statements. In turn, certain partners involved in this project have given commitments that could, in the case of Total S.A.’s guarantees being called for the maximum amount, reduce the Group’s exposure by up to 404 million, recorded under “Other commitments received” in the same Note. “Guarantees given against borrowings” also include the guarantees provided in 2010 by Total S.A. in connection with the financing of the Jubail project (operated by SAUDI ARAMCO TOTAL Refining and Petrochemical Company (SATORP)) of up to 2,463 million, proportional to TOTAL’s share in the project (37.5%). In addition, Total S.A. provided in 2010 a

guarantee in favor of its partner in the Jubail project (Saudi Arabian Oil Company) with respect to Total Refining Saudi Arabia SAS’s obligations under the shareholders agreement with respect to SATORP. As of December 31, 2011, this guarantee is of up to 1,095 million and has been presented under “Other operating commitments” in Note 23 to the Consolidated Financial Statements. These guarantees and other information on the Company’s commitments and contingencies are presented in Note 23 to the Consolidated Financial Statements. The Group does not currently consider that these guarantees, or any other off-balance sheet arrangements of Total S.A. nor any other members of the Group, have or are reasonably likely to have, currently or in the future, a material effect on the Group’s financial condition, changes in financial condition, revenues or expenses, results of operation, liquidity, capital expenditures or capital resources.

 

 

CONTRACTUAL OBLIGATIONS

 

 

Payment due by period (M)    Less
than
1 year
     1-3
years
     3-5
years
     More
than
5 years
     Total  

Non-current debt obligations(a)

             8,052         5,069         7,308         20,429   

Current portion of non-current debt obligations(b)

     3,488                                 3,488   

Finance lease obligations(c)

     25         70         64         18         177   

Asset retirement obligations(d)

     272         469         335         5,808         6,884   

Operating lease obligations(c)

     762         968         651         940         3,321   

Purchase obligations(e)

     11,049         11,058         9,476         45,770         77,353   

Total

     15,596         20,617         15,595         59,844         111,652   

 

(a) Non-current debt obligations are included in the items “Non-current financial debt” and “Hedging instruments of non-current financial debt” of the Consolidated Balance Sheet. The figure in this table is net of the non-current portion of issue swaps and swaps hedging bonds, and excludes non-current finance lease obligations of 152 million.
(b) The current portion of non-current debt is included in the items “Current borrowings”, “Current financial assets” and “Other current financial liabilities” of the balance sheet. The figure in this table is net of the current portion of issue swaps and swaps hedging bonds and excludes the current portion of finance lease obligations of 25 million.
(c) Finance lease obligations and operating lease obligations: the Group leases real estate, retail stations, ships, and other equipment through non-cancelable capital and operating leases. These amounts represent the future minimum lease payments on non-cancelable leases to which the Group is committed as of December 31, 2011, less the financial expense due on finance lease obligations for 31 million.
(d) The discounted present value of Upstream asset retirement obligations, primarily asset removal costs at the completion date.
(e) Purchase obligations are obligations under contractual agreements to purchase goods or services, including capital projects. These obligations are enforceable and legally binding on TOTAL and specify all significant terms, including the amount and the timing of the payments. These obligations mainly include: hydrocarbon unconditional purchase contracts (except where an active, highly liquid market exists and when the hydrocarbons are expected to be re-sold shortly after purchase), reservation of transport capacities in pipelines, unconditional exploration works and development works in Upstream, and contracts for capital investment projects in Downstream. This disclosure does not include contractual exploration obligations with host states where a monetary value is not attributed and purchases of booking capacities in pipelines where the Group has a participation superior to the capacity used.

For additional information on the Group’s contractual obligations, see Note 23 to the Consolidated Financial Statements. The Group has other obligations in connection with pension plans which are described in Note 18 to the Consolidated Financial Statements. As these obligations are not contractually fixed as to timing and amount, they have not been included in this disclosure. Other non-current liabilities, detailed in Note 19 to the Consolidated Financial Statements, are liabilities related to risks that are probable and amounts that can be reasonably estimated. However, no contractual agreements exist related to the settlement of such liabilities, and the timing of the settlement is not known.

 

80


Table of Contents

RESEARCH AND DEVELOPMENT

 

 

In 2011, Research & Development (R&D) expenses amounted to 776 million, compared to 715 million in 2010 and 650 million in 2009. The process initiated in 2004 to increase R&D budgets continued in 2011. In addition, the Group set up in 2009 a structure to contribute to the development of start-ups that specialize in innovative energy technologies.

In 2011, 3,946 employees were dedicated to R&D, compared to 4,087 in 2010 and 4,016 in 2009. The reduction in 2011 can be explained, in particular, by the sale of part of the Specialty Chemicals’ Resins activity.

There are six major R&D focuses at TOTAL:

 

 

developing knowledge, tools and technological mastery to discover and profitably operate complex oil and gas resources to help meet the global demand for energy;

 

developing and industrializing solar, biomass and carbon capture and storage technologies to help prepare for future energy needs;

 

developing practical, innovative and competitive materials that meet customers’ specific needs, contribute to the emergence of new features and systems, enable current materials to be replaced by materials showing higher performance for users, and address the challenges of improved energy efficiency, lower environmental impact and toxicity, better management of their life cycle and waste recovery;

 

developing, industrializing and improving first-level competitive processes for the conversion of oil, coal and biomass resources to adapt to changes in resources and markets, improve reliability and safety, achieve better energy efficiency, reduce the

   

environmental footprint and maintain the Group’s economic margins in the long term;

 

understanding and measuring the impacts of the Group’s operations and products on ecosystems (water, soil, air, biodiversity) to improve environmental safety, in conformity with existing regulation, and reduce the Group’s environmental footprint to achieve sustainability in its operations; and

 

mastering and using innovative technologies such as biotechnologies, materials sciences, nanotechnologies, high-performance computing, information and communications technologies and new analytic techniques.

The Group intends to increase R&D in all of its business units through cross-functional themes and technologies. Attention is paid to synergies of R&D efforts between business units.

The Group has twenty-two R&D sites worldwide and has developed approximately 600 partnerships with other industrial groups and academic or highly specialized research institutes. TOTAL also has a permanently renewed network of scientific advisors worldwide that monitor and advise on matters of interest to the Group’s R&D activities. Long-term partnerships with universities and academic laboratories deemed strategic in Europe, the United States, Japan and China, as well as innovative small businesses, are part of the Group’s approach.

Each business unit is actively developing its intellectual property policy in order to protect its innovations, to permit its activity to develop without constraints and to facilite its partnerships. In 2011, more than 250 new patent applications were issued by the Group.

 

 

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

DIRECTORS AND SENIOR MANAGEMENT

 

Composition of the Board of Directors

Directors are appointed by the shareholders for a 3-year term (Article 11 of the Company’s by-laws).

In case of the resignation or death of a director between two Shareholders’ Meetings, the Board may temporarily appoint a replacement director. This appointment must be ratified by the next Shareholders’ Meeting. The terms of office of the members of the Board are staggered to more evenly space the renewal of appointments.

The Board of Directors appoints the Chairman of the Board from among its members. The Board of Directors also appoints the Chief Executive Officer who may or may not be a member of the Board.

As of December 31, 2011, the Board of Directors had fifteen members, including one director appointed by the shareholders to represent employee shareholders. Twelve of the members of the Board were independent.

 

81


Table of Contents

The following individuals were members of the Board of Directors of TOTAL S.A. (information as of December 31, 2011(1)):

 

 

 

Christophe de Margerie

Born on August 6, 1951 (French).

Mr. de Margerie joined the Group after graduating from the École Supérieure de Commerce in Paris in 1974. He served in several positions in the Group’s Finance Department and Exploration & Production division. In 1995, he was appointed President of Total Middle East. In May 1999, he joined the Executive Committee as President of the Exploration & Production division. He then became Senior Executive Vice President of Exploration & Production of the new TotalFinaElf group in 2000. In January 2002, he became President of the Exploration & Production division of TOTAL. He was appointed a member of the Board of Directors by the Shareholders’ Meeting held on May 12, 2006 and became Chief

Executive Officer of TOTAL on February 14, 2007. On May 21, 2010, he was appointed Chairman and Chief Executive Officer of TOTAL.

Director of TOTAL S.A. since 2006 — Last renewal: May 15, 2009 until 2012.

Chairman of the Strategic Committee.

Holds 105,556 TOTAL shares and 53,869 shares of the “TOTAL ACTIONNARIAT FRANCE” collective investment fund.

Principal other directorships

 

 

Member of the Supervisory Board of Vivendi*

 

Manager of CDM Patrimonial SARL

 

 

 

 

Thierry Desmarest

Born on December 18, 1945 (French).

A graduate of the École Polytechnique and an Engineer of the French Corps des Mines, Mr. Desmarest served as Director of Mines and Geology in New Caledonia, then as technical advisor at the Offices of the Minister of Industry and the Minister of Economy. He joined TOTAL in 1981, where he held various management positions, then served as President of Exploration & Production until 1995. He served as Chairman and Chief Executive Officer of TOTAL from May 1995 until February 2007, and then as Chairman of the Board of TOTAL until May 21, 2010. He was appointed Honorary Chairman and remains a director of TOTAL and Chairman of the TOTAL Foundation.

Director of TOTAL S.A. since 1995 — Last renewal: May 21, 2010 until 2013.

Chairman of the Nominating & Governance Committee, member of the Compensation Committee and the Strategic Committee.

Holds 186,576 shares in full and 144,000 shares by usufruct.

Principal other directorships

 

 

Director of Sanofi*(2)

 

Director of Air Liquide*

 

Director of Renault S.A.*

 

Director of Renault S.A.S.

 

Director of Bombardier Inc. (Canada)*

 

 

 

 

 

(1) As of May 13, 2011, the directorships of Bertrand Jacquillat and Lord Levene of Portsoken expired.
(2) Non-consolidated company which was removed from the Company’s scope of consolidation on July 1, 2010.
* Company names marked with an asterisk are publicly listed companies.
Underlined companies are companies excluded from the group in which the director has his or her main duties.

 

82


Table of Contents

Patrick Artus

Born on October 14, 1951 (French).

Independent director.

A graduate from the École Polytechnique, the École Nationale de la Statistique et de l’Administration de l’Économie (ENSAE) and the Institut d’Études Politiques de Paris, Mr. Artus began his career at the INSEE (French National Institute for Statistics and Economic Studies) where his work included economic forecasting and modeling. He then worked at the Economics Department of the OECD (1980), later becoming the Head of Research at the ENSAE from 1982 to 1985. He was scientific adviser

at the research department of the Banque de France, before joining the Natixis Group as the head of the research department. He is an associate professor at the University of Paris I, Sorbonne. He is also a member of the council of economic advisors to the French Prime Minister and of the Cercle des Economistes.

Director of TOTAL S.A. since May 15, 2009 and until 2012.

Member of the Compensation Committee.

Holds 1,000 shares.

Principal other directorships

 

 

Director of IPSOS

 

 

 

 

Patricia Barbizet

Born on April 17, 1955 (French).

Independent director.

A graduate of the École Supérieure de Commerce of Paris in 1976, Ms. Barbizet started her career in the Renault Group as the Treasurer of Renault Véhicules Industriels and Chief Financial Officer of Renault Crédit International. She joined the Pinault group in 1989 as the Chief Financial Officer. In 1992, she became the Chief Executive Officer of Financière Pinault. She was the President of the Supervisory Board of the Pinault Printemps Redoute group until May 2005 and became Vice-President of the Board of Directors of PPR in May 2005. Patricia Barbizet is also a member of the Board of Directors of TOTAL, TF1, Air France-KLM and Fonds stratégique d’investissement.

Director of TOTAL S.A. since 2008 — Last renewal: May 13, 2011 and until 2014.

Chairperson of the Audit Committee and member of the Strategic Committee.

Holds 1,000 shares.

Principal other directorships

 

 

Vice Chairman of PPR* Board

 

Chief Executive Officer and Director of Artémis

 

Chief Executive Officer (non-Director) of Financière Pinault

 

Director and Deputy Chief Executive Officer of Société Nouvelle du Théâtre Marigny

 

Permanent representative of Artémis at the Board of Directors of Agefi

 

Permanent representative of Artémis at the Board of Directors of Sebdo le Point

 

Member of the Management Board of Château Latour (SCI)

 

Chief Member of the Supervisory Board of Yves Saint Laurent

 

Administratore Delagato and administratore of Palazzo Grazzi

 

Non-executive Director of Tawa Plc*

 

Chairman of the Board of Directors of Christie’s International Plc

 

Board member of Gucci Group N.V.

 

Director of Air France-KLM*

 

Director of Bouygues*

 

Director of TF1*

 

Director Fonds stratégique d’investissement (French government sovereign fund)

 

 

 

 

 

* Company names marked with an asterisk are publicly listed companies.
Underlined companies are companies excluded from the group in which the director has his or her main duties.

 

83


Table of Contents

 

Daniel Bouton

Born on April 10, 1950 (French).

Independent director.

Inspector General of Finance, Mr. Bouton has held various positions within the French Ministry of Economy. He served as Budget Director at the Ministry of Finance from 1988 to 1990. He joined Société Générale in 1991, where he was appointed Chief Executive Officer in 1993, then Chairman and Chief Executive Officer in November 1997. He served

as Chairman of the Société Générale group until May 12, 2008 and has been the Honorary Chairman since May 6, 2009.

Director of TOTAL S.A. since 1997 — Last renewal: May 15, 2009 until 2012.

Holds 3,200 shares.

Principal other directorships

 

 

Director of Veolia Environnement*

 

 

 

 

 

Gunnar Brock

Born on April 12, 1950 (Swedish).

Independent director.

Graduated from the Stockholm School of Economics with an MBA grade in Economics and Business Administration, Mr. Brock held various international positions at Tetra Pak. He served as Chief Executive Officer of Alfa Laval from 1992 to 1994 and as Chief Executive Officer of Tetra Pak from 1994 to 2000. After serving as Chief Executive Officer of Thule International, he was appointed Chief Executive Officer of Atlas Copco AB from 2002 to 2009. He is currently Chairman of the Board of Stora Enso Oy. Mr. Brock is also a member of the Royal Swedish

Academy of Engineering Sciences and of the Board of Directors of the Stockholm School of Economics.

Director of TOTAL S.A. since May 21, 2010 and until 2013.

Member of the Strategic Committee.

Holds 1,000 shares.

Principal other directorships

 

 

Chairman of the Board of Stora Enso Oy

 

Chairman of the Board of Mölnlycke Health Care Group

 

Member of the Board of Investor AB

 

Chairman of the Board of Rolling Optics

 

Member of the Board of Stena AB*

 

 

 

 

Claude Clément

Born on November 17, 1956 (French).

Mr. Clément joined the Group in February 1977 and started his career at Compagnie Française de Raffinage, which offered him professional training. He held various positions at the Refining Manufacturing Department in French and African refineries (Gabon, Cameroon). He is currently Manager of the Refining Manufacturing Methods at the Refining Manufacturing Division. Mr. Clément has been an elected member of the Supervisory Board of the “TOTAL ACTIONNARIAT FRANCE” collective investment

fund since 2009, an elected member of the Supervisor Board of the “TOTAL ACTIONS EUROPÉENNES”, “TOTAL DIVERSIFIE A DOMINANTE ACTIONS” and “TOTAL ÉPARGNE SOLIDAIRE” collective investment funds since 2010 and an elected member of the Supervisor Board of the “TOTAL DIVERSIFIÉ A DOMINANTE OBLIGATIONS”, “TOTAL MONETAIRE” and “TOTAL OBLIGATIONS” collective investment funds since 2010.

Director of TOTAL S.A. since May 21, 2010 and until 2013.

Holds 820 TOTAL shares and 3,442 shares of the “TOTAL ACTIONNARIAT FRANCE” collective investment fund.

 

 

 

 

 

* Company names marked with an asterisk are publicly listed companies.
Underlined companies are companies excluded from the group in which the director has his or her main duties.

 

84


Table of Contents

Marie-Christine Coisne-Roquette

Born on November 4, 1956 (French).

Independent director.

A graduate of the University of Paris X Nanterre (law and English) and admitted to the Paris and New York Bar Associations in 1980, Ms. Coisne-Roquette worked as an attorney in Paris and New York until 1988, when she joined the family-owned Sonepar group. From 1988 to 1998, while also serving as Chief Executive Officer of the family-owned Colam Entreprendre holding company, she held several consecutive operational directorships at Sonepar S.A., where she was appointed Chairman of the Board in 1998. She has served as Chairman and Chief Executive Officer of Sonepar since 2002. A member of the Executive Board of MEDEF since 2000, Ms. Coisne-Roquette has chaired that organization’s Tax Commission since 2005.

Director of TOTAL S.A. since May 13, 2011 and until 2014.

Member of the Audit Committee since May 13, 2011.

Holds 1,130 shares.

Principal other directorships

 

 

Chairperson and Chief Executive Officer of Sonepar S.A.

 

Chairman and Chief Executive Officer of Colam Entreprendre

 

Director of Hagemeyer Canada, Inc.

 

President of the Supervisory Board of OTRA N.V.

 

Director of Sonepar Canada, Inc.

 

President of the Supervisory Board of Sonepar Deutschland GmbH

 

Director of de Sonepar Ibérica

 

Director of de Sonepar Italia Holding

 

Chairperson of the Board of Directors of Sonepar Mexico

 

Member of the Supervisory Board of Sonepar Nederland B.V.

 

Director of Sonepar USA Holdings, Inc.

 

Director of Feljas and Masson SAS

 

Permanent representative of Colam Entreprendre, member of the Board of Directors at Cabus & Raulot (S.A.S.)

 

Permanent representative of Colam Entreprendre and Sonepar, co-administrators of Sonedis (société civile)

 

Permanent representative of Sonepar, Director of Sonepar France

 

Permanent representative of Sonepar, President of Sonepar International (S.A.S.)

 

Permanent representative of Colam Entreprendre, Director of Sovemarco Europe (S.A.)

 

Co-manager of Développement Mobilier & Industriel (D.M.I.) (société civile)

 

Manager of Ker Coro (société civile immobilière)

 

 

 

 

Bertrand Collomb

Born on August 14, 1942 (French).

Independent director.

A graduate of the École Polytechnique and a member of France’s engineering Corps des Mines, Mr. Collomb held a number of positions within the Ministry of Industry and other cabinet positions from 1966 to 1975. He joined the Lafarge group in 1975, where he served in various management positions. He served as Chairman and Chief Executive Officer of Lafarge from 1989 to 2003, then as Chairman of the Lafarge Board of Directors from 2003 to 2007, and has been the Honorary Chairman since 2007.

He is also Chairman of the Institut des Hautes Études pour la Science et la Technologie (IHEST) and a Board member of the Institut Européen de la Technologie.

Director of TOTAL S.A. since 2000 — Last renewal: May 15, 2009 until 2012.

Member of the Compensation Committee and the Nominating & Governance Committee.

Holds 4,712 shares.

Principal other directorships

 

 

Director of Lafarge*

 

Director of DuPont* (United States)

 

Director of Atco* (Canada)

 

 

 

 

 

 

* Company names marked with an asterisk are publicly listed companies.
Underlined companies are companies excluded from the group in which the director has his or her main duties.

 

85


Table of Contents

Paul Desmarais Jr.(1)

Born on July 3, 1954 (Canadian).

Independent director.

A graduate of McGill University in Montreal and INSEAD in Fontainebleau, Mr. Desmarais was elected Vice Chairman (1984) then Chairman of the Board (1990) of Corporation

Financière Power, a company he helped to found. Since 1996, he has served as Chairman of the Board and Co-Chief Executive Officer of Power Corporation of Canada.

Director of TOTAL S.A. since 2002 — Last renewal: May 13, 2011 until 2014.

Holds 2,000 ADRs (corresponding to 2,000 shares).

 

 

Principal other directorships

 

 

Chairman of the Board, Co-Chief Executive Officer and Member of the Executive Committee of Power Corporation of Canada*

 

Co-Chairman of the Board and member of the Executive Committee of Corporation Financière Power* (Canada)

 

Vice Chairman and Acting Managing Director of Pargesa Holding S.A.* (Switzerland)

 

Director and member of the Executive Committee of La Great-West Compagnie d’assurance-vie (Canada)

 

Director and member of the Executive Committee of First Great-West Life & Annuity Insurance Company (United States)

 

Director and member of the Executive Committee of Great-West Lifeco Inc.* (Canada)

 

Director of Great West Financial (Canada) Inc. (Canada)

 

Director and member of the Permanent Committee of Groupe Bruxelles Lambert S.A.* (Belgium)

 

Director and member of the Executive Committee of Groupe Investors Inc. (Canada)

 

Director and member of the Executive Committee of Groupe d’assurance London Inc. (Canada)

 

Director and member of the Executive Committee of London Life, compagnie d’assurance-vie (Canada)

 

Director and member of the Executive Committee of Mackenzie Inc.

 

Director and Deputy Chairman of the Board of La Presse Ltée (Canada)

 

Director and Deputy Chairman of Gesca Ltée (Canada)

 

Director of GDF Suez*

 

Director of Lafarge*

 

Director and member of the Executive Committee of Compagnie d’Assurance du Canada sur la Vie (Canada)

 

Director and member of the Executive Committee of the Corporation Financière Canada Life (Canada)

 

Director and member of the Executive Committee of IGM Inc.* (Canada)

 

Director and Chairman of the Board of 171263 Canada Inc. (Canada)

 

Director of 152245 Canada Inc. (Canada)

 

Director of GWL&A Financial Inc. (United States)

 

Director of Great West Financial (Nova Scotia) Co. (Canada)

 

Director of First Great-West Life & Annuity Insurance Company (United States)

 

Director of Power Communications Inc.

 

Director and Vice Chairman of the Board of Power Corporation International

 

Director and member of the Executive Committee of Putnam Investments LLC

 

Member of the Supervisory Board of Power Financial Europe B.V.

 

Director of Canada Life Capital Corporation Inc. (Canada)

 

Director and member of the Executive Committee of The Canada Life Assurance Company of Canada (Canada)

 

Director and member of the Executive Committee of Crown Life Insurance Company (Canada)

 

Director and Deputy Chairman of the Board of Square Victoria Communications Group Inc.

 

Member of the Supervisory Board of Parjointco N.V.

 

 

 

 

 

 

(1) Mr. Desmarais Jr. is a director of Groupe Bruxelles Lambert, which acting in concert with Compagnie Nationale à Portefeuille, to the Company’s knowledge, owns 5.5% of the Company’s shares and 5.5% of the voting rights. Mr. Demarais Jr. disclaims beneficial ownership of such shares.
* Company names marked with an asterisk are publicly listed companies.
Underlined companies are companies excluded from the group in which the director has his or her main duties.

 

86


Table of Contents

Barbara Kux

Born on February 26, 1954 (Swiss).

Independent director.

Holder of an MBA (with honors) from INSEAD in Fontainebleau, Ms. Kux joined McKinsey & Company in 1984 as a Management Consultant, where she was responsible for strategic assignments for international groups. After serving as manager for development of emerging markets at ABB and then at Nestlé between 1989 and 1999, she was appointed Executive Director of Ford in Europe from 1999 to 2003. In 2003, Ms. Kux became a member of the Management Committee of the

Philips group and, starting in 2005, was in charge of sustainable development. Since 2008, she has been a member of the Management Board of Siemens AG. She is also responsible for sustainable development at the Group and is in charge of the Group’s supply chain.

Director of TOTAL S.A. since May 13, 2011 and until 2014.

Member of the Strategic Committee.

Holds 1,000 shares.

Principal other directorships

 

 

Member of the Management Board of Siemens AG*

 

 

 

 

Anne Lauvergeon

Born on August 2, 1959 (French).

Independent director.

Chief Mining Engineer and a graduate of the École Normale Supérieure with a doctorate in physical sciences, Ms. Lauvergeon held various positions in industry before becoming Deputy Chief of Staff in the Office of the President of the Republic in 1990. She joined Lazard Frères et Cie as Managing Partner in 1995. From 1997 to 1999, she was Executive Vice President and member of the Executive Committee of Alcatel, in charge of industrial partnerships and international affairs. Ms. Lauvergeon

served as Chairman of the Management Board of Areva from July 2001 to June 2011 and Chairman and Chief Executive Officer of Areva NC (formerly Cogema) from June 1999 to June 2011.

Director of TOTAL S.A. since 2000 — Last renewal: May 15, 2009 until 2012.

Member of the Strategic Committee.

Holds 2,000 shares.

Principal other directorships

 

 

Director of GDF Suez*

 

Director of Vodafone Group Plc*

 

 

 

 

Claude Mandil

Born on January 9, 1942 (French).

Independent director.

A graduate of the École Polytechnique and a General Engineer from France’s engineering school Corps des Mines, Mr. Mandil served as a Mining Engineer in the Lorraine and Bretagne regions. He then served as a Project Manager at the Délégation de l’Aménagement du Territoire et de l’Action Régionale (City and Department planning/DATAR) and as the Interdepartmental Head of Industry and Research and regional delegate of ANVAR. From 1981 to 1982, he served as the technical advisor on the staff of the Prime Minister, in charge of the industry, energy and research sectors. He was appointed Chief Executive Officer, then Chairman and Chief Executive Officer of the Institut de Développement Industriel (Industry Development Institute — IDI) until 1988. He was Chief Executive Officer of the Bureau de Recherches

Géologiques et Minières (BRGM) from 1988 to 1990. From 1990 to 1998, Mr. Mandil was Chief Executive Officer for Energy and Commodities at the French Industry Ministry and the first representative for France to the Management Board of the International Energy Agency (IEA). He served as Chairman of the IEA from 1997 to 1998. In 1998, he was appointed Deputy Chief Executive Officer of Gaz de France and, in April 2000, Chairman of the Institut Français du Pétrole (French Institute for Oil). From 2003 to 2007, he was the Executive Director of the EIA.

Director of TOTAL S.A. since 2008 — Last renewal: May 13, 2011 and until 2014.

Member of the Strategic Committee.

Holds 1,000 shares.

Principal other directorships

 

 

Director of Institut Veolia Environnement

 

Director of Schlumberger SBC Institute

 

 

 

 

 

 

* Company names marked with an asterisk are publicly listed companies.
Underlined companies are companies excluded from the group in which the director has his or her main duties.

 

87


Table of Contents

Michel Pébereau(1)

Born on January 23, 1942 (French).

Independent director.

Honorary Inspector General of Finance, Mr. Pébereau held various positions in the Ministry of Economy and Finance, before serving, from 1982 to 1993, as Chief Executive Officer and then as Chairman and Chief Executive Officer of Crédit Commercial de France (CCF). He was Chairman and Chief Executive Officer of BNP then BNP Paribas from 1993 to 2003, Chairman of the Board of Directors from 2003 to December 1, 2011, and is currently Honorary Chairman of BNP Paribas.

 

Director of TOTAL S.A. since 2000 — Last renewal: May 15, 2009 until 2012.

Chairman of the Compensation Committee and member of the Nominating & Governance Committee.

Holds 2,356 shares.

Principal other directorships

 

 

Director of BNP Paribas*

 

Director of Saint-Gobain*

 

Director of AXA*

 

Director of EADS N.V.*

 

Director of Pargesa Holding S.A.* (Switzerland)

 

Director of BNP Paribas Suisse

 

Member of the Supervisory Board of Banque marocaine pour le Commerce et l’Industrie*

 

Non-voting member (Censeur) of Galeries Lafayette

 

 

 

 

Thierry de Rudder(2)

Born on September 3, 1949 (Belgian and French).

Independent director.

A graduate of the Université de Genève in mathematics, the Université Libre de Bruxelles and Wharton (MBA), Mr. de Rudder served in various positions at Citibank from 1975 to 1986 before joining Groupe Bruxelles Lambert, where he was appointed Acting Managing Director.

Director of TOTAL S.A. since 1999 — Last renewal: May 21, 2010 until 2013.

Member of the Audit Committee and the Strategic Committee.

Holds 3,956 shares.

Principal other directorships

 

 

Acting Managing Director of Groupe Bruxelles Lambert*

 

Director of Brussels Securities (Belgium)

 

Director of GBL Treasury Center (Belgium)

 

Director of Sagerpar (Belgium)

 

Director of GBL Energy Sàrl (Luxembourg)

 

Director of GBL Verwaltung Sàrl (Luxembourg)

 

Director of GBL Verwaltung GmbH (Germany)

 

Director of Ergon Capital Partners (Belgium)

 

Director of Ergon Capital Partners II (Belgium)

 

Director of Ergon Capital Partners III (Belgium)

 

Director of GDF Suez*

 

Director of Lafarge*

 

Director of Electrabel

 

 

 

 

At the meeting held on January 12, 2012, the Board of Directors took note of the resignation of Mr. Thierry de Rudder from his position as a director as of the end of the Board meeting, and consequently decided to co-opt Mr. Gérard Lamarche to replace Mr. de Rudder for the

remaining term of his predecessor’s directorship until the Shareholders’ Meeting to be held in 2013 to approve the 2012 accounts. The nomination of Mr. Lamarche is subject to the ratification of the Shareholders’ general meeting on May 11, 2012.

 

 

 

(1) Mr. Pébereau is Honorary Chairman of BNP Paribas, which, to the Company’s knowledge, owns 0.2% of the Company’s shares and 0.2% of the voting rights. Mr. Pébereau is also a director of Pargesa Holding SA, part of Group Bruxelles Lambert, which acting in concert with Compagnie Nationale à Portefeuille, to the Company’s knowledge, owns 5.5% of the Company’s shares and 5.5% of the voting rights. Mr. Pébereau disclaims beneficial ownership of such shares.
(2) Mr. de Rudder was Acting Managing Director of Groupe Bruxelles Lambert which, acting in concert with Compagnie Nationale à Portefeuille and to the Company’s knowledge, owns 5.5% of the Company’s shares and 5.5% of the voting rights. Mr. de Rudder disclaims beneficial ownership of such shares. Since January 2012, Mr. Gérard Lamarche is Acting Managing Director of Groupe Bruxelles Lambert.
* Company names marked with an asterisk are publicly listed companies.
Underlined companies are companies excluded from the group in which the director has his or her main duties.

 

88


Table of Contents

Gérard Lamarche

Born July 15, 1961 (Belgian).

Independent director.

Mr. Lamarche graduated in economic science from Louvain-La-Neuve university and the INSEAD business school (Advanced Management Program for Suez Group Executives). He also followed the Global Leadership Series course of training at the Wharton International Forum in 1998-99. He started his career in 1983 with Deloitte Haskins & Sells in Belgium, before becoming a consultant in mergers and acquisitions in Holland in 1987. In 1988, Mr. Lamarche joined Société Générale de Belgique as an investment manager and management controller between 1989 and 1991, then as a consultant in strategic operations from 1992 to 1995. He joined Compagnie Financière de Suez as a project manager for the Chairman and Secretary of the Executive Committee (1995-1997), before taking part in the merger between Compagnie de Suez and Lyonnaise des Eaux, which became Suez Lyonnaise des Eaux (1997), and then being appointed as the acting Managing Director in charge of Planning, Management Control and Accounts. In 2000, Mr. Lamarche pursued his career in industry by joining

NALCO (the American subsidiary of the Suez group and the world leader in the treatment of industrial water) as the Director and Chief Executive Officer. In March 2004, he was appointed Chief Executive Officer in charge of Finance of the Suez group, before being appointed Senior Executive and Vice President in charge of Finance and member of the Management Committee and the Executive Committee of the GDF Suez group in July 2008. On April 12, 2011, Mr. Lamarche became a Director on the Board of Directors of Groupe Bruxelles Lambert (GBL). He has been the acting Managing Director since January 2012. Mr. Lamarche is also a Director of Legrand.

Director of TOTAL S.A. since 2012 — Nomination by cooptation: January 12, 2012 until 2013.

Member of the Audit Committee and the Strategic Committee.

Holds 1,575 shares.

Principal other directorships

 

 

Acting Managing Director and Director of Groupe Bruxelles Lambert*

 

Director and member of the Audit Committee of Legrand*

 

 

 

 

Other information

The Board noted the absence of potential conflicts between the Directors’ duties in the best interests of the Company and the private interests of its directors. To the Company’s knowledge, the members of the Board of TOTAL S.A. are not related by close family ties; there are no arrangements or agreements with clients or suppliers that facilitated their appointment; there is no service agreement binding a director of TOTAL S.A. to one of its subsidiary and providing for special benefits upon termination of such agreement.

The current members of the Board of Directors of the Company have informed the Company that they have not been convicted, have not been associated with a bankruptcy, receivership or liquidation, and have not been incriminated or publicly sanctioned or disqualified, as stipulated in item 14.1 of Annex I of EC Regulation 809/2004 of April 29, 2004.

At its meeting held on February 9, 2012, the Board of Directors decided to propose the renewal of the directorships of Ms. Lauvergeon and Messrs. de Margerie, Artus, Collomb, and Pébereau, which are due to expire. At

the general Shareholders’ meeting on May 11, 2012, the Board will also propose the nomination of a new independent director, Ms. Anne-Marie Idrac, who will place her expertise of the world of industry at the Board’s disposal and will broaden the representativeness and the diversity of the Board. If the resolution is approved by the Shareholders’ Meeting, the proportion of women sitting in the Board will be one-third.

Representative of the Worker’s Council: pursuant to Article L. 2323- 62 of the French Labor Code, members of the Worker’s Council attend, with consultative rights, all meetings of the Board. In compliance with the second paragraph of such article, since July 7, 2010, four members of the Worker’s Council attend Board meetings.

At its meeting on September 15, 2009, the Board of Directors appointed Mr. Charles Paris de Bollardière Secretary of the Board.

Director independence

At its meeting on February 9, 2012, the Board of Directors, on the recommendation of the Nominating & Governance Committee, reviewed the independence of the Company’s

 

 

 

* Company names marked with an asterisk are publicly listed companies.
Underlined companies are companies excluded from the group in which the director has his or her main duties.

 

89


Table of Contents

directors as of December 31, 2011. At the Committee’s suggestion, the Board considered that, pursuant to the AFEP-MEDEF Code, a director is independent when “he or she has no relationship of any kind with the Company, its Group or its Management, that may compromise the exercise of his or her freedom of judgment”.

For each director, this assessment relies on the independence criteria set forth in the AFEP-MEDEF Code as reminded hereafter:

 

 

not to be an employee or a director of the Company, or a Group company, and not having been in such a position for the previous five years;

 

not to be a director of a company in which the Company holds a directorship or in which an employee appointed as such or an executive director of the company is a director;

 

not to be a material customer, supplier, investment banker or commercial banker of the Company or Group and for which the Company or the Group is not a material part of their business;

 

not to be related by close family ties to a corporate executive officer;

 

not to have been an auditor of the Company within the previous five years;

 

not to have been a director of the Company for more than twelve years (upon expiry term of office during which the 12-year limit is reached).

The AFEP-MEDEF Code expressly stipulates that the Board can decide that the implementation of certain defined criteria is not relevant or induces an interpretation that is particular to the Company.

With regard to the criterion applying to twelve years of service, the AFEP-MEDEF code states that “the status of independent director due to the application of this criterion shall only be relinquished at the end of the directorship during which the 12-year period is exceeded”. Pursuant to the report of the Nominating & Governance Committee, on February 9, 2012, the Board observed that Mr. Bouton and Mr. de Rudder had exceeded twelve years of service on December 31, 2011. Since the directorships of Messrs. Bouton and de Rudder had been renewed before the twelve-year period expired, the Board decided that they can still be considered as independent directors, according to the AFEP-MEDEF code.

Concerning “material” relationships, as a client, supplier, investment or finance banker, between a director and the

Company, the Board deemed that the level of activity between Group companies and the bank at which one of its Directors is an officer, which is less than 0.1% of its net banking income and less than 5% of the Group’s overall assets, represents neither a material portion of the overall activity of such bank nor a material portion of the Group’s external financing. The Board concluded that Mr. Pébereau should be considered as independent.

Similarly, the Board of Directors deemed that the level of activity between Group companies and one of its suppliers, Stena AB, of which Mr. Brock is a director, which is less than 2.68% of Stena AB’s turnover, represents neither a material portion of the supplier’s overall activity nor a material portion of the Group’s purchasing. The Board concluded that Mr. Brock could be considered as an independent director.

Mmes. Barbizet, Coisne-Roquette, Kux and Lauvergeon and Messrs. Artus, Bouton, Brock, Collomb, Desmarais, Mandil, Pébereau and de Rudder were deemed to be independent directors.

80% of the directors were independent on December 31, 2011.

Moreover, the Board noted that the directorships of Ms. Lauvergeon and Messrs. Collomb and Pébereau will exceed twelve years on March 22, 2012 for Messrs. Collomb and Pébereau, and on May 25, 2012 for Ms. Lauvergeron, after the Shareholders’ meeting that will be invited to renew her directorship on May 11, 2012. The Board of Directors deemed that, for a company with a long-term activity and investment cycles of more than ten years, extended directorships and the corresponding experience represent an asset for the Group and a means of consolidating the independence of judgment of its Directors. The Board concluded that the proposal to renew the directorships of Ms. Lauvergeon and Messrs. Collomb and Pébereau at the Shareholders meeting in May 11, 2012, does not call their independence into question, according to the AFEP-MEDEF code, in view of their independence of judgment.

In addition, the Board of Directors has examined the situations of the directors whose nomination or ratification will be submitted to the Shareholders’ meeting on May 11, 2012. Ms. Idrac and Mr. Lamarche are deemed to be independent directors.

 

 

90


Table of Contents

General Management

Management form

Based on the recommendation by the Nominating & Governance Committee, the Board of Directors decided at its meeting on May 21, 2010 to reunify the positions of Chairman of the Board and Chief Executive Officer and appoint the Chief Executive Officer to the position of Chairman of the Board until its term of office expires, that is until the Shareholders’ Meeting called to approve the financial statements for the fiscal year 2011.

As a result, Mr. de Margerie has been appointed Chairman and Chief Executive Officer of TOTAL S.A. since May 21, 2010.

The Board of Directors deemed that the unified management form was the most appropriate to the Group’s business and specificities of the oil and gas sector. This decision was made taking into account the advantage of the unified management and the composition of the Committees of the Board that comprise a significant portion of independent directors, which ensures balanced authority.

The management form selected shall remain in effect until a decision to the contrary is made by the Board of Directors.

The Executive Committee

The Executive Committee, under the responsibility of the Chairman and Chief Executive Officer, is the decision-making body of the Group.

It implements the strategy formulated by the Board of Directors and authorizes related investments, subject to the approval by the Board of Directors for investments exceeding 3% of the Group’s equity or the notification of the Board for investments exceeding 1% of equity.

As of December 31, 2011, the members of TOTAL’s Executive Committee were as follows:

 

 

Christophe de Margerie, Chairman of the Executive Committee (Chairman and Chief Executive Officer);

 

François Cornélis, Vice Chairman of the Executive Committee (President of the Chemicals division);

 

Michel Bénézit (President of the Refining & Marketing division);

 

Yves-Louis Darricarrère (President of the Exploration & Production division);

 

Jean-Jacques Guilbaud (Chief Administrative Officer); and

 

Patrick de La Chevardière (Chief Financial Officer).

 

In the context of the reorganization of its Downstream and Chemicals segments, TOTAL’s Executive Committee was changed on January 1, 2012. As of that date, the members of TOTAL’s Executive Committee are:

 

 

Christophe de Margerie, Chairman of the Executive Committee (Chairman and Chief Executive Officer);

 

Philippe Boisseau (President of the Supply & Marketing segment);

 

Yves-Louis Darricarrère (President of the Exploration & Production division and Gas & Power division);

 

Jean-Jacques Guilbaud (Chief Administrative Officer);

 

Patrick de La Chevardière (Chief Financial Officer); and

 

Patrick Pouyanné (President of the Refining & Chemicals segment).

The Management Committee

The Management Committee facilitates coordination among the different entities of the Group and monitors the operating results of the operational divisions and the activity reports of the functional divisions.

In addition to the members of the Executive Committee, the following twenty-two individuals from various operating divisions and non-operating departments served as members of the Management Committee as of December 31, 2011:

 

 

Corporate: René Chappaz, Peter Herbel, Jean-Marc Jaubert, Manoelle Lepoutre, Jean-François Minster, Jean-Jacques Mosconi, Jacques-Emmanuel Saulnier, François Viaud;

 

Upstream: Marc Blaizot, Philippe Boisseau, Arnaud Breuillac, Michel Hourcard, Jacques Marraud des Grottes;

 

Downstream: Pierre Barbé, Alain Champeaux, Bertrand Deroubaix, Eric de Menten, André Tricoire; and

 

Chemicals: Françoise Leroy, Jacques Maigné, Bernard Pinatel, Patrick Pouyanné.

In addition to the members of the Executive Committee, the following twenty-five individuals from various operating divisions and non-operating departments served as members of the Management Committee as of January 16, 2012:

 

 

Corporate: René Chappaz, Peter Herbel, Jean-Marc Jaubert, Helle Kristoffersen, Manoelle Lepoutre, Françoise Leroy, Jean-François Minster, Jacques-Emmanuel Saulnier, François Viaud;

 

Upstream: Marc Blaizot, Arnaud Breuillac, Olivier Cleret de Langavant, Isabelle Gaildraud, Michel Hourcard, Jacques Marraud des Grottes;

 

 

91


Table of Contents
 

Refining & Chemicals: Pierre Barbé, Bertrand Deroubaix, Jacques Maigné, Jean-Jacques Mosconi, Bernard Pinatel, Bernadette Spinoy; and

 

Supply & Marketing: Benoît Luc, Momar Nguer, Jérôme Paré, Jérôme Schmitt.

In addition, Jérôme Schmitt served as the Group’s Treasurer until January 1, 2012. Effective January 2, 2012, Humbert de Wendel is the Group’s Treasurer.

 

 

COMPENSATION

 

 

Board Compensation

The overall amount of directors’ fees allocated to members of the Board of Directors was set at 1.1 million for each fiscal year by the Shareholders’ Meeting on May 11, 2007.

In 2011, the overall amount of directors’ fees allocated to the members of the Board of Directors was 1.07 million, noting that there were fifteen directors as of December 31, 2011, as at year-end 2010.

The allocation of the overall amount of fees for 2011 remains based on an allocation scheme comprised of fixed compensation and variable compensation based on fixed amounts per meeting, which made it possible to take into account each director’s actual attendance at the meetings of the Board of Directors and its Committees.

To take into account the creation of the Strategic Committee, the Board of Directors decided at its meeting of October 27, 2011, to set out the allocation of fees and the fixed and variable amounts per meeting as follows:

 

 

a fixed amount of 20,000 is to be paid to each director (calculated prorata temporis in case of a change during the period), apart from the Chairman of the Audit Committee, who is to be paid 30,000 and the other Audit Committee members, who are to be paid 25,000;

 

an amount of 5,000 per director for each Board of Directors’ meeting actually attended;

 

an amount of 3,500 per director for each Compensation Committee, Nominating & Governance Committee or Strategic Committee meeting actually attended;

 

an amount of 7,000 per director for each Audit Committee meeting actually attended;

 

a premium of 2,000 for travel from a country outside of France to attend a Board of Directors or Committee meeting;

 

the Chairman and Chief Executive Officer does not receive directors’ fees as director of TOTAL S.A. or any other company of the Group.

See the table “Directors’ Fees and Other Compensation Received by Directors” below for additional compensation information.

Policy for determining the compensation and other benefits of the corporate executive officers

Based on a proposal by the Compensation Committee, the Board adopted the following policy for determining the compensation and other benefits of the corporate executive officers (the Chairman and the Chief Executive Officer):

 

 

Compensation and benefits for the Chairman and the Chief Executive Officer are set by the Board of Directors after considering proposals from the Compensation Committee. Such compensation shall be reasonable and fair, in a context that values both teamwork and motivation within the Company.

Compensation for the Chairman and the Chief Executive Officer is related to market practice, work performed, results obtained and responsibilities held.

 

 

Compensation for the Chairman and the Chief Executive Officer includes both a fixed portion and a variable portion. The fixed portion is reviewed at least every two years.

 

 

The amount of variable compensation is reviewed each year and may not exceed a stated percentage of fixed compensation. Variable compensation is determined based on pre-defined quantitative and qualitative criteria that are periodically reviewed by the Board of Directors. Quantitative criteria are limited in number, objective, measurable and adapted to the Group’s strategy.

Variable compensation is designed to reward short-term performance and progress towards medium-term objectives. The compensation is determined in line with the annual assessment of the performance of the Chairman and the Chief Executive Officer and the Company’s medium-term strategy.

The Board of Directors keeps track of the fixed and variable portions of the compensation of the Chairman and the Chief Executive Officer over several years and in light of the Company’s performance.

 

 

92


Table of Contents
 

The Group does not have a specific pension plan for the Chairman and the Chief Executive Officer. They are eligible for retirement benefits and pensions available to certain employee categories in the Group under conditions determined by the Board.

 

 

Stock options and performance shares are designed to align the long-term interests of the Chairman and the Chief Executive Officer with those of the shareholders.

The allocation of options and performance shares to the Chairman and the Chief Executive Officer is examined in the light of all the forms of compensation of each person.

The exercise price for stock options awarded is not discounted compared to the market price, at the time of the grant, for the underlying share.

Stock options and performance shares are awarded at regular intervals to prevent any opportunistic behavior.

The exercise of options and the definitive allocation of performance shares to which the Chairman and the Chief Executive Officer are entitled are subjected to performance criteria that must be met over several years.

The Board puts in place restrictions on the transfer of a portion of shares held upon the exercise of options and the definitive allocation of performance shares, applicable to the Chairman and the Chief Executive Officer until the end of their term of office.

The Chairman and the Chief Executive Officer may be entitled to stock options or performance shares when they leave office.

 

 

After three years in office, the Chairman and Chief Executive Officer are required to hold at least the number of Company shares set by the Board.

 

 

The components of the compensation of the Chairman and the Chief Executive Officer are made public after the meeting of the Board of Directors that approves them.

Compensation of the Chairman and Chief Executive Officer

The compensation paid to Mr. de Margerie for his duties as Chairman and Chief Executive Officer was set by the Board of Directors of TOTAL S.A., based on a

recommendation by the Compensation Committee in line with the guidance of the AFEP-MEDEF Corporate Governance Code.

It includes an annual fixed base salary of 1,500,000, and a variable portion not to exceed 165% of the fixed base salary. The fixed base salary was set by comparison with the compensation paid to the Chairman and Chief Executive Officer of other French companies included in the CAC 40 index. The maximum percentage of the fixed base salary represented by the variable portion is based on equivalent practice at a reference sample of companies, including oil and gas companies.

The variable portion is based on criteria determined by the Board of Directors. The equivalent of up to 100% of the fixed base salary is linked to economic criteria, which varies on a straight-line basis to avoid threshold effects. The criteria based on the Chairman and Chief Executive Officer’s personal contribution account for an additional amount that cannot exceed 65% of the fixed base salary.

The economic criteria were selected so as to not only reward short-term performance in terms of return on investment for shareholders, but also the progress made by the Group toward medium-term objectives by comparison with data for the oil and gas industry as a whole. They include:

 

 

return on equity for a maximum of 50% of the base salary; and

 

the Company’s earnings performance compared with that of the four other major international oil companies that are its competitors(1), assessed by reference to the average growth over three years of two indicators, earnings per share and consolidated net income. Each indicator represents a maximum of 25% of the base salary.

The Chairman and Chief Executive Officer’s personal contribution is evaluated on the basis of objective, mainly operational criteria related to the Group’s business segments and established in line with its strategy, including health, safety and environment (HSE) performance and oil and gas production and reserves growth.

With respect to the fiscal year 2011, the Board of Directors at its meeting of February 9, 2012, after having found that

the Chairman and Chief Executive Officer’s objectives related to personal contribution were deemed to be substantially fulfilled and assessed to what extent financial performance criteria had been met, the Board set the

 

 

 

(1) ExxonMobil, BP, Shell and Chevron.

 

93


Table of Contents

variable portion payable to Mr. de Margerie in 2012 at 1,530,000 for his contribution in 2011, equivalent to 102% of his fixed base salary.

The total gross compensation paid to Mr. de Margerie in his role as Chairman and Chief Executive Officer was made up of a fixed base salary of 1,500,000 and a variable portion of 1,530,000 for the 2011 fiscal year, to be paid in 2012.

Mr. de Margerie’s total gross compensation as Chief Executive Officer for the period between January 1, 2010 and May 21, 2010 was 1,030,359, composed of a fixed base salary of 507,097 and a variable portion of 523,262 paid in 2011. Mr. de Margerie’s total gross compensation as Chairman and Chief Executive Officer for the period between May 22, 2010 and December 31, 2010 was 1,977,763, composed of a fixed base salary of 919,355 and a variable portion of 1,058,408 paid in 2011.

As Chairman and Chief Executive Officer, Mr. de Margerie has the use of a company car, receives the health coverage provided for Group employees and is eligible for the life insurance plan open to the Group’s executive officers (see “— Pensions and other commitments” below).

See the tables “Summary of compensation, stock options and performance shares awarded to the Chairman and Chief Executive Officer” and “Chairman and the Chief Executive Officer’s compensation” below for additional compensation information.

Executive officer compensation

In 2011, the aggregate amount paid directly or indirectly by the French and foreign companies belonging to the Group of the Company as compensation to the executive officers of TOTAL in office at December 31, 2011 (members of the Management Committee and the Treasurer) as a group was 20.4 million (twenty-nine individuals), including 9 million paid to the six members of the Executive Committee. Variable compensation accounted for 42.4% of the aggregate amount of 20.4 million paid to executive officers.

Pensions and other commitments

 

1) Pursuant to applicable law, the Chairman and Chief Executive Officer is eligible for the basic French social security pension and for pension benefits under the ARRCO (Association pour le Régime de Retraite Complémentaire des Salariés) and AGIRC (Association Générale des Institutions de Retraite des Cadres) government-sponsored supplementary pension schemes. He also participates in the internal defined
  contribution pension plan and the defined benefit supplementary pension plan, known as RECOSUP, created by the Company. This supplementary pension plan, which is not limited to the Chairman and Chief Executive Officer, is described in point 2 below.

The sum of the supplementary pension plan benefits and external pension plan benefits may not exceed 45% of the compensation used as the calculation basis. In the event this percentage is exceeded, the supplementary pension is reduced accordingly.

The compensation taken into account when calculating the supplementary pension is the retiree’s final three-year average gross compensation (fixed and variable portions).

As of December 31, 2011, Mr. de Margerie’s aggregate benefit entitlement under all of the above pension plans would amount to 22.31% of his gross annual compensation received in 2011 (2011 fixed base salary and variable portion for 2010, paid in 2011).

 

2) The Chairman and Chief Executive Officer participates in a defined benefit supplementary pension plan financed and managed by TOTAL S.A. and open to all employees of the Group whose annual compensation is greater than eight times the ceiling for calculating French social security contributions (36,372 in 2012). Compensation above this amount does not qualify as pensionable compensation under either government-sponsored or contractual pension schemes.

To be eligible for this supplementary pension plan, participants must meet specific age and length of service criteria. They must also still be employed by the Company upon retirement, unless they retire due to disability or had taken early retirement at the Group’s initiative after the age of 55.

The plan provides participants with a pension equal to the sum of 1.8% of the portion of the reference compensation between eight and forty times the annual ceiling for calculating French social security contributions, and 1% of the reference compensation between forty and sixty times the annual ceiling for calculating French social security contributions, which is multiplied by the number of years of service (up to twenty years). It is adjusted in line with changes in the value of the ARRCO pension point and strictly capped as described in point 1 above.

As of December 31, 2011, the Group’s pension obligations to Mr. de Margerie under the defined

 

 

94


Table of Contents

benefit supplementary pension plan represented the equivalent of 18.01% of his gross annual compensation paid in 2011.

 

3) The Chairman and Chief Executive Officer is also entitled to a lump-sum retirement benefit equal to that available to eligible members of the Group under the French National Collective Bargaining Agreement for the Petroleum Industry. This benefit amounts to 25% of the gross annual compensation (fixed and variable portions) received in the 12-month period preceding retirement. Pursuant to the provisions of Article L. 225-42-1 of the French Commercial Code, such benefit is subject to the performance conditions detailed in point 7 below.

This retirement benefit cannot be combined with the compensation for loss of office described in point 5 below.

 

4) The Chairman and Chief Executive Officer also participates in the same life insurance plan as the Group’s employees, covering supplementary benefits or annuities in the event of temporary incapacity for work and disability, together with a life insurance plan funded by the Company and open to the executive officers of the Group. Upon death, the plan guarantees a payment equal to two years’ gross compensation (fixed and variable portions), increased to three years upon accidental death, as well as, in the event of disability, a payment proportional to the degree of disability.

 

5) If the Chairman and Chief Executive Officer is removed from office or his term of office is not renewed by the Company, he is entitled to compensation for loss of office equal to two years’ gross annual compensation. The calculation will be based on the gross compensation (including both fixed and variable portions) paid in the 12-month period preceding the termination or non-renewal of his term of office.

This compensation for loss of office to be paid in the event of a change of control or a change of strategy of the Company would not be due in cases of gross negligence or willful misconduct or if the Chairman and Chief Executive Officer leaves the Company of his own volition, accepts new responsibilities within the Group, or may claim full retirement benefits within a short time period.

Pursuant to the provisions of Article L. 225-42-1 of the French Commercial Code, this benefit is subject to the performance conditions detailed in point 7 below.

6) Commitments with regard to the pension and life insurance plans for the Chairman and Chief Executive Officer and the retirement benefit and compensation for loss of office arrangements set out in point 5 were approved on May 21, 2010, by the Board of Directors and by the Shareholders’ Meeting.

 

7) In addition, in compliance with Article L. 225-42-1 of the French Commercial Code, the commitments described in points 3 and 5 are subject to performance conditions that are deemed to be met if at least two of the following three criteria are satisfied:

 

   

the average ROE (return on equity) over the three years immediately preceding the year in which the officer retires is at least 12%;

   

the average ROACE (return on average capital employed) over the three years immediately preceding the year in which the officer retires is at least 10%;

   

TOTAL’s oil and gas production growth over the three years immediately preceding the year in which the officer retires is greater than or equal to the average production growth rate of the four other major international oil companies that are its competitors: ExxonMobil, Shell, BP and Chevron.

In compliance with the AFEP-MEDEF Corporate Governance Code, the Board of Directors decided that payment of the lump-sum retirement benefit or compensation for loss of office shall be subject to demanding performance conditions combining both internal and external performance criteria.

The three criteria were selected to take into account the Company’s general interest, shareholder interests and standard market practices, especially in the oil and gas industry.

More specifically, ROE enables the payment of the retirement benefit or compensation for loss of office to be tied to the Company’s overall shareholder return. Shareholders can use ROE to gauge the Company’s ability to generate profit from the capital they have invested and from prior years’ earnings reinvested in the Company.

ROACE is used by most oil and gas companies to assess the operational performance of average capital employed, regardless of whether it is funded by equity or debt. ROACE is an indicator of the return on capital employed by the Company for operational activities and, as a result, makes it possible to tie the payment of the retirement benefit or compensation for loss of office to the value created for the Company.

 

 

95


Table of Contents

The third and last criterion used by the Board of Directors is the Group’s oil and gas production growth compared with that of its competitors. This indicator is widely used in the industry to measure operational performance and the ability to ensure the sustainable development of the Group, most of whose capital expenditure is allocated to exploration and production activities.

 

8) In addition, regarding the implementation of the pension commitments described in points 1 and 2
  above made by the Company for directors for fiscal year 2011, the annual supplementary pension received by Mr. Desmarest in relation to his previous employment by the Group was approximately 562,354 (December 31, 2011 value), adjusted in line with changes in the value of the ARRCO pension point.

 

9) As of December 31, 2011, the total amount of the Group’s commitments under pension plans and similar for company officers is equal to 31.2 million.
 

 

Chairman and Chief Executive Officer Summary table at February 29, 2012    Employment

contract

   Retirement benefit and supplementary pension plans    Benefits or advantages due or likely to be due upon termination or change of office    Benefits related to a non-compete agreement

Christophe de Margerie

Chairman and Chief Executive Officer

Start of the office: February 2007(a)

Term of current office:

The Shareholders’ Meeting called in 2012 to approve the financial statements for the year ending December 31, 2011

   NO   

YES

(retirement benefit)(b)

(internal defined supplementary pension plan(c) and corporate RECOSUP defined contribution pension plan(d) also applicable to certain Group employees)

  

YES

(compensation for loss of office)(e)

   NO

 

(a) Chief Executive Officer since February 13, 2007, and Chairman and Chief Executive Officer since May 21, 2010.
(b) Payment subject to performance conditions in accordance with the decision of the Board of Directors on February 11, 2009, and confirmed by the Board of Directors on May 15, 2009 and May 21, 2010. Details of these commitments are set out in points 3 and 7 above. This retirement benefit cannot be combined with the compensation for loss of office described below.
(c) Representing an annual pension that would be equivalent, as of December 31, 2011, to 18.01% of the annual compensation for 2011.
(d) Mr. de Margerie’s pension benefit represented a booked expense of 2,121 for fiscal year 2011.
(e) Payment subject to performance conditions in accordance with the decision of the Board of Directors on February 11, 2009, and confirmed by the Board of Directors on May 15, 2009 and May 21, 2010. Details of these commitments are set out in points 5 and 7 above.

 

Stock options and performance share grants policy

General policy

Stock options and performance share grants put in place by TOTAL S.A. concern only TOTAL shares. No options for or grants of performance shares of any of the Group’s listed subsidiaries are awarded by TOTAL S.A.

All grants are approved by the Board of Directors, based on recommendations by the Compensation Committee. For each plan, the Compensation Committee recommends a list of beneficiaries, the conditions and the number of options or performance shares awarded to each beneficiary. The Board of Directors then gives final approval for this list and the grant conditions.

Stock options have a term of eight years, with an exercise price set at the average of the closing TOTAL share prices on Euronext Paris during the twenty trading days prior to the grant date, without any discount. The exercising of the options is subject to a presence condition and performance conditions (based on the return on equity

(ROE) of the Group) that vary depending on the plan and beneficiary category. As of 2011, all options granted are subject to performance conditions. Subject to the presence condition and applicable performance conditions being met, options may only be exercised after an initial two-year vesting period and the shares issued upon exercise are subject to a two-year mandatory holding period. However, for the 2007 to 2011 option plans, options awarded to beneficiaries employed by non-French subsidiaries at the grant date can be converted to bearer form or transferred after the 2-year vesting period at the end of which the options may be exercised.

Performance shares awarded under selective plans become final after a two-year vesting period, subject to a presence condition and a performance condition based on the return on equity (ROE) of the Group. At the end of this vesting period, and provided that the conditions set are satisfied, the performance share grants are finally awarded. However, these shares may not be transferred prior to the end of an additional two-year mandatory holding period. For beneficiaries employed by non-French subsidiaries on the grant date, the vesting period for performance shares

 

 

96


Table of Contents

may be increased to four years; in such cases, there would be no mandatory holding period. As of 2011, all performance shares granted to executive officers are subject to performance conditions.

The grant of these options or performance shares is used to extend, based upon individual performance assessments at the time of each plan, the Group-wide policy of developing employee shareholding (for further information, see “— Employees and Share Ownership — Arrangements for involving employees in the Company’s share capital” below).

Stock options and performance share grants to the Chairman and Chief Executive Officer are subject to specific performance conditions set out below.

Grants to the Chairman and Chief Executive Officer

The Chairman and Chief Executive Officer has been awarded share subscription options, the exercise of which has been subject, since 2007, to a presence condition and performance conditions based on the Group’s ROE and ROACE. The reasons for selecting these criteria are detailed in point 7 of “— Pensions and other commitments” above.

Pursuant to Article L. 225-185 of the French Commercial Code, the Board of Directors decided that, for the 2007 to 2011 share subscription option plans, the corporate officers (the Chairman of the Board and the Chief Executive Officer, and as from May 21, 2010 the Chairman and Chief Executive Officer) are required to hold for as long as they remain in office, a number of TOTAL shares representing 50% of the capital gains, net of tax and other deductions, resulting from the exercise of stock options under these plans. Once the Chairman and Chief Executive Officer holds a number of shares (directly or through collective investment funds invested in Company stock) corresponding to more than five times his current gross annual fixed compensation, this holding requirement will be reduced to 10%. If in the future this ratio is no longer met, the previous 50% holding requirement will once again apply.

As of 2011, the Chairman and Chief Executive Officer receives performance share grants, the final awarding of which is subject to a presence condition and performance conditions.

On the September 14, 2011 grant of TOTAL performance shares, the Board of Directors decided that the Chairman and Chief Executive Officer will have to hold for as long as he remains in office, 50% of the capital gains, net of tax and other deductions, from shares granted under performance share grant plans. Once the Chairman and

Chief Executive Officer holds a number of shares (directly or through collective investment funds invested in Company stock) corresponding to more than five times his gross annual fixed compensation at that time, this holding requirement will be reduced to 10%. If in the future this ratio is no longer met, the previous 50% holding requirement will once again apply.

In light of this holding requirement, the acquisition of the performance shares is not subject to an additional purchase of the Company’s shares.

The Chairman and Chief Executive Officer has given a commitment not to hedge the price risk on the TOTAL stock options and shares he has been granted to date, and on the shares he holds.

2011 share subscription option plan: The Board of Directors decided that, provided the presence condition within the Group is satisfied, the number of options finally granted to the Chairman and Chief Executive Officer will be subject to two performance conditions:

 

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROE of the Group. The average ROE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate is equal to zero if the average ROE is less than or equal to 7%, varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%, and is equal to 100% if the average ROE is more than or equal to 18%.

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROACE of the Group. The average ROACE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate is equal to zero if the average ROACE is less than or equal to 6%, varies on a straight-line basis between 0% and 100% if the average ROACE is more than 6% and less than 15%, and is equal to 100% if the average ROACE is more than or equal to 15%.

2010 share subscription option plan: The Board of Directors decided that, provided the presence condition within the Group is satisfied, the number of options finally granted to the Chairman and Chief Executive Officer will be subject to two performance conditions:

 

 

For 50% of the share subscription options granted, the performance condition states that the number of

 

 

97


Table of Contents
   

options finally granted is based on the average ROE of the Group. The average ROE is calculated by the Group based on TOTAL’s consolidated balance sheet and statement of income for fiscal years 2010 and 2011. The acquisition rate is equal to zero if the average ROE is less than or equal to 7%, varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%, and is equal to 100% if the average ROE is more than or equal to 18%.

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROACE of the Group calculated based on TOTAL’s consolidated balance sheet and statement of income for fiscal years 2010 and 2011. The acquisition rate is equal to zero if the average ROACE is less than or equal to 6%, varies on a straight-line basis between 0% and 100% if the average ROACE is more than 6% and less than 15%, and is equal to 100% if the average ROACE is more than or equal to 15%.

2009 share subscription option plan: The Board of Directors decided that, provided the presence condition within the Group is satisfied, the number of options finally granted to the Chief Executive Officer will be subject to two performance conditions:

 

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROE of the Group as published by TOTAL. The average ROE is calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2009 and 2010. The acquisition rate is equal to zero if the average ROE is less than or equal to 7%, varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%, and is equal to 100% if the average ROE is more than or equal to 18%.

 

For 50% of the share subscription options granted, the performance condition states that the number of options granted is related to the average ROACE of the Group as published by TOTAL. The average ROACE is calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2009 and 2010. The acquisition rate is equal to zero if the average ROACE is less than or equal to 6%, varies on a straight-line basis between 0% and 100% if the average ROACE is more than 6% and less than 15%, and is equal to 100% if the average ROACE is more than or equal to 15%.

 

The acquisition rate applicable to the subscription options that were subject to the performance condition of the 2009 Plan was 100%.

2011 performance share plan: The Board of Directors decided that, provided the presence condition within the Group is satisfied, the number of shares finally granted to the Chairman and Chief Executive Officer will be subject to two performance conditions:

 

 

For 50% of the shares granted, the performance condition states that the number of shares finally granted is based on the average ROE of the Group. The average ROE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate is equal to zero if the average ROE is less than or equal to 7%, varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%, and is equal to 100% if the average ROE is more than or equal to 18%.

 

For 50% of the shares granted, the performance condition states that the number of shares finally granted is based on the average ROACE of the Group. The average ROACE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate is equal to zero if the average ROACE is less than or equal to 6%, varies on a straight-line basis between 0% and 100% if the average ROACE is more than 6% and less than 15%, and is equal to 100% if the average ROACE is more than or equal to 15%.

The Chairman and Chief Executive Officer was not awarded any performance shares as part of the plans in the period 2006 to 2010.

Grants to employees

Share subscription option plans

2011 share subscription option plan: The Board of Directors decided that, provided the presence condition within the Group is satisfied, for each grantee other than the Chairman and Chief Executive Officer, the options will be finally granted to the beneficiary provided that the performance condition is fulfilled. The performance condition states that the number of options finally granted is based on the average of the ROE of the Group. The average ROE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

 

98


Table of Contents
 

varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

is equal to 100% if the average ROE is more than or equal to 18%.

2010 share subscription option plan: The Board of Directors decided that, provided the presence condition within the Group was satisfied:

 

 

for each grantee of up to 3,000 options, other than the Chairman and Chief Executive Officer, the options will be finally granted;

 

for each grantee of more than 3,000 options and less than or equal to 50,000 options (other than the Chairman and Chief Executive Officer):

   

the first 3,000 options and two-thirds of the options in excess of this number will be finally granted to their beneficiary;

   

the outstanding options, that is one-third of the options in excess of the first 3,000 options, will be granted provided that the performance condition described below is fulfilled;

 

for each grantee of more than 50,000 options, other than the Chairman and Chief Executive Officer:

   

the first 3,000 options, two-thirds of the options above the first 3,000 options and below the first 50,000 options, and one-third of the options in excess of the first 50,000 options, will be finally granted to their beneficiary;

   

the remaining options, that is one-third of the options above the first 3,000 options and below the first 50,000 options, and two-thirds of the options in excess of the first 50,000 options, will be finally granted provided that the performance condition is fulfilled.

This condition states that the number of options finally granted is based on the average ROE of the Group. The average ROE is calculated by the Group based on TOTAL’s consolidated balance sheet and statement of income for fiscal years 2010 and 2011. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

is equal to 100% if the average ROE is more than or equal to 18%.

2009 share subscription option plan: The Board of Directors decided that, provided the presence condition within the Group was met, for each beneficiary, other than the Chief Executive Officer, of more than 25,000 options, one-third of the options granted in excess of this number will be finally granted subject to a performance condition. This condition is based on the average ROE of the Group as published by TOTAL. The average ROE is calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2009 and 2010. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

is equal to 100% if the average ROE is more than or equal to 18%.

The acquisition rate applicable to the subscription options that were subject to the performance condition of the 2009 Plan was 100%.

Performance share plans

2011 performance share plan: The Board of Directors decided that, provided that the presence condition within the Group is satisfied, for executives officers(1) other than the Chairman and Chief Executive Officer, the number of shares finally granted will be subject to the performance condition set out below. This condition is based on the average ROE as published by the Group and calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2011 and 2012. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

is equal to 100% if the average ROE is more than or equal to 18%.

 

 

 

(1) Executive officers, excluding the Chairman and Chief Executive Officer, are employees other than directors.

 

99


Table of Contents

Furthermore, the Board of Directors decided that, for each beneficiary (other than the Chairman and Chief Executive Officer and the executive officers) of more than 100 shares, the shares in excess of this number will be finally granted subject to a performance condition. This condition is based on the average ROE as published by the Group and calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2011 and 2012. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

is equal to 100% if the average ROE is more than or equal to 18%.

2010 performance share plan: The Board of Directors decided that, provided that the presence condition within the Group is satisfied, for each beneficiary of more than 100 shares, half of the shares in excess of this number will be finally granted subject to a performance condition. This condition is based on the average ROE calculated by the Group based on TOTAL’s consolidated balance sheet and statement of income for fiscal years 2010 and 2011. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

is equal to 100% if the average ROE is more than or equal to 18%.

2009 performance share plan: The Board of Directors decided that, provided that the presence condition within the Group is satisfied, for each beneficiary of more than 100 shares, half of the shares in excess of this number will be finally granted subject to a performance condition. This condition is based on the average ROE of the Group as published by TOTAL. The average ROE is calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2009 and 2010. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

is equal to 100% if the average ROE is more than or equal to 18%.

Due to the application of the performance condition, the acquisition rate was 100% for the 2009 Plan.

In addition, the Board of Directors decided at its meeting of May 21, 2010 to implement a global free share plan intended for the Group’s employees, that is more than 100,000 employees. On June 30, 2010, rights to twenty-five free shares were granted to every employee. The shares are subject to a vesting period of two to four years depending on the case. The shares granted are not subject to any performance condition. They will be issued at the end of the vesting period.

 

 

SUMMARY OF COMPENSATION, STOCK OPTIONS AND PERFORMANCE SHARES AWARDED TO THE CHAIRMAN AND CHIEF EXECUTIVE OFFICER

 

For the year ended ()    2011      2010  

Christophe de Margerie

Chairman and Chief Executive Officer (since May 21, 2010)

     

Compensation due for fiscal year as Chairman and Chief Executive Officer(a)

     3,030,000         3,008,122   

In-kind benefits(b)

     6,991         6,908   

Value of options awarded(c)

     702,400         1,387,200   

Value of performance shares awarded(d)

     437,440           

Total

     4,176,831         4,402,230   

 

(a) Compensation detailed in the following table. For the 2010 fiscal year, Mr. de Margerie received compensation of 1,030,359 as Chief Executive Officer for the period from January 1 to May 21, 2010, and compensation of 1,977,763 as Chairman and Chief Executive Officer for the period from May 22 to December 31, 2010.
(b) Mr. de Margerie has the use of a company car; he receives the health coverage provided for Group employees and is eligible for the life insurance plan open to the Group’s executive officers (see “— Pensions and other commitments”).
(c) Options awarded in 2011 are detailed in the table “Stock options awarded in 2011 to the Chairman and Chief Executive Officer”. The value of options awarded was calculated on the day when they were awarded using the Black-Scholes model based on the assumptions used for the consolidated accounts (see Note 25 to the Consolidated Financial Statements).
(d) The value of performance shares was calculated on the day when they were awarded.

 

100


Table of Contents

CHAIRMAN AND CHIEF EXECUTIVE OFFICER’S COMPENSATION

 

      For the year ended 2011      For the year ended 2010  
For the year ended ()    Amount due     Amount paid(a)      Amount due     Amount paid(a)  

Christophe de Margerie

Chairman and Chief Executive Officer (since May 21, 2010)

         

Fixed compensation

     1,500,000        1,500,000         1,426,452 (b)      1,426,452 (b) 

Variable compensation(c)

     1,530,000        1,581 670         1,581,670 (d)      1,356,991   

Extraordinary compensation

                             

Directors’ fees

                             

In-kind benefits(e)

     6,991        6,991         6,908        6,908   

Total

     3,036,991        3,088,661         3,015,030        2,790,351   

 

(a) Variable portion paid for prior fiscal year. For more detailed information about these criteria, see “— Compensation of the Chairman and Chief Executive Officer”.
(b) Includes a fixed portion of 507,097 for the period between January 1 and May 21, 2010 and 919,355 for the period between May 22 and December 31, 2010.
(c) The variable portion for the Chairman and Chief Executive Officer is calculated by taking into account the Group’s return on equity during the relevant fiscal year, the Group’s earnings compared to those of the other major international oil companies that are its competitors as well as the Chairman and Chief Executive Officer’s personal contribution based on operational target criteria. The variable portion can reach a maximum amount of 165% of the fixed base salary. The objectives related to personal contribution were considered to have been substantially fulfilled.
(d) Including a variable portion of 523,262 for the period between January 1 to May 21 2010, and 1,058,408 for the period between May 22 and December 31, 2010.
(e) Mr. de Margerie has the use of a company car, receives the health coverage provided for Group employees and is eligible for the life insurance plan open to the Group’s executive officers (see “— Pensions and other commitments”).

DIRECTORS’ FEES AND OTHER COMPENSATION RECEIVED BY DIRECTORS

Total compensation (including in-kind benefits) paid to each director in the year indicated (Article L. 225-102-1 of the French Commercial Code, 1st and 2nd paragraphs):

 

Gross amount ()    2011     2010  

Christophe de Margerie(a)

     (b )      (b ) 

Thierry Desmarest (a)(b)

     639,854 (d)      1,604,039 (d) 

Patrick Artus(c)

     65,500        55,000   

Patricia Barbizet(a)

     115,500        107,000   

Daniel Bouton

     63,500        55,000   

Gunnar Brock(a)(e)

     75,500        39,328   

Claude Clément(e)

     156,365 (f)      127,929 (f) 

Marie-Christine Coisne-Roquette(g)

     48,460          

Bertrand Collomb

     72,500        71,000   

Paul Desmarais Jr.

     51,000        45,000   

Bertrand Jacquillat(h)

     55,040        95,000   

Barbara Kux(a)(i)

     26,770          

Anne Lauvergeon(a)

     63,500        45,000   

Peter Levene of Portsoken(j)

     19,230        79,000   

Claude Mandil(a)

     63,500        55,000   

Michel Pébereau

     77,500        71,000   

Thierry de Rudder(a)

     138,500        142,000   

 

(a) Member of the Strategic Committee.
(b) For the Chairman and Chief Executive Officer, see the summary compensation tables “Summary of compensation, stock options and performance shares awarded to the Chairman and Chief Executive Officer” and “Chairman and Chief Executive Officer’s compensation”. The Chairman and Chief Executive Officer did not receive any directors’ fees.
(c) Member of the Compensation Committee since May 21, 2010.
(d) Including for 2011, fees received (77,500) and pension benefits received (562,354), and including for 2010, fees received (39,328), fixed and variable compensation for his role as Chairman of the Board of Directors up to May 21, 2010 (751,407), the retirement benefit (492,963) and pension benefits received (320,341).
(e) Director since May 21, 2010.
(f) Including for 2011, the directors’ fees received, representing 58,500, as well as the compensation received from Total Raffinage Marketing (a subsidiary of TOTAL S.A.), representing 97,865 and including for 2010, directors’ fees received, representing 32,328 as well as the compensation received from Total Raffinage Marketing, representing 95,601.
(g) Director and member of the Audit Committee from May 13, 2011.
(h) Director and member of the Audit Committee until May 13, 2011.
(i) Director since May 13, 2011.
(j) Director until May 13, 2011.

 

101


Table of Contents

Over the past two years, the directors currently in office have not received any compensation or in-kind benefits from companies controlled by TOTAL S.A., except for Mr. Clément, who is an employee of Total Raffinage Marketing, and Mr. Desmarest, Chairman of the Board of Directors until May 21, 2010. The compensation indicated in the table above (except for that of the Chairman and Chief Executive Officer and Messrs. Desmarest and Clément) consists solely of directors’ fees (gross amount) paid during the relevant period. None of the directors have service contracts linking them to TOTAL S.A. or any of its subsidiaries that provide for benefits upon termination of employment.

STOCK OPTIONS AWARDED IN 2011 TO THE CHAIRMAN AND CHIEF EXECUTIVE OFFICER

The stock options awarded to the Chairman and Chief Executive Officer are detailed in the table “TOTAL stock options awarded to Mr. de Margerie, Chairman and Chief Executive Officer of TOTAL S.A.” below.

 

     Date of
Plan
    Type of
options
  Value of
options
()
(a)
    Number of
options
awarded
during
fiscal  year
(b)
    Exercise
price
    Exercise
period
    Performance
condition
Christophe de Margerie    

 

2011 Plan

09/14/2011

  

  

  Subscription
options
    702,400        160,000        33.00       
 
09/15/2013-
09/14/2019 
  
  
 

For 50% of the options, the condition is based on the average ROE for the Group’s 2011 and 2012 fiscal years. For 50% of the options, the condition is based on the average ROACE for the Group’s 2011 and 2012 fiscal years.

Chairman and Chief Executive Officer

                               

Total

                702,400        160,000                       

 

(a) The value of options awarded was calculated on the day they were awarded using the Black-Scholes model based on the assumptions used for the consolidated accounts (see Note 25 to the Consolidated Financial Statements).
(b) As part of the share subscription option plan awarded on September 14, 2011, the Board of Directors decided that, for the Chairman and Chief Executive Officer, the number of share subscription options that are likely to be exercised at the end of the two-year vesting period will be subject to performance conditions being met (see “— Grants to the Chairman and Chief Executive Officer”).

STOCK OPTIONS EXERCISED IN 2011 BY THE CHAIRMAN AND CHIEF EXECUTIVE OFFICER

The stock options awarded to the Chairman and Chief Executive Officer are detailed in the table “TOTAL stock options awarded to Mr. de Margerie, Chairman and Chief Executive Officer of TOTAL S.A.” below.

 

      Date of Plan    Number of options
exercised during
fiscal year
     Exercise
price ()
 

Christophe de Margerie

   2003 Plan      113,576         32.84   

Chairman and Chief Executive Officer

   07/16/2003                  

Total

          113,576            

 

102


Table of Contents

PERFORMANCE SHARES AWARDED IN 2011 TO THE CHAIRMAN AND

CHIEF EXECUTIVE OFFICER OR ANY DIRECTOR

 

      Date of
Plan
     Number of
shares
awarded
during
fiscal year
     Value of
shares ()
(a)
     Acquisition
date
     Availability
date
    

Performance

condition

Christophe de Margerie Chairman and Chief Executive Officer     
 
2011 Plan
09/14/2011
  
  
     16,000         437,440         09/15/2013         09/15/2015       For 50% of the shares, the condition is based on the average ROE for the Group’s 2011 and 2012 fiscal years. For 50% of the shares, the condition is based on the average ROACE for the Group’s 2011 and 2012 fiscal years.
Claude Clément Director representing employee shareholders     
 
2011 Plan
09/14/2011
  
  
     240         6,562         09/15/2013         09/15/2015       Shares in excess of the first 100 shares are subject to a condition based on the average ROE for the Group’s 2011 and 2012 fiscal years.
Total               16,240                                   

 

(a) The value of performance shares was calculated on the day when they were awarded.

PERFORMANCE SHARES FINALLY AWARDED IN 2011 FOR THE CHAIRMAN AND CHIEF EXECUTIVE OFFICER OR ANY DIRECTOR

 

      Date of Plan   

Number of shares

finally awarded during
fiscal year

     Acquisition
condition
 

Christophe de Margerie

   2009 Plan                

Chairman and Chief Executive Officer

   09/15/2009                  

Claude Clément

   2009 Plan           

Director representing employee shareholders

   09/15/2009                 

Total

                    

 

103


Table of Contents

TOTAL STOCK OPTION GRANTS

The following table gives a breakdown of stock options awarded by category of beneficiaries (main executive officers, other executive officers and other employees) for the plans in effect during 2011.

 

          Number of
beneficiaries
    Number
of options
awarded
(a)
    Percentage     Average
number of
options per
beneficiary
(a)
 

2003 Plan(b)(d):: Subscription options

  Main executive officers(c)     28        356,500        12.2     12,732   

Decision of the Board on July 16, 2003

  Other executive officers     319        749,206        25.5     2,349   

Exercise price: 133.20; discount: 0.0%

  Other employees     3,603        1,829,600        62.3     508   

Exercise price as of May 24, 2006: 32.84(a)

  Total     3,950        2,935,306        100     743   

2004 Plan(d): Subscription options

  Main executive officers(c)     30        423,500        12.6     14,117   

Decision of the Board on July 20, 2004

  Other executive officers     319        902,400        26.8     2,829   

Exercise price: 159.40; discount: 0.0%

  Other employees     3,997        2,039,730        60.6     510   

Exercise price as of May 24, 2006: 39.30(a)

  Total     4,346        3,365,630        100     774   

2005 Plan(d): Subscription options

  Main executive officers(c)     30        370,040        24.3     12,335   

Decision of the Board on July 19, 2005

  Other executive officers     330        574,140        37.6     1,740   

Exercise price: 198.90; discount: 0.0%

  Other employees     2,361        581,940        38.1     246   

Exercise price as of May 24, 2006: 49.04(a)

  Total     2,721        1,526,120        100     561   

2006 Plan(d): Subscription options

  Main executive officers(c)     28        1,447,000        25.3     51,679   

Decision of the Board on July 18, 2006

  Other executive officers     304        2,120,640        37.0     6,976   

Exercise price: 50.60; discount: 0.0%

  Other employees     2,253        2,159,600        37.7     959   
  Total     2,585        5,727,240        100     2,216   

2007 Plan(d)(e): Subscription options

  Main executive officers(c)     27        1,329,360        22.8     49,236   

Decision of the Board on July 17, 2007

  Other executive officers     298        2,162,270        37.1     7,256   

Exercise price: 60.10; discount: 0.0%

  Other employees     2,401        2,335,600        40.1     973   
  Total     2,726        5,827,230        100     2,138   

2008 Plan(d)(e)(f): Subscription options

  Main executive officers(c)     26        1,227,500        27.6     47,212   
Awarded on October 9, 2008, by decision of the Board of Directors on September 9, 2008  

Other executive officers

Other employees

   

 

298

1,690

  

  

   

 

1,988,420

1,233,890

  

  

   

 

44.7

27.7


   

 

6,673

730

  

  

Exercise price: 42.90; discount: 0.0%

  Total     2,014        4,449,810        100     2,209   

2009 Plan(d)(e)(g): Subscription options

  Main executive officers(c)     26        1,201,500        27.4     46,212   

Decision of the Board on September 15, 2009

  Other executive officers     284        1,825,540        41.6     6,428   

Exercise price: 39.90; discount: 0.0%

  Other employees     1,742        1,360,460        31.0     781   
  Total     2,052        4,387,500        100     2,138   

2010 Plan(d)(e): Subscription options

  Main executive officers(c)     25        1,348,100        28.2     53,924   

Decision of the Board on September 14, 2010

  Other executive officers     282        2,047,600        42.8     7,261   

Exercise price: 38.20; discount: 0.0%

  Other employees     1,790        1,392,720        29.0     778   
  Total     2,097        4,788,420        100     2,283   

2011 Plan(d)(e): Subscription options

  Main executive officers(c)     29        846,600        55.7     29,193   

Decision of the Board on September 14, 2011

  Other executive officers     177        672,240        44.3     3,798   

Exercise price: 33.00; discount: 0.0%

  Other employees                            
  Total     206        1,518,840        100     7,373   

 

(a) To take into account the spin-off of Arkema, pursuant to the provisions in effect on the date of the Shareholders’ Meeting on May 12, 2006, at its meeting of March 14, 2006, the Board of Directors resolved to adjust the rights of TOTAL stock options holders. For each plan and each holder, the exercise prices for TOTAL stock options were multiplied by 0.986147 and the number of unexercised stock options was multiplied by 1.014048 (and then rounded up), effective as of May 24, 2006. In addition, to take into account the four-for-one stock split approved by the Shareholders’ Meeting on May 12, 2006, the exercise price for stock options was divided by four and the number of unexercised stock options was multiplied by four. The presentation in this table of the number of options initially awarded has not been adjusted to reflect the four-for-one stock split.
(b) Certain employees of the Elf Aquitaine group in 1998 also benefited from the vesting of Elf Aquitaine options awarded in 1998 subject to performance conditions related to the Elf Aquitaine group from 1998 to 2002. These Elf Aquitaine plans expired on March 31, 2005.
(c) Members of the Management Committee and the Treasurer as of the date of the Board meeting awarding the options. Mr. Desmarest has not been a member of the Management Committee since February 14, 2007. Mr. Desmarest was awarded 110,000 options under the 2007 Plan and no options since 2008.
(d) The options are exercisable, subject to a presence condition, after a 2-year vesting period from the date of the Board meeting awarding the options and expire eight years after this date. The underlying shares may not be transferred during the 4-year period from the date of the Board meeting awarding the options (except for the 2008 Plan). The presence condition states that the termination of the employment contract will result in the employee losing the right to exercise the options.
(e) The 4-year transfer restriction period does not apply to employees of non-French subsidiaries as of the date of the grant, who may transfer the underlying shares after a 2-year period from the date of the grant.
(f) For the 2008 Plan, the options acquisition rate, linked to the performance condition, was 60%.
(g) For the 2009 Plan, the options acquisition rate, linked to the performance condition, was 100%.

 

104


Table of Contents

TOTAL STOCK OPTIONS AS OF DECEMBER 31, 2011

 

     2003 Plan     2004 Plan     2005 Plan     2006 Plan     2007 Plan     2008 Plan     2009 Plan     2010 Plan     2011 Plan     Total  
Type of options   Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
        

Date of the Shareholders’ Meeting

    05/17/2001        05/14/2004        05/14/2004        05/14/2004        05/11/2007        05/11/2007        05/11/2007        05/21/2010        05/21/2010     

Grant date(a)

    07/16/2003        07/20/2004        07/19/2005        07/18/2006        07/17/2007        10/09/2008        09/15/2009        09/14/2010        09/14/2011           

Total number of options awarded, including(b):

    11,741,224        13,462,520        6,104,480        5,727,240        5,937,230        4,449,810        4,387,500        4,788,420        1,518,840        58,117,264   

Directors(c)

    240,000        240,000        240,720        400,720        310,840        200,660        200,000        240,000        160,000        2,232,940   

 C. de Margerie

    n/a        n/a        n/a        160,000        200,000        200,000        200,000        240,000        160,000        1,160,000   

 C. Clément

    n/a        n/a        n/a        n/a        n/a        n/a        n/a                        

 D. Boeuf

    n/a               720        720        840        660               n/a        n/a        2,940   

 T. Desmarest

    240,000        240,000        240,000        240,000        110,000                             n/a        1,070,000   

Additional grant

           24,000        134,400                                                  158,400   

Adjustments related to the spin-off of Arkema(d)

    163,180        196,448        90,280                                                  449,908   

Date as of which the options may be exercised

    07/17/2005        07/21/2006        07/20/2007        07/19/2008        07/18/2009        10/10/2010        09/16/2011        09/15/2012        09/15/2013     

Expiry date

    07/16/2011        07/20/2012        07/19/2013        07/18/2014        07/17/2015        10/09/2016        09/15/2017        09/14/2018        09/14/2019     

Exercise price ()(e)

    32.84        39.30        49.04        50.60        60.10        42.90        39.90        38.20        33.00           

Cumulative number of options exercised as of December 31, 2011

    11,068,508        1,266,293        38,497        8,620               200        1,080        2,040        9,400     

Cumulative number of options canceled as of December 31, 2011

    835,896        322,151        128,127        95,114        86,865        113,912        28,740        86,337        1,000           

Number of options:

                   

 outstanding as of January 1, 2011

    5,734,444        12,338,847        6,178,856        5,640,886        5,866,445        4,349,158        4,371,890        4,787,300               49,267,826   

 awarded in 2011

                                                            1,518,840        1,518,840   

 canceled in 2011(f)(g)

    (738,534     (28,208     (16,320     (17,380     (16,080     (13,260     (14,090     (85,217     (1,000     (930,089

 exercised in 2011

    (4,995,910     (216,115                          (200            (2,040     (9,400     (5,223,665

 outstanding as of December 31, 2011

           12,094,524        6,162,536        5,623,506        5,850,365        4,335,698        4,357,800        4,700,043        1,508,440        44,632,912   

 

(a) The grant date is the date of the Board meeting awarding the options, except for the share subscription option plan of October 9, 2008, approved by the Board on September 9, 2008.
(b) The number of options awarded before May 23, 2006, has been multiplied by four to take into account the four-for-one stock split approved by the Shareholders’ Meeting on May 12, 2006.
(c) Options awarded to directors at the time of grant.
(d) Adjustments approved by the Board at its meeting on March 14, 2006, pursuant to the provisions in effect at the time of the Board meeting and at the time of the Shareholders’ Meeting on May 12, 2006, related to the spin-off of Arkema. These adjustments were made on May 22, 2006 effective as of May 24, 2006.
(e) Exercise price as of May 24, 2006. The exercise prices of TOTAL subscription shares under the plans in force at that date were multiplied by 0.25 to take into account the four-for-one stock split on May 18, 2006. Moreover, following the spin-off of Arkema, the exercise prices of TOTAL stock options under these plans were multiplied by an adjustment factor equal to 0.986147 effective as of May 24, 2006. The exercise prices effective before May 24, 2006 are given in Note 25, points A, B and C to the Consolidated Financial Statements.
(f) Out of the 930,089 options canceled in 2011, 738,534 options that were not exercised expired due to the expiry of the 2003 subscription option plan on July 16, 2011.
(g) The acquisition rate applicable to the subscription options that were subject to the performance condition of the 2009 Plan was 100%.

If all the outstanding stock options as of December 31, 2011 were exercised, the corresponding shares would represent 1.85%(1) of the Company’s potential share capital as of such date.

 

(1) Out of a total potential share capital of 2,408,400,225 shares.

 

105


Table of Contents

TOTAL STOCK OPTIONS AWARDED TO MAIN EXECUTIVE OFFICERS (MANAGEMENT COMMITTEE AND TREASURER) AS OF DECEMBER 31, 2011

 

     2003 Plan     2004 Plan     2005 Plan     2006 Plan     2007 Plan     2008 Plan     2009 Plan     2010 Plan     2011 Plan     Total  
Type of options   Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
        

Expiry date

    07/16/2011        07/20/2012        07/19/2013        07/18/2014        07/17/2015        10/09/2016        09/15/2017        09/14/2018        09/14/2019     

Exercise price ()(a)

    32.84        39.30        49.04        50.60        60.10        42.90        39.90        38.20        33.00           

Options awarded by the Board(b)

    680,904        848,800        711,440        851,240        1,032,120        1,138,300        1,215,300        1,406,400        846,600        8,731,104   

Adjustments related to the spin-off of Arkema(c)

    8,988        11,992        10,048                                                  31,028   

Options outstanding as of January 01, 2011

    277,119        757,792        721,488        851,240        1,032,120        1,059,901        1,215,300        1,406,400          7,321,360   

Options awarded in 2011

                                                            846,600        846,600   

Options exercised in 2011

    (277,119                                                             (277,119 ) 

Options canceled in 2011

                                                     (59,000            (59,000 ) 

Options outstanding as of December 31, 2011

           757,792        721,488        851,240        1,032,120        1,059,901        1,215,300        1,347,400        846,600        7,831,841   

 

(a) Exercise price as of May 24, 2006. The exercise prices of TOTAL subscription shares under the plans in force at that date were multiplied by 0.25 to take into account the four-for-one stock split on May 18, 2006. Moreover, following the spin-off of Arkema, the exercise prices of TOTAL stock options under these plans were multiplied by an adjustment factor equal to 0.986147 effective as of May 24, 2006. The exercise prices effective before May 24, 2006 are given in Note 25, points A, B and C to the Consolidated Financial Statements.
(b) The number of options awarded before May 23, 2006, has been multiplied by four to take into account the four-for-one stock split approved by the Shareholders’ Meeting on May 12, 2006.
(c) Adjustments approved by the Board at its meeting on March 14, 2006, pursuant to the provisions in effect at the time of the Board meeting and of the Shareholders’ Meeting on May 12, 2006, related to the spin-off of Arkema. These adjustments were made on May 22, 2006 effective as of May 24, 2006.

As part of the 2007, 2008 and 2009 share subscription option plans, the Board of Directors decided that for each beneficiary of more than 25,000 options, one-third of the options awarded in excess of this number be subject to a performance condition. For the 2010 share subscription option plan, beneficiaries of more than 3,000 options are subject to a performance condition for part of the options (see “— Grants to the Chairman and Chief Executive Officer”). For the 2011 share subscription option plan, all of the options are subject to a performance condition.

In addition, Mr. Clément, the director representing employee shareholders, has not exercised any option in 2011 and has not been awarded any share subscription options under the 2011 Plan.

 

106


Table of Contents

TOTAL STOCK OPTIONS AWARDED TO MR. DE MARGERIE, CHAIRMAN AND

CHIEF EXECUTIVE OFFICER OF TOTAL S.A.

 

     2003 Plan     2004 Plan     2005 Plan     2006 Plan     2007 Plan     2008 Plan     2009 Plan     2010 Plan     2011 Plan     Total  
Type of options   Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
    Subscription
options
        

Expiry date

    07/16/2011        07/20/2012        07/19/2013        07/18/2014        07/17/2015        10/09/2016        09/15/2017        09/14/2018        09/14/2019     

Exercise price ()(a)

    32.84        39.30        49.04        50.60        60.10        42.90        39.90        38.20        33.00           

Options awarded by the Board(b)

    112,000        128,000        130,000        160,000        200,000        200,000        200,000        240,000        160,000        1,530,000   

Adjustments related to the spin-off of Arkema(c)

    1,576        1,800        1,828                                                  5,204   

Options outstanding as of January 01, 2011

    113,576        129,800        131,828        160,000        200,000        176,667        200,000        240,000               1,351,871   

Options awarded in 2011

                                                            160,000        160,000   

Options exercised in 2011

    (113,576                                                             (113,576

Options canceled in 2011

                                                                     

Options outstanding as of December 31, 2011

           129,800        131,828        160,000        200,000        176,667        200,000        240,000        160,000        1,398,295   

 

(a) Exercise price as of May 24, 2006. The exercise prices of TOTAL subscription shares under the plans in force at that date were multiplied by 0.25 to take into account the four-for-one stock split on May 18, 2006. Moreover, following the spin-off of Arkema, the exercise prices of TOTAL stock options under these plans were multiplied by an adjustment factor equal to 0.986147 effective as of May 24, 2006. The exercise prices effective before May 24, 2006 are given in Note 25, points A, B and C to the Consolidated Financial Statements (chapter 9).
(b) The number of options awarded before May 23, 2006, has been multiplied by four to take into account the four-for-one stock split approved by the Shareholders’ Meeting on May 12, 2006.
(c) Adjustments approved by the Board at its meeting on March 14, 2006, pursuant to the provisions in effect at the time of the Board meeting and of the Shareholders’ Meeting on May 12, 2006, related to the spin-off of Arkema. These adjustments were made on May 22, 2006 effective as of May 24, 2006.

As part of the 2007 to 2011 Plans, the Board has made the grant of these options to the Chairman and Chief Executive Officer subject to performance conditions (see “— Grants to the Chairman and Chief Executive Officer”). For the 2009 Plan, the acquisition rate, linked to the performance conditions, was 100%.

As of December 31, 2011, the outstanding options of the Chairman and Chief Executive Officer represented 0.058%(1) of the Company’s potential share capital as of such date.

Mr. Desmarest, Chairman of the Board of Directors until May 21, 2010, was not awarded any share subscription options under the 2008, 2009, 2010 and 2011 plans. In addition, he was not awarded any performance shares under plans in the period 2005 to 2011.

 

(1) Out of a total potential share capital of 2,408,400,225 shares.

 

107


Table of Contents

STOCK OPTIONS AWARDED TO THE TEN EMPLOYEES (OTHER THAN CORPORATE EXECUTIVE OFFICERS) RECEIVING THE LARGEST AWARDS/STOCK OPTIONS EXERCISED BY THE TEN EMPLOYEES (OTHER THAN CORPORATE EXECUTIVE OFFICERS) EXERCISING THE LARGEST NUMBER OF OPTIONS

 

      Total number of
options
awarded/exercised
     Exercise price ()     Grant date(a)      Expiry date  

Options awarded in 2011 to the ten employees of TOTAL S.A., or any company in the Group, receiving the largest number of options

     430,400        33.00        09/14/2011         09/14/2019   

Options exercised in 2011 by the ten employees of TOTAL S.A., or any company in the Group, exercising the largest number of options(b)

     227,671         32.84        07/16/2003         07/16/2011   
     9,736         39.30        07/20/2004         07/20/2012   
     237,407         33.10 (c)      

 

(a) The grant date is the date of the Board meeting awarding the options.
(b) Exercise price as of May 24, 2006. The exercise prices of TOTAL stock options under the plans in force at that date were multiplied by 0.25 to take into account the four-for-one stock split on May 18, 2006. Moreover, following the spin-off of Arkema, the exercise prices of TOTAL stock options under these plans were multiplied by an adjustment factor equal to 0.986147 effective as of May 24, 2006. The exercise prices effective before May 24, 2006 are given in Note 25, points A, B and C to the Consolidated Financial Statements.
(c) Weighted-average price.

 

108


Table of Contents

TOTAL GLOBAL FREE AND PERFORMANCE SHARE GRANTS

TOTAL global free share plan

In addition to the performance shares granted, the Board of Directors decided at its meeting on May 21, 2010, to implement a global free share plan intended for all the Group employees, that is, more than 100,000 employees. On June 30, 2010, rights to twenty-five free shares were granted to every employee. The shares are subject to a vesting period of two to four years depending on the case. The shares granted are not subject to any performance condition. Following the vesting period, the shares will be issued.

Breakdown of TOTAL performance share grants

The following table gives a breakdown of TOTAL performance share grants by category of beneficiary (main executive officers, other executive officers and other employees).

 

          Number of
beneficiaries
    Number
of shares
awarded
(a)
    Percentage     Average
number of
shares per
beneficiary
 

2005 Plan(b)

  Main executive officers(c)     29        13,692        2.4     472   

Decision of the Board on July 19, 2005

  Other executive officers     330        74,512        13.1     226   
  Other employees(d)     6,956        481,926        84.5     69   
  Total     7,315        570,130        100     78   

2006 Plan(b)

  Main executive officers(c)     26        49,200        2.2     1,892   

Decision of the Board on July 18, 2006

  Other executive officers     304        273,832        12.0     901   
  Other employees(d)     7,509        1,952,332        85.8     260   
  Total     7,839        2,275,364        100     290   

2007 Plan(b)

  Main executive officers(c)     26        48,928        2.1     1,882   

Decision of the Board on July 17, 2007

  Other executive officers     297        272,128        11.5     916   
  Other employees(d)     8,291        2,045,309        86.4     247   
  Total     8,614        2,366,365        100     275   

2008 Plan(b)

  Main executive officers(c)     25        49,100        1.8     1,964   
Awarded on October 9, 2008, by decision of the Board of Directors on September 9, 2008   Other executive officers     300        348,156        12.5     1,161   
  Other employees(d)     9,028        2,394,712        85.8     265   
  Total     9,353        2,791,968        100     299   

2009 Plan(b)

  Main executive officers(c)     25        48,700        1.6     1,948   

Decision of the Board on September 15, 2009

  Other executive officers     284        329,912        11.1     1,162   
  Other employees(d)     9,693        2,593,406        87.3     268   
  Total     10,002        2,972,018        100     297   

2010 Plan(e)

  Main executive officers(c)     24        46,780        1.6     1,949   

Decision of the Board on September 14, 2010

  Other executive officers     283        343,080        11.4     1,212   
  Other employees(d)     10,074        2,620,151        87.0     260   
  Total     10,381        3,010,011        100     290   

2011 Plan

  Main executive officers(c)     29        184,900        5.1     6,376   

Decision of the Board on September 14, 2011

  Other executive officers     274        624,000        17.1     2,277   
  Other employees(d)     9,658        2,840,870        77.8     294   
  Total     9,961        3,649,770        100     366   

 

(a) The number of performance shares awarded shown in this table has not been adjusted to take into account the four-for-one stock split approved by the Shareholders’ Meeting on May 12, 2006.
(b) For the 2005, 2006, 2007 and 2009 Plans, the acquisition rates of the shares awarded, linked to the performance conditions, were 100%. For the 2008 Plan, the acquisition rate, linked to the performance condition, was 60%.
(c) Members of the Management Committee and the Treasurer as of the date of the Board meeting granting the performance shares. The Chairman of the Board and the Chief Executive Officer were not awarded any performance shares, with the exception of the 2011 Plan. On September 14, 2011, the Board of Directors of TOTAL S.A. decided to grant 16,000 performance shares to Mr. de Margerie.
(d) Mr. Clément, employee of Total Raffinage Marketing, a subsidiary of TOTAL S.A. and the director of TOTAL S.A. representing employee shareholders, was awarded 320 performance shares under the 2005 Plan, 200 performance shares under the 2007 Plan, 500 performance shares under the 2008 Plan, 240 performance shares under the 2010 Plan and 240 performance shares under the 2011 Plan.
(e) Excluding free shares granted as part of the 2010 global free share plan.

The grant of these performance shares, which were bought back by the Company on the market, will become final after a 2-year vesting period. This final grant is subject to a presence condition and a performance condition (see “— Stock options and performance share grants policy — General policy”). Moreover, the transfer of the performance shares will not be permitted until the end of a 2-year mandatory holding period.

 

109


Table of Contents

PERFORMANCE SHARE PLANS AS OF DECEMBER 31, 2011

 

      2005 Plan(a)     2006 Plan     2007 Plan     2008 Plan     2009 Plan     2010 Plan     2011 Plan  

Date of the Shareholders’ Meeting

     05/17/2005        05/17/2005        05/17/2005        05/16/2008        05/16/2008        05/16/2008        05/13/2011   

Grant date(b)

     07/19/2005        07/18/2006        07/17/2007        10/09/2008        09/15/2009        09/14/2010        09/14/2011   

Closing price on grant date(c)

     52.13        50.40        61.62        35.945        41.615        39.425        32.69   

Average repurchase price per share paid by the Company

     51.62        51.91        61.49        41.63        38.54        39.11        39.58   

Total number of performance shares awarded, including to

     2,280,520        2,275,364        2,366,365        2,791,968        2,972,018        3,010,011        3,649,770   

—Directors(d)

     416        416        432        588               240        16,240   

—Ten employees with largest grants(e)

     20,000        20,000        20,000        20,000        20,000        20,000        91,400   

Start of the vesting period:

     07/19/2005        07/18/2006        07/17/2007        10/09/2008        09/15/2009        09/14/2010        09/14/2011   

Date of final grant, subject to specific condition (end of the vesting period)

     07/20/2007        07/19/2008        07/18/2009        10/10/2010        09/16/2011        09/15/2012        09/15/2013   

Transfer possible from (end of the mandatory holding period)

     07/20/2009        07/19/2010        07/18/2011        10/10/2012        09/16/2013        09/15/2014        09/15/2015   

Number of performance shares:

              

— Outstanding as of January 1, 2011

                                 2,954,336        3,000,637          

—Awarded in 2011

                                          3,649,770   

—Canceled in 2011

     800 (g)      700 (g)      792 (g)      356 (g)      (26,214     (10,750     (19,579

—Finally granted in 2011(f)

     (800 )(g)      (700 )(g)      (792 )(g)      (356 )(g)      (2,928,122     (1,836       

—Outstanding as of December 31, 2011

                                        2,988,051        3,630,191   

 

(a) The number of performance shares awarded has been multiplied by four to take into account the four-for-one stock split approved by TOTAL Shareholders’ Meeting on May 12, 2006.
(b) The grant date is the date of the Board meeting awarding the performance share grant, except for the performance shares awarded on October 9, 2008, approved by the Board on September 9, 2008.
(c) To take into account the four-for-one stock split in May 18, 2006, the closing price for TOTAL shares on July 19, 2005 (208.50) has been divided by four.
(d) Mr. Desmarest, Chairman of the Board of Directors of TOTAL S.A. until May 21, 2010, and Mr. de Margerie, Chief Executive Officer since February 13, 2007 and Chairman and Chief Executive Officer since May 21, 2010, were not awarded performance shares under the plans approved by the Board of Directors of TOTAL S.A. on July 18, 2006, July 17, 2007, September 9, 2008, September 15, 2009 and September 14, 2010. Furthermore, Mr. Desmarest was not awarded performance shares under the plan approved by the Board of Directors of TOTAL S.A. on July 19, 2005. On September 14, 2011, the Board of Directors of TOTAL S.A. decided to grant 16,000 performance shares to Mr. de Margerie. In addition, Mr. Boeuf, director of TOTAL S.A. representing employee shareholders until December 31, 2009, was awarded performance shares under the plans approved by the Board of Directors of TOTAL S.A. on July 19, 2005, July 18, 2006, July 17, 2007 and September 9, 2008. Mr. Boeuf was not awarded any performance shares under the plan approved by the Board of Directors of TOTAL S.A. on September 15, 2009.
     Mr. Clément, director of TOTAL S.A. representing employee shareholders since May 21, 2010, was awarded 240 performance shares under the plan approved by the Board of Directors of TOTAL S.A. on September 14, 2011. In addition, Mr. Clément was awarded 240 performance shares under the plan approved by the Board of Directors of TOTAL S.A. on September 14, 2010.
(e) Employees of TOTAL S.A., or of any Group company, who were not directors of TOTAL S.A. as of the date of grant.
(f) For the 2010 Plan, final grants following the death of the beneficiary.
(g) Performance shares finally awarded for which the entitlement right had been canceled erroneously.

In case of a final grant of the outstanding performance shares as of December 31, 2011, the corresponding shares would represent 0.27%(1) of the Company’s potential share capital as of such date.

 

(1) Out of a total potential share capital of 2,408,400,225 shares.

 

110


Table of Contents

FOLLOW-UP OF THE GLOBAL FREE SHARE PLAN

 

      2010 Plan
(2+2)
(b)
    2010 Plan
(4+0)
(c)
    Total  

Date of the Shareholders’ Meeting

     05/16/2008        05/16/2008     

Grant date(a)

     06/30/2010        06/30/2010     

Final grant date

     07/01/2012        07/01/2014     

Transfer possible from

     07/01/2014        07/01/2014           

Outstanding as of January 1, 2010

      

Awarded

     1,508,850        1,070,650        2,579,500   

Canceled

     (125     (75     (200

Finally granted(d)

     (75       (75

Outstanding as of January 1, 2011

     1,508,650        1,070,575        2,579,225   

Awarded

                     

Canceled

     (29,175     (54,625     (83,800

Finally granted(d)

     (475     (425     (900

Outstanding as of December 31, 2011

     1,479,000        1,015,525        2,494,525   

 

(a) The June 30, 2010 grant was decided by the Board of Directors on May 21, 2010.
(b) Vesting period of two years followed by a holding period of two years.
(c) Vesting period of four years without a holding period.
(d) Final grant following the death or disability of the beneficiary of the shares.

In case of a final grant of the outstanding shares as of December 31, 2011, the corresponding shares would represent 0.10%(1) of the Company’s potential share capital as of such date.

PERFORMANCE SHARE GRANTS TO THE TEN EMPLOYEES (OTHER THAN CORPORATE EXECUTIVE OFFICERS) RECEIVING THE LARGEST NUMBER OF PERFORMANCE SHARES

 

      Number of
performance shares
granted/finally
awarded
     Grant date      Date of
final grant
(end of
vesting
period)
     End of
mandatory
holding
period
 

Performance share grants approved by the Board meeting on September 14, 2011 to the ten TOTAL S.A. employees (other than corporate executive officers) receiving the largest number of performance shares(a)

     91,400        09/14/2011         09/15/2013         09/15/2015   

Performance shares finally awarded in 2011 following the performance share plan approved by the Board meeting on September 15, 2009, to the ten employees (other than corporate executive officers) at the time of such approval receiving the largest number of performance shares(b)

     20,000         09/15/2009         09/16/2011         09/16/2013   

 

(a) Grant approved by the Board on September 14, 2011. Grants of these performance shares will become final, subject to a performance condition, after a 2-year vesting period (i.e., on September 15, 2013) (see “— Stock options and performance share grants policy — General policy”). Moreover, the transfer of the performance shares will not be permitted until the end of a 2-year mandatory holding period (i.e., on September 15, 2015).
(b) This final grant is subject to a performance condition (see “— Stock options and performance share grants policy — General policy”). The acquisition rate of the shares awarded, linked to the performance condition, was 100%. Moreover, the transfer of the performance shares finally awarded will only be permitted after the end of a 2-year mandatory holding period (i.e., from September 16, 2013).

 

(1) Out of a total potential share capital of 2,408,400,225 shares.

 

111


Table of Contents

CORPORATE GOVERNANCE

 

 

For several years, TOTAL has been actively examining corporate governance matters. At its meeting on November 4, 2008, the Board of Directors confirmed its decision to refer to the Corporate Governance Code for Listed Companies published by the principal French business confederations, the Association Française des Entreprises Privées (AFEP) and the Mouvement des Entreprises de France (MEDEF) (“AFEP-MEDEF Code”) for corporate governance matters.

The AFEP-MEDEF Code was amended in April 2010 to make recommendations related to the balanced number of men and women sitting in Board and Committees’ meetings. The code recommends that a target of at least 20% of women be reached before April 2013 and at least 40% before April 2016. These requirements were also stipulated in the French law of January 27, 2011 regarding balanced representation of men and women on Boards of Directors and Supervisory Boards and equal opportunity. The law states that the 20% threshold must be attained at the end of the 2014 Shareholders’ Meeting and that the 40% threshold must be attained at the end of the 2017 Shareholders’ Meeting.

As of December 31, 2011, the Company’s Board of Directors was comprised of four women out of a total of fifteen members (i.e., 26%). At the Shareholders’ Meeting in May 2012, it will be proposed to appoint one additional woman to replace one director whose term is coming to an end. If the resolution is approved by the Shareholders’ Meeting, the proportion of women sitting on the Board will be one-third. The Board of Directors will keep examining corporate governance issues to keep diversifying in the years to come.

At its meeting on February 8, 2012, the Nominating & Governance Committee examined current practices in the Company in view of the AFEP-MEDEF code and concluded that the Company complied with almost all the recommendations.

Mr. Thierry Desmarest, Honorary Chairman of the Company and director, can still be entrusted with representative missions for the Group, by decision of the Board of Directors on May 21, 2010.

Since 2004, the Board of Directors has had a Financial Code of Ethics that, in the overall context of the Group’s

Code of Conduct, sets forth specific rules for its Chairman, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and the financial and accounting officers for its principal activities. The Board has made the Audit Committee responsible for implementing and ensuring compliance with this code.

In 2005, the Board approved the procedure for alerting the Audit Committee of complaints or concerns regarding accounting, internal accounting controls or auditing matters.

Rules of procedure of the Board of Directors

At its meeting on February 13, 2007, the Board of Directors adopted rules of procedure to replace the Directors’ Charter.

The Board’s rules of procedure specify the obligations of each director and set forth the mission and working procedures of the Board of Directors. They also define the respective responsibilities and authority of the Chairman and of the Chief Executive Officer. It is reviewed on a regular basis to match the changes in rules and practices related to governance.

An unabridged version of these rules of procedure, which were approved by the Board of Directors of TOTAL S.A.(1), is available herein.

Mission of the Board of Directors

The mission of the Board of Directors is to determine the strategic direction of the Group and supervise the implementation of this vision. With the exception of the powers and authority expressly reserved for shareholders and within the limits of the Company’s legal purpose, the Board may address any issue related to the operation of the Company and take any decision concerning the matters falling within its purview. Within this framework, the Board’s duties and responsibilities include, but are not limited to, the following:

 

 

appointing the Chairman and the Chief Executive Officer(2) and supervising the handling of their responsibilities;

 

defining the Company’s strategic orientation and, more generally, that of the Group;

 

 

 

(1) In these rules of procedure, TOTAL S.A. is referred to as the “Company” and, collectively with all of its direct and indirect subsidiaries, as the “Group”.
(2) The Chairman and Chief Executive Officer, if the Chairman of the Board of Directors is also responsible for the general management of the Company, the Chairman of the Board of Directors and the Chief Executive Officer, if this is not the case, and, where appropriate, any acting Managing Directors, in accordance with the organization adopted by the Board of Directors.

 

112


Table of Contents
 

approving investments or divestments under study by the Group that concern amounts greater than 3% of shareholders’ equity;

 

reviewing information on significant events related to the Company’s affairs, in particular for investments or divestments that are greater than 1% of shareholders’ equity;

 

conducting audits and investigations as it may deem appropriate. The Board, with the assistance of the Audit Committee where appropriate, ensures that:

   

the proper definition of authority within the Company and the proper exercise of duties and responsibilities by the bodies of the Company are in place;

   

no individual is authorized to contract on behalf of the Company or to commit to pay, or to make payments, on behalf of the Company, without proper supervision and control;

   

the internal control function operates properly and that the statutory auditors are able to conduct their audits under appropriate circumstances;

   

the committees it has created duly perform their responsibilities;

 

monitoring the quality of the information provided to the shareholders and the financial markets through the financial statements that it approves and the annual reports, or when major transactions are conducted;

 

convening and setting the agenda for Shareholders’ Meetings or meetings of bondholders;

 

preparing, for each year, a list of the directors it deems to be independent under generally recognized corporate governance criteria.

Directors’ obligations

Before accepting a directorship, every candidate receives a copy of TOTAL S.A.’s by-laws and rules of procedure. He ensures that he has broad knowledge of the general and particular commitments related to his duty, especially the laws and regulations governing directorships in French limited liability companies (société anonyme) whose shares are listed in one or several regulated markets.

Accepting a directorship involves upholding the Directors’ ethical rules as described in the Code of Corporate Governance to which the Company refers. It also involves upholding the rules of procedure and the Group’s values as described in its Code of Conduct.

When directors participate in and vote at Board meetings, they are required to represent the interest of the shareholders and the Company as a whole.

Independence of judgment: Directors undertake, under any circumstance, to maintain the independence of their

analysis, judgment, decision making and actions as well as not to be unduly influenced, directly or indirectly, by other directors, particular groups of shareholders, creditors, suppliers and, more generally, any third party.

Preparation of each Board meeting: Directors undertake to devote the amount of time required to consider the information they are given and otherwise prepare for meetings of the Board and of the committees on which they sit. Directors may request any additional information that they feel is necessary or useful from the Chairman and Chief Executive Officer. Directors, if they consider it necessary, may request training on the Company’s specificities, businesses and activities, and any other training that is of use in the exercise of their duties as Directors.

Directors attend all Board meetings and all committees or Shareholders’ Meetings, unless they have previously contacted the Chairman to inform him of scheduling conflicts.

Files reviewed at each meeting of the Board as well as the information collected before or during the meetings are confidential. Directors cannot use them for or share them with a third party whatever the reason. Directors take any necessary measures to keep them confidential. Confidentiality and privacy are lifted when such information is made publicly available by the Company.

The Chairman of the Board makes sure that the Company provides the directors with the relevant information, including criticisms, in particular financial statement reports and press releases, and the main press articles about the Company.

Duty of loyalty: Directors cannot take advantage of their office or duties to ensure, for themselves or a third party, any monetary or non-monetary benefit.

They notify the Board of Directors of any potential conflicts of interest with the Company or any other company of the Group. They refrain from participating in the vote relating to the corresponding resolution or even to the debate preceding the vote.

Directors must inform the Board of Directors of their entering into a transaction that involves directly the Company or any other company of the Group before such transaction is closed.

Directors cannot take any responsibility in a personal capacity in companies or businesses that are competing with the Company or any other company of the Group without previously informing the Board.

 

 

113


Table of Contents

Directors are committed not to seek or accept directly or indirectly from the Company or any other company of the Group benefits that may be considered as compromising their independence.

Duty of expression: Directors are committed to clearly expressing their opposition if they deem that a decision made by the Board of Directors is contrary to the Company’s corporate interest and should strive to convince the Board of the relevancy of their position.

Company’s securities and stock exchange rules: While in office, directors are required to hold the minimum number of registered shares as set by the Company’s by-laws.

Directors refrain from trading any shares and ADRs of TOTAL S.A. and its publicly traded subsidiaries for which they hold non-public information that could impact the securities’ market value. To this purpose, directors act in compliance with the following procedures:

 

 

any shares and ADRs of TOTAL S.A. and its publicly traded subsidiaries are to be held in registered form, either with the Company or its agent(1), or administered registered shares with a French broker (or U.S. broker for ADRs) whose contact details are communicated to the Board’s Secretary by the director;

 

buying on margin or short selling (Paris option market (MONEP), warrants, exchangeable obligations, etc.) those same securities is also prohibited;

 

any transaction on the TOTAL share (or ADR) is strictly prohibited, including hedging transactions, on the day when the Company discloses its periodic earnings (quarterly, interim and annual) as well as the fifteen calendar days preceding such date; and

 

directors make all necessary arrangements to declare to the French Financial Markets Authority (Autorité des marchés financiers) and inform the Board’s secretary, under the form and timeframe provided for by applicable laws, of any transaction on the company’s securities entered into by himself or any other individual with whom he is closely related.

Workings of the Board of Directors

The Board of Directors meets at least four times a year and as often as circumstances may require.

Before each meeting of the Board, the agenda is sent out to directors and, whenever possible, it is sent together with the documents that are necessary to consider.

Directors can delegate their authority to another director at the meetings of the Board, within the limit of one delegation per director per meeting.

Whenever authorized by the law, those directors attending the meeting of the Board via video conference (in compliance with the technical requirements set by applicable regulations) are considered present for the calculation of the quorum and majority.

The Board allocates directors’ fees to, and may allocate additional directors’ fees to, directors who participate on specialized committees within the total amount established by the Shareholders’ Meeting. The Chairman and the Chief Executive Officer are not awarded directors’ fees for their work on the Board and Committees.

The Board of Directors, based on the recommendation of its Chairman, appoints a Secretary. Every member of the Board of Directors can refer to the Secretary and benefit from his assistance. The Secretary is responsible for the working procedures of the Board of Directors. The Board shall review such procedures periodically.

The Board conducts, at regular intervals not to exceed three years, an assessment of its practices. Such assessment is carried out possibly under the supervision of an independent director or with the contribution of an outside counsel. In addition, the Board of Directors conducts an annual discussion of its methods.

Responsibility and authority of the Chairman

The Chairman represents the Board, and, except under exceptional circumstances, is the sole member authorized to act and speak on behalf of the Board.

He is responsible for organizing and presiding over the Board’s activities and monitors corporate bodies to ensure that they are functioning effectively and respecting corporate governance principles. He coordinates the activity of the Board and its committees. He sets the agenda for the meeting by including the issues proposed by the Chief Executive Officer.

He ensures that directors have in due course clear and appropriate information that is necessary to carry out their duties.

He is responsible, with the Group’s general management, for maintaining relations between the Board and the Company’s shareholders. He monitors the quality of the information disclosed by the Company.

In close cooperation with the Group’s general management, he may represent the Group in high-level discussions with government authorities and the Group’s important partners, on both a national and international level.

 

 

 

(1) Currently, BNP Paribas Securities Services for TOTAL shares and Bank of New York for TOTAL ADRs.

 

114


Table of Contents

He is regularly informed by the Chief Executive Officer of events and situations that are important for the Group relating to the strategy, organization, monthly financial reporting, major investment and divestment projects and major financial operations. He may request that the Chief Executive Officer or other Company directors, provided the Chief Executive Officer is informed, provide any useful information for the Board or its committees to carry out their duties.

He may also work with the statutory auditors to prepare matters before the Board or the Audit Committee.

He presents every year in a report to the Shareholders’ Meeting, practices of the Board of Directors and potential limits set by the Board of Directors concerning the powers of the Chief Executive Officer. For this purpose, he receives from the Chief Executive Officer the relevant information.

Authority of the Chief Executive Officer

The Chief Executive Officer is responsible for the general management of the Company. He chairs the Group’s Executive Committee and Management Committee. Subject to the Company’s corporate governance rules and in particular the rules of procedure of the Board of Directors, he has the full extent of authority to act on behalf of the Company in all instances, with the exception of actions that are, by law, reserved to the Board of Directors or to Shareholders’ meetings.

The Chief Executive Officer is responsible for periodic reporting of the Group’s results and outlook to shareholders and the financial community.

At each meeting of the Board, the Chief Executive Officer reports the highlights of the Group’s activity.

Committees of the Board of Directors

The Board of Directors approved the creation of:

 

 

an Audit Committee;

 

a Nominating & Governance Committee;

 

a Compensation Committee; and

 

a Strategic Committee.

The missions and composition of these committees are defined in their relevant rules of procedure approved by the Board of Directors. The Committees carry out their duty for and report to the Board of Directors. Each committee reports on its activities to the Board of Directors.

Committees of the Board of Directors

The Committees of the Board of Directors are: an Audit Committee; a Nominating & Governance Committee; a Compensation Committee; and a Strategic Committee.

On April 28, 2011, the Board agreed in principle on the creation of a new Strategic Committee, the composition and rules of which it approved at its meeting on July 28, 2011. This Committee was set up and met for the first time on September 14, 2011.

The composition and an unabridged version of the rules of procedures of the Committees of the Board of Directors is available herein.

Audit Committee

Rules of procedure (unabridged version)

The Board of Directors of TOTAL S.A. (hereafter referred to as the “Company” and, collectively with all its direct and indirect subsidiaries, as the “Group”) has approved the following rules of procedure of the Company’s Audit Committee (hereafter, the “Committee”).

The members of the Committee are directors of the Company and therefore uphold the rules of procedure of the Board of Directors of TOTAL S.A.

Mission: To allow the Board of Directors of TOTAL S.A. to ensure that internal control is effective and that published information available to shareholders and financial markets is reliable, the duties of the Committee include:

 

 

recommending the appointment of statutory auditors and their compensation, ensuring their independence and monitoring their work;

 

establishing the rules for the use of statutory auditors for non-audit services and verifying their implementation;

 

supervising the audit by the statutory auditors of the Company’s statutory financial statements and consolidated financial statements;

 

examining the accounting policies used to prepare the financial statements and examining the Company’s statutory financial statements and consolidated annual, semi-annual, and quarterly financial statements prior to their examination by the Board of Directors, after regularly monitoring the financial situation, cash position and obligations of the Company;

 

supervising the implementation of internal control and risk management procedures and their effective application, with the assistance of the internal audit department;

 

supervising procedures for preparing financial information;

 

monitoring the implementation and activities of the disclosure committee, including reviewing the conclusions of this committee;

 

 

115


Table of Contents
 

reviewing the annual work program of internal and external auditors;

 

receiving information periodically on completed audits and examining annual internal audit reports and other reports (statutory auditors, annual report, etc.);

 

reviewing the choice of appropriate accounting principles and methods;

 

reviewing the Group’s policy for the use of derivative instruments;

 

reviewing, if requested by the Board of Directors, major transactions contemplated by the Group;

 

reviewing significant litigation annually;

 

implementing and monitoring compliance with the financial code of ethics;

 

proposing to the Board of Directors, for implementation, a procedure for complaints or concerns of employees, shareholders and others, related to accounting, internal accounting controls or auditing matters, and monitoring the implementation of this procedure; and

 

reviewing the procedure for booking the Group’s proved reserves.

Composition: The Committee is made up of at least three directors designated by the Board of Directors. Members must be independent directors.

In selecting the members of the Committee, the Board of Directors pays particular attention to their independence and their financial and accounting qualifications.

The Board of Directors appoints one of the members of the Committee to serve as the financial expert on the Committee.

Members of the Committee may not be executive officers of the Company or one of its subsidiaries, nor own more than 10% of the Company’s shares, whether directly or indirectly, individually or acting together with another party.

Members of the Committee may not receive from the Company and its subsidiaries, either directly or indirectly, any compensation other than: (i) directors’ fees paid for their services as directors or as members of the committee, or, if applicable, as members of another committee of the Company’s Board; and (ii) compensation and pension benefits related to prior employment by the Company, or another Group company, which are not dependent upon future work or activities.

The term of office of the members of the Committee coincides with the term of their appointment as director. The term of office as a member of the Committee may be renewed at the same time as the appointment as director.

However, the Board of Directors can change the composition of the Committee at any time.

Organization of activities: The Committee appoints its own Chairman. The Chairman appoints the Committee secretary, who may be the Chief Financial Officer of the Company.

The Committee deliberates when at least one-half of its members are present. A member of the Committee cannot be represented.

The Committee meets at least four times a year to review the annual and quarterly consolidated financial statements, and at the request of its Chairman, at least one-half of its members, the Chairman of the Board of Directors or the Chief Executive Officer of the Company. The Committee Chairman prepares the schedule of its meetings.

The Audit Committee may meet with the Chairman of the Board, the Chief Executive Officer, and, if applicable, any acting Managing Director of the Company and perform inspections and consult with managers of operating or non-operating departments, as may be useful in performing its duties. The Chairman of the committee gives prior notice of such meeting to the Chairman of the Board or, if the latter is not the Chief Executive Officer, to both the Chairman of the Board of Directors and the Chief Executive Officer. In particular, the Committee is authorized to consult with those involved in preparing or auditing the financial statements (Chief Financial Officer and principal Finance Department managers, Audit Department, Legal Department) by asking the Company’s Chief Financial Officer to call them to a meeting.

The Committee consults with the statutory auditors. It has the capacity of consulting them without Company representatives attending. If it is informed of a substantial irregularity, it recommends that the Board of Directors take all appropriate action.

If it deems it necessary to accomplish its duties, the Committee may request from the Board of Directors the resources to engage external consultants.

The proposals made by the Committee to the Board of Directors are adopted by a majority of the members present at the Committee meeting. The Chairman of the Committee casts the deciding vote if an even number of members is present at the meeting.

The Committee can adopt proposals intended for the Board of Directors without meeting if all the members of the Committee so agree and sign each proposal.

A written summary of Committee meetings is drawn up.

Report: The Committee submits written reports to the Board of Directors regarding its work.

It periodically evaluates its performance based on these rules of procedure and, if applicable, offers suggestions for improving its performance.

 

 

116


Table of Contents

Members of the Audit Committee in 2011

In 2011, the Committee’s members were Ms. Patricia Barbizet, Mr. Thierry de Rudder and Mr. Bertrand Jacquillat, until his term as director expired on May 13, 2011. At the Shareholders’ Meeting on May 13, 2011, Ms. Marie-Christine Coisne-Roquette was appointed a member of the Audit Committee to replace Mr. Jacquillat.

All of the members of the Committee are independent directors and have recognized experience in the financial and accounting fields.

The Committee is chaired by Ms. Barbizet.

At its meeting on July 28, 2011, the Board of Directors decided to appoint Ms. Barbizet to serve as the Audit Committee financial expert based on a recommendation by the Audit Committee.

At its meeting on January 12, 2012, the Board of Directors decided to co-opt Mr. Gérard Lamarche as a director and to nominate him as a member of the Audit Committee in replacement of Mr. de Rudder, who is resigning from his position as a Director.

Compensation Committee

Rules of procedure (unabridged version)

The Board of Directors of TOTAL S.A. (hereafter referred to as the “Company” and, collectively with all its direct and indirect subsidiaries, as the “Group”) has approved the following rules of procedure of the Company’s Compensation Committee (hereafter, the “Committee”).

The members of the Committee are directors of the Company and therefore uphold the rules of procedure of the Board of Directors of TOTAL S.A.

The Committee is focused on:

 

 

examining the executive compensation policies implemented by the Group and the compensation of members of the Executive Committee;

 

evaluating the performance and recommending the compensation of each corporate executive officer, and

 

preparing reports which the Company must present in these areas.

Duties: The Committee’s duties include:

 

 

examining the main objectives proposed by the Company’s general management regarding compensation of the Group’s executive officers, including stock option and restricted share grant plans and equity-based plans, and advising on this subject;

 

presenting recommendations and proposals to the Board of Directors concerning:

   

compensation, pension and life insurance plans, in-kind benefits and other compensation (including severance benefits) for the corporate executive officers of the Company; in particular, the Committee proposes compensation structures that take into account the Company’s strategy, objectives and earnings and market practices,

   

stock option and restricted share grants, particularly grants of registered shares to the corporate executive officers;

 

examining the compensation of the members of the Executive Committee, including stock option and restricted share grant plans and equity-based plans, pension and insurance plans and in-kind benefits;

 

preparing and presenting reports in accordance with these rules of procedure;

 

examining, for the parts within its remit, reports to be sent by the Board of Directors or its Chairman to the shareholders;

 

preparing recommendations requested at any time by the Chairman of the Board of Directors or the general management of the Company regarding compensation.

Composition: The Committee is made up of at least three directors designated by the Board of Directors. A majority of the members must be independent directors.

Members of the Compensation Committee may not receive from the Company and its subsidiaries, either directly or indirectly, any compensation other than: (i) directors’ fees paid for their services as directors or as members of the committee, or, if applicable, as members of another committee of the Company’s Board; (ii) compensation and pension benefits related to prior employment by the Company, or another Group company, which are not dependent upon future work or activities.

The term of office of the members of the Committee coincides with the term of their appointment as director. The term of office as a member of the Committee may be renewed at the same time as the appointment as director.

However, the Board of Directors can change the composition of the Committee at any time.

Organization of activities: The Committee appoints its Chairman and its secretary. The secretary is a Company senior executive.

The Committee deliberates when at least one-half of its members are present. A member of the Committee cannot be represented.

 

 

117


Table of Contents

The Committee meets at least twice a year. It meets on an as-needed basis through notice by its Chairman or by one-half of its members.

The Committee invites the Chairman of the Board or the Chief Executive Officer of the Company, as applicable, to present recommendations. Neither the Chairman nor the Chief Executive Officer may be present during the Committee’s deliberations regarding his own situation. If the Chairman of the Board is not the Chief Executive Officer of the Company, the Chief Executive Officer may not be present during the Committee’s deliberations regarding the situation of the Chairman of the Board.

While maintaining the appropriate level of confidentiality for its discussions, the Committee may request from the Chief Executive Officer to be assisted by any senior executive of the Company whose skills and qualifications could facilitate the handling of an agenda item.

If it deems it necessary to accomplish its duties, the Committee may request from the Board of Directors the resources to engage external consultants.

The proposals made by the Committee to the Board of Directors are adopted by a majority of the members present at the Committee meeting. The Chairman of the Committee casts the deciding vote if an even number of Committee members is present at the meeting.

The Committee can adopt proposals intended for the Board of Directors without meeting if all the members of the Committee so agree and sign each proposal.

A written summary of Committee meetings is drawn up.

Report: The Committee reports on its activities to the Board of Directors.

At the request of the Chairman of the Board, the Committee examines all draft reports of the Company regarding compensation of the executive officers or any other issues relevant to its area of expertise.

Members of the Compensation Committee in 2011

In 2011, the Committee’s members were Messrs. Patrick Artus, Bertrand Collomb, Thierry Desmarest and Michel Pébereau. Messrs. Artus, Collomb and Pébereau are independent directors. Mr. Pébereau chairs the Committee.

At its meeting on February 9, 2012, the Board of Directors decided to change the composition of the Compensation Committee. As of this date, the Committee’s members are Messrs. Patrick Artus, Gunnar Brock, Thierry Desmarest, Claude Mandil and Michel Pébereau. Messrs. Artus, Brock, Mandil and Pébereau are independent directors.

Nominating & Governance Committee

Rules of procedure (unabridged version)

The Board of Directors of TOTAL S.A. (hereafter referred to as the “Company” and, collectively with all its direct and indirect subsidiaries, as the “Group”) has approved the following rules of procedure of the Company’s Nominating and Governance Committee (hereafter, the “Committee”).

The members of the Committee are directors of the Company and therefore uphold the rules of procedure of the Board of Directors of TOTAL S.A.

The Committee is focused on:

 

 

recommending to the Board of Directors the persons that are qualified to be appointed as directors, so as to guarantee the scope of coverage of the Directors’ competencies and the diversity of their profiles;

 

recommending to the Board of Directors the persons that are qualified to be appointed as corporate executive officers;

 

preparing the Company’s corporate governance rules and supervising their implementation; and

 

examining any questions referred to it by the Board or the Chairman of the Board, in particular questions related to ethics and situations of conflicting interests.

Duties: The Committee’s duties include:

 

 

presenting recommendations to the Board for its membership and the membership of its committees, and the qualification in terms of independence of each candidate for Directors’ positions on the Board of Directors;

 

proposing annually to the Board of Directors the list of directors who may be considered as “independent directors”;

 

examining, for the parts within its remit, reports to be sent by the Board of Directors or its Chairman to the shareholders;

 

assisting the Board of Directors in the selection and evaluation of the corporate executive officers and examining the preparation of their possible successors, including cases of unforeseeable absence;

 

recommending to the Board of Directors the persons that are qualified to be appointed as directors;

 

recommending to the Board of Directors the persons that are qualified to be appointed as member of a Committee of the Board of Directors;

 

proposing methods for the Board of Directors to evaluate its performance, and in particular preparing means of regular self-assessment of the workings of the Board of Directors, and the possible assessment thereof by an external consultant;

 

 

118


Table of Contents
 

proposing to the Board of Directors the terms and conditions for allocating directors’ fees and the conditions under which expenses incurred by the directors are reimbursed;

 

developing and recommending to the Board of Directors the corporate governance principles applicable to the Company;

 

examining any questions referred to it by the Board or the Chairman of the Board, in particular questions related to ethics and situations of conflicting interests;

 

preparing recommendations requested at any time by the Board of Directors or the general management of the Company regarding appointments or governance.

 

examining the conformity of the Company’s governance practices with the recommendations of the Code of Corporate Governance adopted by the Company;

 

examining changes in the duties of the Board of Directors.

Composition: The Committee is made up of at least three directors designated by the Board of Directors. A majority of the members must be independent directors.

Members of the Nominating & Governance Committee, other than the Company’s corporate executive officers, may not receive from the Company and its subsidiaries any compensation other than: (i) directors’ fees paid for their services as directors or as members of the committee, or, if applicable, as members of another committee of the Company’s Board; (ii) compensation and pension benefits related to prior employment by the Company, or another Group company, which are not dependent upon future work or activities.

The term of office of the members of the Committee coincides with the term of their appointment as director. The term of office as a member of the Committee may be renewed at the same time as the appointment as director.

However, the Board of Directors can change the composition of the Committee at any time.

Organization of activities: The Committee appoints its Chairman and its secretary. The secretary is a Company senior executive.

The Committee deliberates when at least one-half of its members are present. A member of the Committee cannot be represented.

The Committee meets at least twice a year. It meets on an as-needed basis through notice by its Chairman or by one-half of its members.

The Committee invites the Chairman of the Board or the Chief Executive Officer of the Company, as applicable, to present recommendations. The corporate executive officers, whether they are members of the Committee or

invited to its meetings, may not be present at deliberations concerning their own situation.

While maintaining the appropriate level of confidentiality for its discussions, the Committee may request from the Chief Executive Officer to be assisted by any senior executive of the Company whose skills and qualifications could facilitate the handling of an agenda item.

If it deems it necessary to accomplish its duties, the Committee may request from the Board of Directors the resources to engage external consultants.

The proposals made by the Committee to the Board of Directors are adopted by a majority of the members present at the Committee meeting. The Chairman of the Committee casts the deciding vote if an even number of Committee members is present at the meeting.

The Committee can adopt proposals intended for the Board of Directors without meeting if all the members of the Committee so agree and sign each proposal.

A written summary of Committee meetings is drawn up.

Report: The Committee reports on its activities to the Board of Directors.

Members of the Nominating & Governance Committee in 2011

In 2011, the Committee’s members were Messrs. Bertrand Collomb, Thierry Desmarest and Michel Pébereau. Messrs. Collomb and Pébereau are independent directors. The Committee is chaired by Mr. Desmarest. At its meeting on February 9, 2012, the Board of Directors decided to change the composition of the Nominating and Governance Committee. As of this date, the Committee’s members are Messrs. Patrick Artus, Gunnar Brock, Bertrand Collomb, Thierry Desmarest and Claude Mandil. Messrs. Artus, Brock, Collomb and Mandil are independent directors.

Strategic Committee

Rules of procedure (unabridged version)

The members of the Committee are directors of the Company and therefore uphold the rules of procedure of the Board of Directors of TOTAL S.A.

Duties: To allow the Board of Directors of TOTAL S.A. to ensure the Group’s development, the Committee’s duties include:

 

 

examining the overall strategy of the Group proposed by the Company’s general management;

 

examining operations that are of particular strategic importance;

 

reviewing competition and the resulting medium and long-term outlook for the Group.

 

 

119


Table of Contents

Composition: The Committee is made up of at least five directors designated by the Board of Directors.

Members of the Committee may not receive from the Company and its subsidiaries, either directly or indirectly, any compensation other than:

 

 

directors’ fees paid for their services as directors or as members of the Committee, or, if applicable, as members of another committee of the Company’s Board; and

 

compensation and pension benefits related to prior employment by the Company, or another Group company, which are not dependent upon future work or activities.

The term of office of the members of the Committee coincides with the term of their appointment as director. The term of office as a member of the Committee may be renewed at the same time as the appointment as director.

However, the Board of Directors can change the composition of the Committee at any time.

Organization of activities: The Chairman of the Board of Directors of the Company chairs the Committee. The Chairman appoints the Committee secretary, who may be the Secretary of the Board of Directors.

The Committee deliberates when at least one-half of its members are present. A member of the Committee cannot be represented.

The Committee meets at least once a year and at the request of its Chairman, at least one-half of its members, or the Chief Executive Officer of the Company. The Committee Chairman prepares the schedule of its meetings.

Directors who are not members of the Committee are free to participate in the Committee’s meetings. This voluntary participation entitles them to the same directors’ fees as those paid to the members of the Committee for attending meetings.

The Committee may meet with the Chief Executive Officer, and, if applicable, any acting Managing Director of the Company and consult with managers of operating or non-operating departments, as may be useful in performing its duties. The Chairman of the Committee [, if the latter is not the Chief Executive Officer of the Company,] gives prior notice of such meeting to the Chief Executive Officer. In particular, the Committee is authorized to consult with the Vice President Strategy & Business Intelligence of the Company or the person delegated by the latter, by asking the Company’s Chief Executive Officer to call them to a meeting.

If it deems it necessary to accomplish its duties, the Committee may request from the Board of Directors the resources to engage external consultants.

A written summary of Committee meetings is drawn up.

Report: The Committee submits written reports to the Board of Directors regarding its work.

It periodically evaluates its performance based on these rules of procedure and, if applicable, offers suggestions for improving its performance.

Members of the Strategic Committee in 2011

In 2011, the Committee’s members were Mmes. Patricia Barbizet, Barbara Kux and Anne Lauvergeon and Messrs. Christophe de Margerie, Thierry Desmarest, Gunnar Brock, Claude Mandil and Thierry de Rudder.

At its meeting on January 12, 2012, the Board of Directors decided to co-opt Mr. Gérard Lamarche as a director and to nominate him as a member of the Strategic Committee in replacement of Mr. de Rudder, who resigned from his position as a Director.

Mmes. Barbizet, Kux and Lauvergeon and Messrs. Brock, Mandil and Lamarche are independent directors.

As a reminder, directors who are not members of the Committee are free to participate in the Committee’s meetings.

Mr. Christophe de Margerie chairs the Committee.

Board of Directors practices

Management form

On May 21, 2010, the Board of Directors decided to reunify the positions of Chairman and Chief Executive Officer and appoint the Chief Executive Officer to the duties of Chairman of the Board. This decision was made further to the work done by the Nominating & Governance Committee and in the best interests of the Company, taking into account the advantage of the unified management and the majority of independent directors appointed at the Committees, which ensures balanced authority.

The Board of Directors deemed that the unified management form was the most appropriate to the Group’s organization, modus operandi and business, and the specificities of the oil and gas sector. It respects the respective prerogatives of the various Company instances (Shareholders’ meeting, Board of Directors, general management).

 

 

120


Table of Contents

Moreover, the Company by-laws and the respective rules of procedure of the Board of Directors and the Committees provide the guarantees required to implement best governance practices within a unified management framework. In particular, the by-laws allow the Board to nominate one or two Vice-Chairmen. They also state that the Board of Directors can be summoned by any means, even verbally, or at short notice in the event of an emergency, by the Chairman, a Vice-Chairman, or one third of the members, at any time and whenever the Company so requires. The rules of procedure of the Board of Directors also state that each Director is required to inform the Board of Directors of any conflicts of interest with the Company or with any other company in the Group, and to abstain from voting on the resolution in question, and even to refrain from taking part in the debate preceding the vote.

Performance and evaluation

At its meeting on February 10, 2011, the Board of Directors discussed its practices and made suggestions for improvement with respect to broadening criteria when benchmarking with other companies, and for a thorough

study of the Group’s opportunities in the energy sector. These proposals were implemented at the meeting of the new Strategic Committee and when the report of the meeting was presented to the Board of Directors.

At its meeting of February 9, 2012, the Board of Directors discussed its practices on the basis of a formal evaluation carried out by means of a detailed questionnaire completed by all of the directors. The responses were then submitted for examination by the Nominating & Governance Committee and summarized. It is this summary that was discussed by the Board of Directors.

The formal evaluation showed a generally positive opinion of the practices of the Board of Directors and the Committees, which highlighted that the improvements requested by the directors in 2011 had been made. The Board therefore stated that it was globally satisfied with its practices and suggested improvements mainly relating to more in-depth strategic reflection. This has already been put in place with the Strategic Committee, and work in this area will continue for the benefit of the Board of Directors and the Group.

 

EMPLOYEES AND SHARE OWNERSHIP

 

Employees

The tables below set forth the number of employees, by division and geographic location, of the Group (fully consolidated subsidiaries) as of the end of the periods indicated:

 

      Upstream      Downstream      Chemicals      Corporate      Total  

2011

     23,563         29,423         41,665         1,453         96,104   

2010

     17,192         32,631         41,658         1,374         92,855   

2009

     16,628         33,760         44,667         1,332         96,387   

 

      France      Rest of Europe      Rest of the World      Total  

2011

     35,037         22,453         38,614         96,104   

2010

     35,169         24,931         32,755         92,855   

2009

     36,407         26,299         33,681         96,387   

 

 

TOTAL believes that the relationship between its management and labor unions is, in general, satisfactory.

Arrangements for involving employees in the Company’s share capital

Pursuant to agreements signed on March 15, 2002, as amended, the Group created a “Total Group Savings Plan” (PEGT), a “Partnership for Voluntary Wage Savings Plan” (PPESV, later becoming PERCO) and a “Complementary Company Savings Plan” (PEC) for employees of the Group’s French companies having adhered to these plans. These plans allow investments in a number of mutual funds including one invested in Company shares (“TOTAL

ACTIONNARIAT FRANCE”). A “Shareholder Group Savings Plan” (PEG-A) has also been in place since November 19, 1999 to facilitate capital increases reserved for employees of the Group’s French and foreign subsidiaries covered by these plans.

Company savings plans

The various Company savings plans (PEGT, PEC) give the employees of French Group Companies belonging to these savings plans access to several collective investment funds (fonds communs de placement), including a fund invested in shares of the Company (“TOTAL ACTIONNARIAT FRANCE”).

 

 

121


Table of Contents

The capital increases reserved for employees are conducted under PEG-A through the “TOTAL ACTIONNARIAT FRANCE” fund for employees of the Group’s French subsidiaries and through the “TOTAL ACTIONNARIAT INTERNATIONAL CAPITALISATION” fund for the employees of foreign subsidiaries. In addition, U.S. employees participate in these operations through American Depositary Receipts (ADRs) and Italian employees (as well as German employees starting in 2011) may participate by directly subscribing to new shares at the Group Caisse Autonome in Belgium.

Profit-sharing agreements

Under the June 26, 2009 profit-sharing agreements concerning ten Group companies, the amount available for employees profit-sharing is determined, when permitted by local law, based on the return on equity (ROE) performance of the Group.

Employee shareholding

The total number of TOTAL shares held by employees as of December 31, 2011, is as follows:

 

“TOTAL ACTIONNARIAT FRANCE”

     78,607,765   

“TOTAL ACTIONNARIAT INTERNATIONAL CAPITALISATION”

     19,691,590   

ELF PRIVATISATION N°1

     929,494   

Shares held by U.S. employees

     454,305   

Group Caisse Autonome (Belgium)

     436,431   

TOTAL shares from the exercise of the Company’s stock options and held as registered shares within a Company Savings Plan (PEE)(a)

     3,293,822   

Total shares held by employee shareholder funds

     103,413,407   

 

(a) Company savings plans.

As of December 31, 2011, the employees of the Group held, on the basis of the definition of employee shareholding contained in Article L. 225-102 of the French Commercial Code, 103,413,407 TOTAL shares, representing 4.37% of the Company’s share capital and 8.01% of the voting rights that could be exercised at a Shareholders’ Meeting on that date.

The management of each of the three collective investment funds mentioned above is controlled by a dedicated supervisory board, two-third of its members representing holders of fund units and one-third representing the Company. This board is responsible for reviewing the collective investment funds’ management report and annual financial statements as well as the financial, administrative and accounting management, exercising voting rights attached to portfolio securities, deciding contribution of securities in case of a public tender offer, deciding mergers, spin-offs or liquidations, and granting its

approval prior to changes in the rules and procedures of the collective investment fund in the conditions provided for by the rules and procedures.

These rules and procedures also stipulate a simple majority vote for decisions, except for decisions requiring a qualified majority vote of two-third plus one related to a change in a fund’s rules and procedures, its conversion or disposal, and decisions related to contribution of securities of the Elf Privatisation collective investment fund in case of a public tender offer.

For employees holding shares outside of the employee collective investment funds mentioned in the table above, voting rights are exercised individually.

Capital increase reserved for Group employees

At the Shareholders’ Meeting held on May 21, 2010, the shareholders delegated to the Board of Directors the authority to increase the share capital of the Company in one or more transactions and within a maximum period of twenty-six months from the date of the meeting, reserving subscriptions for such issuance to the Group employees participating in a company savings plan in accordance with the provisions of Articles L. 3332-2 and L. 3332-18 and following of the French Labor Code, and Articles L. 225-129-2, L. 225-129-6 and L. 225-138-1 of the French Commercial Code. The number of ordinary shares that are likely to be issued pursuant to this delegation of authority will not exceed 1.5% of the share capital outstanding on the date of the meeting of the Board of Directors at which a decision to proceed with an issuance is made.

Pursuant to this delegation of authority, the Board of Directors decided on October 28, 2010 to proceed with a capital increase of a maximum of 12 million shares reserved for TOTAL employees in 2011, bearing dividends as of January 1, 2010. The Board of Directors decided to delegate the authority to set the subscription period to the Chairman and Chief Executive Officer.

On March 14, 2011, the Chairman and Chief Executive Officer decided that the subscription period would be set from March 16 to April 1, 2011 and acknowledged that the subscription price per ordinary share would be set at 34.80.

The subscription resulted in the issuance in 2011 of 8,902,717 TOTAL shares.

Shares held by the administration and management bodies

As of December 31, 2011, based on information from the members of the Board and the share registrar, the members of the Board and the Group Executive Officers

 

 

122


Table of Contents

(Management Committee and Treasurer) held a total of less than 0.5% of the share capital:

 

 

Members of the Board of Directors (including the Chairman and Chief Executive Officer): 317,306 shares;

 

Chairman and Chief Executive Officer: 105,556 shares and 53,869 shares of the “TOTAL ACTIONNARIAT FRANCE” collective investment plan;

 

Management Committee (including the Chief Executive Officer) and Treasurer: 572,527 shares.

By decision of the Board of Directors:

 

 

The Chairman and the Chief Executive Officer are required to hold a number of shares of the Company

   

equal in value to two years of the fixed portion of their annual compensation.

 

Members of the Executive Committee are required to hold a number of shares of the Company equal in value to two years of the fixed portion of their annual compensation. These shares have to be acquired within three years from the appointment to the Executive Committee.

The number of TOTAL shares to be considered includes:

 

 

directly held shares, whether or not they are subject to transfer restrictions; and

 

shares in collective investment funds invested in TOTAL shares.

 

 

Summary of transactions in the Company’s securities

The following table presents transactions, of which the Company has been informed, in the Company’s shares or related financial instruments carried out in 2011 by the individuals concerned under paragraphs a) through c) of Article L. 621-18-2 of the French Monetary and Financial Code.

 

Year 2011          Acquisition      Subscription      Transfer      Exchange      Exercise
of stock
options
 
Christophe de Margerie(a)    TOTAL shares                      93,250                 113,576   
     Shares in collective investment plans (FCPE), and other related financial instruments(b)      5,340.09                                   

Michel Bénézit(a)

   TOTAL shares                                         
     Shares in collective investment plans (FCPE), and other related financial instruments(b)      626.95         13,341.83         6,828.94                   

François Cornélis(a)

   TOTAL shares                      9,000                    
     Shares in collective investment plans (FCPE), and other related financial instruments(b)      1,883.86         11,440.06         5,876.63                   
Yves-Louis Darricarrère(a)    TOTAL shares                      14,412                 6,412   
     Shares in collective investment plans (FCPE), and other related financial instruments(b)      901.20         20,088.29         10,319.28                    
Jean-Jacques Guilbaud(a)    TOTAL shares                      29,163                 29,163   
     Shares in collective investment plans (FCPE), and other related financial instruments(b)      1,008.85         14,320.92         8,636.03                   
Bertrand Jacquillat(a)(c)    TOTAL shares      300                 33                   
     Shares in collective investment plans (FCPE), and other related financial instruments(b)                                        
Patrick de La Chevardière(a)    TOTAL shares                                        
     Shares in collective investment plans (FCPE), and other related financial instruments(b)      756.08         14,998.66         7,587.71                   

 

(a) Including the related individuals in the meaning of the provisions of the Article R. 621-43-1 of the French Monetary and Financial Code.
(b) Collective investment funds (FCPE) primarily invested in Company shares.
(c) Director and member of the Audit Committee until May 13, 2011.

 

123


Table of Contents

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major shareholders

Holdings of major shareholders

The major shareholders of TOTAL as of December 31, 2011, 2010 and 2009 are set forth in the table below.

 

     2011     2010     2009  
As of  December 31   % of
share
capital
    % of
voting
rights
    % of
theoretical
voting
rights
(a)
    % of
share
capital
    % of
voting
rights
    % of
share
capital
    % of
voting
rights
 

Groupe Bruxelles Lambert(b)(c)

    4.0        4.0        3.7        4.0        4.0        4.0        4.0   

Compagnie Nationale à Portefeuille(b)(c)

    1.5        1.6        1.4        1.6        1.6        1.4        1.4   

BNP Paribas(b)

    0.2        0.2        0.1        0.2        0.2        0.2        0.2   

Group employees(b)(d)

    4.4        8.0        7.4        4.0        7.7        3.9        7.5   

Other registered shareholders (non-Group)

    1.7        2.8        2.6        1.4        2.5        1.4        2.4   

Treasury shares

    4.6               8.1        4.8               4.9          

of which TOTAL S.A.

    0.4               0.4        0.5               0.6          

of which Total Nucléaire

    0.1               0.2        0.1               0.1          

of which subsidiaries of Elf Aquitaine

    4.2               7.6        4.2               4.2          

Other bearer shareholders

    83.6        83.5        76.7        84.0        84.0        84.2        84.5   

of which holders of ADS(e)

    8.7        8.7        8.0        8.0        8.0        7.5        7.6   

 

(a) Pursuant to article 223-11 of the AMF General Regulation, the number of theoretical voting rights is calculated on the basis of all outstanding shares to which voting rights are attached, including treasury shares that are deprived of voting rights.
(b) Shareholders with an executive officer (or a representative of employees) or director serving as a director of TOTAL S.A.
(c) Groupe Bruxelles Lambert is a company controlled jointly by the Desmarais family and Frère-Bourgeois S.A., and for the latter mainly through its direct and indirect interest in Compagnie Nationale à Portefeuille. In addition, Groupe Bruxelles Lambert and Compagnie Nationale à Portefeuille declared their acting in concert.
(d) Based on the definition of employee shareholding pursuant to Article L. 225-102 of the French Commercial Code.
(e) American Depositary Shares listed on the New York Stock Exchange.

 

As of December 31, 2011, the holdings of the major shareholders were calculated based on 2,363,767,313 shares, representing 2,368,716,634 voting rights exercisable at Shareholders’ Meetings or 2,578,602,075 theoretical voting rights(1) including:

 

 

9,222,905 voting rights attached to the 9,222,905 TOTAL shares held by TOTAL S.A. that are deprived of voting rights; and

 

200,662,536 voting rights attached to the 100,331,268 TOTAL shares held by TOTAL S.A. subsidiaries that cannot be exercised at Shareholders’ Meetings.

For prior years, the holdings of the major shareholders were established on the basis of 2,349,640,931 shares, to which were attached 2,350,274,592 voting rights that could be exercised at the Shareholders’ Meeting, as of December 31, 2010, and of 2,348,422,884 shares to which were attached 2,339,384,550 voting rights that could be exercised at the Shareholders’ Meeting, as of December 31, 2009.

Identification of the holders of bearer shares

In accordance with Article 9 of its by-laws, the Company is authorized, to the extent permitted under applicable law, to identify the holders of securities that grant immediate or future voting rights at the Company’s Shareholders’ Meetings.

Temporary transfer of securities

Pursuant to legal obligations, any legal entity or individual (with the exception of those described in paragraph IV-3° of Article L. 233-7 of the French Commercial Code) holding alone or together a number of shares representing more than 0.5% of the Company’s voting rights pursuant to one or several temporary transfers or similar operations as described by Article L. 225-126 of the French Commercial Code is required to inform the Company and the French Financial Markets Authority of the number of shares temporarily held no later than the third business day preceding the shareholders’ meeting at midnight.

 

 

 

(1) Pursuant to Article 223-11 of the AMF General Regulation, the number of theoretical voting rights is calculated on the basis of all outstanding shares, including those shares held by the Group that are deprived of voting rights.

 

124


Table of Contents

Declarations are to be e-mailed to the Company at: holding.df-shareholdingnotification@total.com.

Failing to declare such information, any share bought under any of the above described temporary transfer operations shall be deprived of voting rights at the relevant Shareholders’ Meeting and at any Shareholders’ Meeting that would be held until such shares are transferred again or returned.

Thresholds notifications

In addition to the legal obligation to inform the Company and the French Financial Markets Authority within four business days when thresholds representing 5%, 10%, 15%, 20%, 25%, 30%, 1/3, 50%, 2/3, 90% or 95% of the share capital or voting rights(1) are crossed (Article L. 233-7 of the French Commercial Code), any individual or entity who directly or indirectly comes to hold a percentage of the share capital, voting rights or rights giving future access to the share capital of the Company which is equal to or greater than 1%, or a multiple of this percentage, is required to notify the Company within fifteen days by registered mail with return receipt requested, and declare the number of securities held.

In case the shares above these thresholds are not declared, any undeclared shares held in excess of the threshold may be deprived of voting rights at future Shareholders’ Meetings if, at that meeting, the failure to make a declaration is acknowledged and if one or more shareholders holding collectively at least 3% of the Company’s share capital or voting rights so request at that meeting.

All individuals and entities are also required to notify the Company in due form and within the time limits stated above when their direct or indirect holdings fall below each of the aforementioned thresholds.

Declarations are to be sent to the Vice President of the Investor Relations department in Paris.

Legal threshold notifications in 2011

Société Générale reported that it had passed:

 

 

on May 6, 2011, above the thresholds of 5% of the share capital and the voting rights of the Company, and that it held after crossing the thresholds 6.86% of the share capital and 6.29% of the voting rights of the Company;

 

on May 25, 2011, below the thresholds of 5% of the share capital and the voting rights of the Company, and that it held after crossing the thresholds 4.92% of the share capital and 4.50% of the voting rights of the Company.

Holdings above the legal thresholds

In accordance with Article L. 233-13 of the French Commercial Code, only one shareholder, Compagnie Nationale à Portefeuille (CNP) and Groupe Bruxelles Lambert (GBL), acting in concert, holds 5% or more of TOTAL’s share capital at year-end 2011(2).

In addition, two known shareholders held 5% or more of the voting rights exercisable at TOTAL Shareholders’ Meetings at year-end 2011:

 

 

CNP jointly with GBL:

In the AMF notice No. 209C1156 dated September 2, 2009, CNP and GBL acting in concert declared that they held more than the threshold of 5% of the voting rights of TOTAL as of August 25, 2009 and held 127,149,464 TOTAL shares representing 127,745,604 voting rights, i.e. 5.42% of the share capital and 5.0009% of the theoretical voting rights(3) (based on a share capital of 2,347,601,812 shares representing 2,554,431,468 voting rights). To the Company’s knowledge, CNP, jointly with GBL, held, as of December 31, 2011, 5.52% of the share capital representing 5.53% of the voting rights exercisable at Shareholders’ Meetings and 5.08% of the theoretical voting rights(3).

 

 

The collective investment fund (fonds commun de placement) “TOTAL ACTIONNARIAT FRANCE”:

To the Company’s knowledge, the collective investment fund (fonds commun de placement) “TOTAL ACTIONNARIAT FRANCE” held, as of December 31, 2011, 3.33% of the share capital representing 6.12% of the voting rights exercisable at a Shareholders’ Meeting and 5.62% of the theoretical voting rights(3).

Shareholders’ agreements

TOTAL is not aware of any agreements among its shareholders.

 

 

 

(1)

Pursuant to Article 223-11 of the AMF General Regulation, the number of voting rights is calculated on the basis of all outstanding shares, including those shares held by the Group that are deprived of voting rights.

(2)

AMF notice No. 209C1156 dated September 2, 2009.

(3)

Pursuant to Article 223-11 of the AMF General Regulation, the number of theoretical voting rights is calculated on the basis of all outstanding shares, including those shares held by the Group that are deprived of voting rights.

 

125


Table of Contents

Treasury shares

As of December 31, 2011, the Company held 109,554,173 TOTAL shares either directly or through its indirect subsidiaries, which represented 4.63% of the share capital, as of this date. By law, these shares are also deprived of voting rights.

TOTAL shares held directly by the Company (treasury shares)

The Company held 9,222,905 treasury shares as of December 31, 2011, representing 0.39% of the share capital, as of that date.

TOTAL shares held directly by Group companies

As of December 31, 2011, Total Nucléaire, a Group company wholly-owned indirectly by TOTAL held 2,023,672 TOTAL shares. As of December 31, 2011,

Financière Valorgest, Sogapar and Fingestval, indirect subsidiaries of Elf Aquitaine, held respectively 22,203,704, 4,104,000 and 71,999,892 TOTAL shares, representing a total of 98,307,596 TOTAL shares. As of December 31, 2011, the Company held through its indirect subsidiaries, 4.24% of the share capital.

Related Party Transactions

The Group’s main transactions with related parties (principally all the investments carried under the equity method) and the balances receivable from and payable to them are shown in Note 24 to the Consolidated Financial Statements.

In the ordinary course of its business, TOTAL enters into transactions with various organizations with which certain of its directors or executive officers may be associated, but no such transactions of a material or unusual nature have been entered into during the period commencing on January 1, 2009, and ending on March 23, 2012.

 

 

ITEM 8. FINANCIAL INFORMATION

 

Consolidated Statements and other supplemental information

See pages F-1 through F-96 for TOTAL’s Consolidated Financial Statements and pages S-1 through S-19 for other supplemental information.

Legal or arbitration proceedings

There are no governmental, legal or arbitration proceedings, including any proceeding that the Company is aware of, threatened with or even pending (including the main legal proceedings described hereafter) that could have a material impact on the Group’s financial situation or profitability. While it is not feasible to predict the outcome of the pending claims, proceedings, and investigations described below with certainty, management is of the opinion that their ultimate disposition should not have a material adverse effect on the Company’s financial position, cash flows, or results of operations.

Antitrust investigations

The principal antitrust proceedings in which the Group’s companies are involved are described below.

Chemicals

 

 

As part of the spin-off of Arkema(1) in 2006, TOTAL S.A. or certain other Group companies agreed

   

to grant Arkema a guarantee for potential monetary consequences related to antitrust proceedings arising from events prior to the spin-off.

This guarantee covers, for a period of ten years from the date of the spin-off, 90% of amounts paid by Arkema related to (i) fines imposed by European authorities or European member-states for competition law violations, (ii) fines imposed by U.S. courts or antitrust authorities for federal antitrust violations or violations of the competition laws of U.S. states, (iii) damages awarded in civil proceedings related to the government proceedings mentioned above, and (iv) certain costs related to these proceedings. The guarantee related to anti-competition violations in Europe applies to amounts above a 176.5 million threshold. On the other hand, the agreements provide that Arkema will indemnify TOTAL S.A. or any Group company for 10% of any amount that TOTAL S.A. or any Group company are required to pay under any of the proceedings covered by this guarantee, in Europe.

If one or more individuals or legal entities, acting alone or together, directly or indirectly holds more than one-third of the voting rights of Arkema, or if Arkema transfers more than 50% of its assets (as calculated under the enterprise valuation method, as of the date

 

 

 

(1)

Arkema is used in this section to designate those companies of the Arkema group whose ultimate parent company is Arkema S.A. Arkema became an independent company after being spun-off from TOTAL S.A. in May 2006.

 

126


Table of Contents

of the transfer) to a third party or parties acting together, irrespective of the type or number of transfers, this guarantee will become void.

 

 

In the United States, civil liability lawsuits, for which TOTAL S.A. has been named as the parent company, are closed without significant impact on the Group’s financial position.

 

 

In Europe, since 2006, the European Commission has fined companies of the Group in its configuration prior to the spin-off an overall amount of 385.47 million, of which Elf Aquitaine and/or TOTAL S.A. were held jointly liable for 280.17 million, Elf Aquitaine being personally fined 23.6 million for deterrence. These fines are entirely settled as of today.

As a result, since the spin-off, the Group has paid the overall amount of 188.07 million(1), corresponding to 90% of the fines overall amount once the threshold provided for by the guarantee is deducted to which an amount of 31.31 million of interest has been added as explained hereinafter.

The European Commission imposed these fines following investigations between 2000 and 2004 into commercial practices involving eight products sold by Arkema. Five of these investigations resulted in prosecutions from the European Commission for which Elf Aquitaine has been named as the parent company, and two of these investigations named TOTAL S.A. as the ultimate parent company of the Group.

TOTAL S.A. and Elf Aquitaine are contesting their liability based solely on their status as parent companies and appealed for cancellation and reformation of the rulings that are still pending before the relevant EU court of appeals or supreme court of appeals.

During the year 2011, four of the proceedings have evolved and are closed as far as Arkema is concerned:

 

  -  

In one of these proceedings, the Court of Justice of the European Union (CJEU) has rejected the action of Arkema while the decisions of the European Commission and of the General Court of the European Union against the parent companies have been squashed. Consequently, this proceeding is definitively closed regarding Arkema as well as the parent companies.

  -  

In two other proceedings, previous decisions against Arkema and the parent companies have been upheld by the General Court of the European Union. While the parent companies have introduced an appeal before the CJEU, Arkema did not appeal to the CJEU.

  -  

Finally, in a last proceeding, the General Court has decided to reduce the amount of the fine initially ordered against Arkema while, in parallel, it has rejected the actions of the parent companies that have remained obliged to pay the whole amount of the fine initially ordered by the European Commission. Arkema has accepted this decision while the parent companies have introduced an appeal before the CJEU.

With the exception of the 31.31 million of interest charged by the European Commission to the parent companies, which has been required to pay in accordance with the decision concerning the last proceeding referred hereinabove, the evolution of the proceedings during the year 2011 did not modify the global amount assumed by the Group in execution of the guarantee.

In addition, civil proceedings against Arkema and other groups of companies were initiated in 2009 and 2011, respectively, before the German and Dutch courts by third parties for alleged damages pursuant to two of the above mentioned legal proceedings. TOTAL S.A. was summoned to serve notice of the dispute before the German court. At this point, the probability to have a favorable verdict and the financial impacts of these proceedings are uncertain due to the number of legal difficulties they give rise to, the lack of documented claims and evaluations of the alleged damages.

Arkema began implementing compliance procedures in 2001 that are designed to prevent its employees from violating antitrust provisions. However, it is not possible to exclude the possibility that the relevant authorities could commence additional proceedings involving Arkema regarding events prior to the spin-off, as well as Elf Aquitaine and/or TOTAL S.A. based on their status as parent company.

Within the framework of all of the legal proceedings described above, a 17 million reserve remains booked in the Group’s consolidated financial statements as of December 31, 2011.

 

 

 

(1) This amount does not take into account a case that led to Arkema, prior to Arkema’s spin-off from TOTAL, and Elf Aquitaine being fined jointly 45 million and Arkema being fined 13.5 million.

 

127


Table of Contents

Downstream

 

 

Pursuant to a statement of objections received by Total Nederland N.V. and TOTAL S.A. (based on its status as parent company) from the European Commission, Total Nederland N.V. was fined 20.25 million in 2006, for which TOTAL S.A. was held jointly liable for 13.5 million. TOTAL S.A. appealed this decision before the relevant court and this appeal is still pending.

 

 

In addition, pursuant to a statement of objections received by Total Raffinage Marketing (formerly Total France) and TOTAL S.A. from the European Commission regarding another product line of the Refining & Marketing division, Total Raffinage Marketing was fined 128.2 million in 2008, which has been paid, and for which TOTAL S.A. was held jointly liable based on its status as parent company. TOTAL S.A. also appealed this decision before the relevant court and this appeal is still pending.

 

 

In addition, civil proceedings against TOTAL S.A and Total Raffinage Marketing and other companies were initiated before U.K and Dutch courts by third parties for alleged damages in connection with the prosecutions brought by the European Commission in this case. At this point, the probability to have a favorable verdict and the financial impacts of these procedures are uncertain due to the number of legal difficulties they gave rise to, the lack of documented claims and evaluations of the alleged damages.

Within the framework of the legal proceedings described above, a 30 million reserve is booked in the Group’s consolidated financial statements as of December 31, 2011.

Whatever the evolution of the proceedings described above, the Group believes that their outcome should not have a material adverse effect on the Group’s financial situation or consolidated results.

Grande Paroisse

An explosion occurred at the Grande Paroisse industrial site in the city of Toulouse in France on September 21, 2001. Grande Paroisse, a former subsidiary of Atofina which became a subsidiary of Elf Aquitaine Fertilisants on December 31, 2004, as part of the reorganization of the Chemicals segment, was principally engaged in the production and sale of agricultural fertilizers. The explosion, which involved a stockpile of ammonium nitrate pellets, destroyed a portion of the site and caused the death of thirty-one people, including twenty-one workers at the site, and injured many others. The explosion also caused

significant damage to certain property in part of the city of Toulouse.

This plant has been closed and individual assistance packages have been provided for employees. The site has been rehabilitated.

On December 14, 2006, Grande Paroisse signed, under the supervision of the city of Toulouse, the deed whereby it donated the former site of the AZF plant to the greater agglomeration of Toulouse (CAGT) and the Caisse des dépôts et consignations and its subsidiary ICADE. Under this deed, TOTAL S.A. guaranteed the site restoration obligations of Grande Paroisse and granted a 10 million endowment to the InNaBioSanté research foundation as part of the setting up of a cancer research center at the site by the city of Toulouse.

Regarding the cause of the explosion, the hypothesis that the explosion was caused by Grande Paroisse through the accidental mixing of hundreds of kilos of a chlorine compound at a storage site for ammonium nitrate was discredited over the course of the investigation. As a result, proceedings against ten of the eleven Grande Paroisse employees charged during the criminal investigation conducted by the Toulouse Regional Court (Tribunal de grande instance) were dismissed and this dismissal was upheld on appeal. Nevertheless, the final experts’ report filed on May 11, 2006 continued to focus on the hypothesis of a chemical accident, although this hypothesis was not confirmed during the attempt to reconstruct the accident at the site. After having articulated several hypotheses, the experts no longer maintain that the accident was caused by pouring a large quantity of a chlorine compound over ammonium nitrate. Instead, the experts have retained a scenario where a container of chlorine compound sweepings was poured between a layer of wet ammonium nitrate covering the floor and a quantity of dry agricultural nitrate at a location not far from the principal storage site. This is claimed to have caused an explosion which then spread into the main storage site. Grande Paroisse was investigated based on this new hypothesis in 2006; Grande Paroisse is contesting this explanation, which it believes to be based on elements that are not factually accurate.

All the requests for additional investigations that were submitted by Grande Paroisse, the former site manager and various plaintiffs were denied on appeal after the end of the criminal investigation procedure. On July 9, 2007, the investigating judge brought charges against Grande Paroisse and the former plant manager before the criminal chamber of the Court of Appeal of Toulouse. In late 2008, TOTAL S.A. and Mr. Thierry Desmarest were summoned to appear in Court pursuant to a request by a victims

 

 

128


Table of Contents

association. The trial for this case began on February 23, 2009, and lasted approximately four months.

On November 19, 2009, the Toulouse Criminal Court acquitted both the former Plant Manager, and Grande Paroisse due to the lack of reliable evidence for the explosion. The Court also ruled that the summonses against TOTAL S.A. and Mr. Thierry Desmarest, Chairman and CEO at the time of the disaster, were inadmissible.

Due to the presumption of civil liability that applied to Grande Paroisse, the Court declared Grande Paroisse civilly liable for the damages caused by the explosion to the victims in its capacity as custodian and operator of the plant.

The Prosecutor’s office, together with certain third parties, has appealed the Toulouse Criminal Court verdict. In order to preserve its rights, Grande Paroisse lodged a cross-appeal with respect to civil charges.

The appeal proceedings before the Court of Appeal of Toulouse was completed on March 16, 2012. The decision is expected on September 24, 2012.

A compensation mechanism for victims was set up immediately following the explosion. 2.3 billion was paid for the compensation of claims and related expenses amounts. As of December 31, 2011, a 21 million reserve was recorded in the Group’s consolidated balance sheet.

Buncefield

On December 11, 2005, several explosions, followed by a major fire, occurred at an oil storage depot at Buncefield, north of London. This depot was operated by Hertfordshire Oil Storage Limited (HOSL), a company in which TOTAL’s UK subsidiary holds 60% and another oil group holds 40%.

The explosion caused injuries, most of which were minor injuries, to a number of people and caused property damage to the depot and the buildings and homes located nearby. The official Independent Investigation Board has indicated that the explosion was caused by the overflow of a tank at the depot. The Board’s final report was released on December 11, 2008. The civil procedure for claims, which had not yet been settled, took place between October and December 2008. The Court’s decision of March 20, 2009, declared TOTAL’s UK subsidiary liable for the accident and solely liable for indemnifying the victims. The subsidiary appealed the decision. The appeal trial took place in January 2010. The Court of Appeals, by a decision handed down on March 4, 2010, confirmed the prior judgment. The Supreme Court of United Kingdom has partially authorized TOTAL’s UK subsidiary to contest the decision. TOTAL’s UK subsidiary finally decided to

withdraw from this recourse due to settlement agreements reached in mid-February 2011.

The Group carries insurance for damage to its interests in these facilities, business interruption and civil liability claims from third parties. The provision for the civil liability that appears in the Group’s consolidated financial statements as of December 31, 2011, stands at 80 million after taking into account the payments previously made.

The Group believes that, based on the information currently available, on a reasonable estimate of its liability and on provisions recognized, this accident should not have a significant impact on the Group’s financial situation or consolidated results.

In addition, on December 1, 2008, the Health and Safety Executive (HSE) and the Environment Agency (EA) issued a Notice of prosecution against five companies, including TOTAL’s UK subsidiary. By a judgment on July 16, 2010, the subsidiary was fined £3.6 million and paid it. The decision takes into account a number of elements that have mitigated the impact of the charges brought against it.

Sinking of the Erika

Following the sinking in December 1999 of the Erika, a tanker that was transporting products belonging to one of the Group companies, the Tribunal de grande instance of Paris convicted TOTAL S.A. of marine pollution pursuant to a judgment issued on January 16, 2008, finding that TOTAL S.A. was negligent in its vetting procedure for vessel selection, and ordering TOTAL S.A. to pay a fine of 375,000. The Court also ordered compensation to be paid to those affected by the pollution from the Erika up to an aggregate amount of 192 million, declaring TOTAL S.A. jointly and severally liable for such payments together with the Erika’s inspection and classification firm, the Erika’s owner and the Erika’s manager.

TOTAL has appealed the verdict of January 16, 2008. In the meantime, it nevertheless proposed to pay third parties who so requested definitive compensation as determined by the Court. Forty-two third parties have been compensated for an aggregate amount of 171.5 million.

By a decision dated March 30, 2010, the Court of Appeal of Paris upheld the lower Court verdict pursuant to which TOTAL S.A. was convicted of marine pollution and fined 375,000. However, the Court of Appeal ruled that TOTAL S.A. bears no civil liability according to the applicable international conventions and consequently ruled that TOTAL S.A. be not convicted.

TOTAL challenged the criminal law-related issues of this decision before the French Supreme Court (Cour de cassation).

 

 

129


Table of Contents

To facilitate the payment of damages awarded by the Court of Appeal in Paris to third parties against Erika’s controlling and classification firm, the ship-owner and the ship-manager, a global settlement agreement was signed late 2011 between these parties and TOTAL S.A. under the auspices of the IOPC Fund. Under this global settlement agreement, each party agreed to the withdrawal of all civil proceedings initiated against all other parties to the agreement.

TOTAL S.A. believes that, based on the information currently available, the case should not have a significant impact on the Group’s financial situation or consolidated results.

Blue Rapid and the Russian Olympic Committee — Russian regions and Interneft

Blue Rapid, a Panamanian company, and the Russian Olympic Committee filed a claim for damages with the Paris Commercial Court against Elf Aquitaine, alleging a so-called non-completion by a former subsidiary of Elf Aquitaine of a contract related to an exploration and production project in Russia negotiated in the early 1990s. Elf Aquitaine believed this claim to be unfounded and opposed it. On January 12, 2009, the Commercial Court of Paris rejected Blue Rapid’s claim against Elf Aquitaine and found that the Russian Olympic Committee did not have standing in the matter. Blue Rapid and the Russian Olympic Committee appealed this decision. On June 30, 2011, the Court of Appeal of Paris dismissed as inadmissible the claim of Blue Rapid and the Russian Olympic Committee against Elf Aquitaine, notably on the grounds of the contract’s termination. Blue Rapid and the Russian Olympic Committee appealed this decision to the French Supreme Court.

In connection with the same facts, and fifteen years after the termination of the exploration and production contract, a Russian company, which was held not to be the contracting party to the contract, and two regions of the Russian Federation which were not even parties to the contract, have launched an arbitration procedure against the aforementioned former subsidiary of Elf Aquitaine that was liquidated in 2005, claiming alleged damages of U.S.$22.4 billion. For the same reasons as those successfully adjudicated by Elf Aquitaine against Blue Rapid and the Russian Olympic Committee, the Group considers this claim to be unfounded as to a matter of law or fact. The Group has lodged a criminal complaint to denounce the fraudulent claim which the Group believes it is a victim of and, has taken and reserved its rights to take other actions and measures to defend its interests.

Iran

In 2003, the United States Securities and Exchange Commission (SEC) followed by the Department of Justice (DoJ) issued a formal order directing an investigation in connection with the pursuit of business in Iran, by certain oil companies including, among others, TOTAL.

The inquiry concerns an agreement concluded by the Company with a consultant concerning a gas field in Iran and aims to verify whether certain payments made under this agreement would have benefited Iranian officials in violation of the Foreign Corrupt Practices Act (FCPA) and the Company’s accounting obligations.

Investigations are still pending and the Company is cooperating with the SEC and the DoJ. In 2010, the Company opened talks with U.S. authorities, without any acknowledgement of facts, to consider an out-of-court settlement as it is often the case in this kind of proceeding.

Late in 2011, the SEC and the DoJ proposed to TOTAL out-of-court settlements that would close their inquiries, in exchange for TOTAL’s committing to a number of obligations and paying fines. As TOTAL was unable to agree to several substantial elements of the proposal, the Company is continuing discussions with the U.S. authorities. The Company is free not to accept an out-of-court settlement solution, in which case it would be exposed to the risk of prosecution in the United States.

In this same affair, a parallel judicial inquiry related to TOTAL was initiated in France in 2006. In 2007, the Company’s Chief Executive Officer was placed under formal investigation in relation to this inquiry, as the former President of the Middle East department of the Group’s Exploration & Production division. The Company has not been notified of any significant developments in the proceedings since the formal investigation was launched.

At this point, the Company cannot determine when these investigations will terminate, and cannot predict their results, or the outcome of the talks that have been initiated. Resolving these cases is not expected to have a significant impact on the Group’s financial situation or consequences on its future planned operations.

Libya

In June 2011, the SEC issued to certain oil companies — including, among others, TOTAL — a formal request for information related to their operations in Libya. TOTAL is cooperating with this non-public investigation.

 

 

130


Table of Contents

Oil-for-Food Program

Several countries have launched investigations concerning possible violations related to the United Nations (UN) Oil-for-Food program in Iraq.

Pursuant to a French criminal investigation, certain current or former Group employees were placed under formal criminal investigation for possible charges as accessories to the misappropriation of corporate assets and as accessories to the corruption of foreign public agents. The Chairman and Chief Executive Officer of the Company, formerly President of the Group’s Exploration & Production division, was also placed under formal investigation in October 2006. In 2007, the criminal investigation was closed and the case was transferred to the Prosecutor’s office. In 2009, the Prosecutor’s office recommended to the investigating judge that the case against the Group’s current and former employees and TOTAL’s Chairman and Chief Executive Officer not be pursued.

In early 2010, despite the recommendation of the Prosecutor’s office, a new investigating judge, having taken over the case, decided to indict TOTAL S.A. on bribery charges as well as complicity and influence peddling. The indictment was brought eight years after the beginning of the investigation without any new evidence being introduced.

In October 2010, the Prosecutor’s office recommended to the investigating judge that the case against TOTAL S.A., the Group’s current and former employees and TOTAL’s Chairman and Chief Executive Officer not be pursued. However, by ordinance notified in early August 2011, the investigating judge on the matter decided to send the case to trial. The hearings are expected in the first quarter of 2013.

The Company believes that its activities related to the Oil-for-Food program have been in compliance with this program, as organized by the UN in 1996. The Volcker report released by the independent investigating committee set up by the UN had discarded any bribery grievance within the framework of the Oil-For-Food program with respect to TOTAL.

Italy

As part of an investigation led by the Prosecutor of the Republic of the Potenza Court, Total Italia and certain Group’s employees are the subject of an investigation related to certain calls for tenders that Total Italia made for the preparation and development of an oil field. On February 16, 2009, as a preliminary measure before the proceedings go before the Court, the preliminary investigation judge of Potenza served notice to Total Italia

of a decision that would suspend the concession for this field for one year. Total Italia has appealed the decision by the preliminary investigation judge before the Court of Appeal of Potenza. In a decision dated April 8, 2009, the Court reversed the suspension of the Gorgoglione concession and appointed for one year, i.e. until February 16, 2010, a judicial administrator to supervise the operations related to the development of the concession, allowing the Tempa Rossa project to continue.

The criminal investigation was closed in the first half of 2010. The preliminary hearing judge, who will decide whether the case shall be returned to the Criminal Court to be judged on the merits, held the first hearing on December 6, 2010. The proceedings before the Judge of the preliminary hearing are still pending.

In 2010, Total Italia’s exploration and production operations were transferred to Total E&P Italia and refining and marketing operations were merged with those of Erg Petroli.

Dividend policy

The Company has paid dividends on its share capital in each year since 1946. Future dividends will depend on the Company’s earnings, financial condition and other factors. The payment and amount of dividends are subject to the recommendation of the Board of Directors and resolution by the Company’s shareholders at the annual Shareholders’ Meeting.

Until the payment of the 2010 dividend, the Company paid an interim dividend in November and the remainder after the Shareholders’ Meeting held in May of each year. Consequently, for 2010, an interim dividend of 1.14 per share and the remainder of 1.14 per share were paid respectively on November 17, 2010 and May 26, 2011.

On October 28, 2010, the Board of Directors decided to change its interim dividend policy and to adopt a new policy based on quarterly dividend payments, starting in 2011.

TOTAL paid three quarterly interim dividends for 2011:

 

 

The Board of Directors decided on the first quarterly interim dividend on April 28, 2011, with an ex-dividend date on September 19, 2011 and a payment date on September 22, 2011;

 

The Board of Directors decided on the second quarterly interim dividend on July 28, 2011, with an ex-dividend date on December 19, 2011 and a payment date on December 22, 2011;

 

 

131


Table of Contents
 

The Board of Directors decided on the third quarterly interim dividend on October 27, 2011, with an ex-dividend date on March 19, 2012 and a payment date on March 22, 2011.

For 2011, TOTAL plans to continue its dividend policy by proposing a dividend of 2.28 per share at the Shareholders’ Meeting on May 11, 2012, including a remainder of 0.57 per share, with an ex-dividend date on June 18, 2012, and a payment on June 21, 2012. This 2.28 per share dividend is stable compared to the previous year.

Subject to the applicable legislative and regulatory provisions, and pending the approval by the Board of Directors for the interim dividends and by the shareholders at the Shareholders’ Meeting for the accounts and the final dividend, the ex-date calendar for the interim quarterly dividends and the final dividend for 2012 should be as follows:

 

 

1st interim dividend: September 24, 2012;

 

2nd interim dividend: December 17, 2012;

 

3rd interim dividend: March 18, 2013;

 

remainder: June 24, 2013.

The provisional ex-dividend dates above relate to the TOTAL shares traded on the Euronext Paris.

Dividends paid to holders of ADRs will be subject to a charge by the Depositary for any expenses incurred by the Depositary in the conversion of euro to dollars. See “Item 10. Additional Information — Taxation”, for a summary of certain U.S. federal and French tax consequences to holders of shares and ADRs.

Significant changes

For a description of significant changes that have occurred since the date of the Company’s Consolidated Financial Statements, see “Item 4. Information on the Company” and “Item 5. Operating and Financial Review and Prospects”, which include descriptions of certain recent 2012 activities.

 

 

ITEM 9. THE OFFER AND LISTING

 

Markets

The principal trading market for the shares is the Euronext Paris exchange in France. The shares are also listed on Euronext Brussels and the London Stock Exchange.

Offer and listing details

Trading on Euronext Paris

Official trading of listed securities on Euronext Paris, including the shares, is transacted through French investment service providers that are members of Euronext Paris and takes place continuously on each business day in Paris from 9:00 a.m. to 5:30 p.m. (Paris time), with a fixing of the closing price at 5:35 p.m. Euronext Paris may suspend or resume trading in a security listed on Euronext Paris, if the quoted price of the security exceeds certain price limits defined by the regulations of Euronext Paris.

The markets of Euronext Paris settle and transfer ownership three trading days after a transaction (T+3). Highly liquid shares, including those of the Company, are eligible for deferred settlement (Service de Règlement Différé — SRD). Payment and delivery for shares under the SRD occurs on the last trading day of each month. Use of the SRD service requires payment of a commission. Under this system, the determination date for settlement on the following month occurs on the fifth trading day prior to the last trading day (inclusive) of each month.

In France, the shares are included in the principal index published by Euronext Paris (the “CAC 40 Index”). The CAC 40 Index is derived daily by comparing the total market capitalization of 40 stocks traded on Euronext Paris to the total market capitalization of the stocks that made up the CAC 40 Index on December 31, 1987. Adjustments are made to allow for expansion of the sample due to new issues. The CAC 40 Index indicates trends in the French stock market as a whole and is one of the most widely followed stock price indices in France. In the UK, the shares are listed in both the FTSE Eurotop 100 and FTSEurofirst 300 index. As a result of the creation of Euronext, the shares are included in Euronext 100, the index representing Euronext’s blue chip companies based on market capitalization. The shares are also included in the Dow Jones Stoxx 50 and Dow Jones Euro Stoxx 50, blue chip indices comprised of the fifty most highly capitalized and most actively traded equities throughout Europe and within the European Monetary Union, respectively. Since June 2000, the shares have been included in the Dow Jones Global Titans Index which consists of fifty global companies selected based on market capitalization, book value, assets, revenue and earnings.

The table below sets forth, for the periods indicated, the reported high and low quoted prices in euros for the currently outstanding shares on Euronext Paris.

 

 

132


Table of Contents
Price per share ()    High      Low  

2007

     63.40         48.33   

2008

     59.50         31.52   

2009

     45.785         34.25   

2010

     46.735         35.655   

First Quarter

     46.735         40.050   

Second Quarter

     44.625         36.210   

Third Quarter

     41.000         35.655   

Fourth Quarter

     41.275         36.910   

2011

     44.550         29.400   

First Quarter

     44.550         39.710   

Second Quarter

     43.730         37.305   

Third Quarter

     40.895         29.400   

September

     34.820         29.400   

Fourth Quarter

     39.810         31.730   

October

     39.810         31.730   

November

     38.705         34.570   

December

     39.605         35.940   

2012 (through February 29)

     42.400         38.570   

January

     40.890         38.570   

February

     42.400         40.225   

 

Trading on the New York Stock Exchange

ADSs evidenced by ADRs have been listed on the New York Stock Exchange since October 25, 1991. The Bank of New York Mellon serves as depositary with respect to the ADSs evidenced by ADRs traded on the New York

Stock Exchange. One ADS corresponds to one TOTAL share. The table below sets forth, for the periods indicated, the reported high and low prices quoted in dollars for the currently outstanding ADSs evidenced by ADRs on the New York Stock Exchange.

 

 

Price per ADR ($)    High      Low  

2007

     87.34         63.89   

2008

     91.34         42.60   

2009

     65.98         42.88   

2010

     67.52         43.07   

First Quarter

     67.52         54.01   

Second Quarter

     60.24         43.07   

Third Quarter

     54.14         44.43   

Fourth Quarter

     58.06         48.08   

2011

     64.44         40.00   

First Quarter

     62.31         52.61   

Second Quarter

     64.44         53.04   

Third Quarter

     58.25         40.00   

September

     49.79         40.00   

Fourth Quarter

     55.93         41.85   

October

     55.93         41.85   

November

     52.89         46.72   

December

     52.46         47.00   

2012 (through February 29)

     57.06         48.82   

January

     53.41         48.82   

February

     57.06         53.01   

ITEM 10. ADDITIONAL INFORMATION

 

Memorandum and Articles of Association

Register information

TOTAL S.A. is registered with the Nanterre Trade Register under the registration number 542 051 180.

Objects and purposes

The Company’s purpose can be found in Article 3 of its bylaws (statuts). Generally, the Company may engage in all activities relating to: (i) the exploration and extraction of mining deposits and the performance of industrial refining, processing, and trading of these materials, as well as their derivatives and by-products; (ii) the production and

 

 

133


Table of Contents

distribution of all forms of energy; (iii) the chemicals, rubber and health industries; (iv) the transportation and shipping of hydrocarbons and other products or materials relating to the Company’s business purpose; and (v) all financial, commercial, and industrial operations and operations relating to any fixed or unfixed assets and real estate, acquisitions of interests or holdings in any business or company that may relate to any of the above-mentioned purposes or to any similar or related purposes, of such nature as to promote the Company’s extension or its development.

Director issues

Compensation

Directors receive attendance fees, the maximum aggregate amount of which, determined by the shareholders acting at a shareholders’ meeting, remains in effect until a new decision is made. The Board of Directors may apportion this amount among its members in whatever way it considers appropriate. In addition, the Board may also grant its Chairman compensation.

Retirement

The number of directors of TOTAL who are acting in their own capacity or as permanent representatives of a legal entity and are over seventy years old may not exceed one-third of the number of directors in office at the end of the fiscal year. If such number is exceeded, the oldest Board member is automatically deemed to have resigned. Directors who are the permanent representative of a legal person may not continue in office beyond their seventieth birthday.

Currently, the duties of the Chairman of the Board automatically cease on his sixty-fifth birthday at the latest. At their meeting of May 15, 2009, the shareholders adopted an amendment of the bylaws pertaining to the rules relating to the nomination of the Chairman. The amendment allows the Board, as an exception to the currently applicable sixty-five year age limit, to appoint as Chairman of the Board for a period of up to two years a director who is more than sixty-five years old but less than seventy years old.

Shareholdings

Each director must own at least 1,000 shares of TOTAL during his or her term of office, except the director representing the employees shareholder who shall hold, either individually or through an investment trust governed by Article L.214-40 of the Monetary & Financial Code

(French FCPE), at least one share or a number of stocks in such investment trust amounting to at least one share.

Election

Directors are elected for a term of three years. In 2003, TOTAL amended its Articles of Incorporation to provide for the election of one director to represent employee shareholders. This director was appointed for the first time at the shareholders’ meeting held on May 14, 2004.

Description of shares

The following is a summary of the material rights of holders of fully paid shares and is based on the bylaws of the Company and French Company Law as codified in Volume II (Livre II) of the French Commercial Code (referred to herein as the “French Company Law”). For more complete information, please read the bylaws of TOTAL S.A., a copy of which has been filed as an exhibit to this Annual Report.

Dividend rights

The Company may make dividend distributions to its shareholders from net income in each fiscal year, after deduction of the overhead and other social charges, as well as of any amortization of the business assets and of any provisions for commercial and industrial contingencies, as reduced by any loss carried forward from prior years, and less any contributions to reserves or amounts that the shareholders decide to carry forward. These distributions are also subject to the requirements of French Company Law and the Company’s bylaws.

Under French Company Law, the Company must allocate 5% of its net profits in each fiscal year to a legal reserve fund until the amount in that fund is equal to 10% of the nominal amount of its share capital.

The Company’s bylaws provide that its shareholders may decide to allocate all or a part of any distributable profits among special or general reserves, to carry them forward to the next fiscal year as retained earnings, or to allocate them to the shareholders as dividends. The bylaws provide that the shareholders’ meeting held to approve the financial statements for the financial year may decide to grant an option to each shareholder between payment of the dividend in cash and payment in shares with respect to all or part of the dividend or interim dividends.

Under French Company Law, the Company must distribute dividends to its shareholders pro rata, according to their shareholdings. Dividends are payable to holders of outstanding shares on the date fixed by the shareholders’

 

 

134


Table of Contents

meeting approving the distribution of dividends or, in the case of interim dividends, on the date fixed by the Company’s Board of Directors at the meeting that approves the distribution of interim dividends. Under French law, dividends not claimed within five years of the date of payment revert to the French State.

Voting rights

Each shareholder of the Company is entitled to the number of votes he or she possesses, or for which he or she holds proxies. According to French Company Law, voting rights may not be exercised in respect of fractional shares.

According to the Company’s bylaws, each registered share that is fully paid and registered in the name of the same shareholder for a continuous period of at least two years is granted a double voting right after such two-year period. Upon capital increase by capitalization of reserves, profits or premiums on shares, a double voting right is granted to each registered share allocated to a shareholder relating to previously existing shares that already carry double voting rights. The double voting right is automatically canceled when the share is converted into a bearer share or when the share is transferred, unless the transfer is due to inheritance, division of community property between spouses, or a donation during the lifetime of the shareholder to the benefit of a spouse or relatives eligible to inherit.

French Company Law limits a shareholder’s right to vote notably in the following circumstances:

 

 

shares held by the Company or by entities controlled by the Company under certain conditions, which cannot be voted;

 

shares held by shareholders making a contribution in-kind to the Company, which cannot be voted with respect to resolutions relating to such in-kind contributions; and

 

shares held by interested parties, which cannot be voted with respect to resolutions relating to such shareholders.

Under the Company’s bylaws, the voting rights exercisable by a shareholder, directly, indirectly or by proxy, at any shareholders’ meeting are limited to 10% of the total number of voting rights attached to the shares on the date of such shareholders’ meeting. This 10% limitation may be increased by taking into account double voting rights held directly or indirectly by the shareholder or by proxy, provided that the voting rights exercisable by a shareholder at any shareholders’ meeting may never exceed 20% of the total number of voting rights attached to the shares.

According to the Company’s bylaws, these limitations on voting lapse automatically if any individual or entity acting

alone or in concert with an individual or entity holds at least two-thirds of the total number of shares as a result of a tender offer for 100% of the shares.

Liquidation rights

In the event the Company is liquidated, its assets remaining after payment of its debts, liquidation expenses and all of its other remaining obligations will first be distributed to repay the nominal value of the shares. After these payments have been made, any surplus will be distributed pro rata among the holders of shares based on the nominal value of their shareholdings.

Redemption provisions

The Company’s shares are not subject to any redemption provisions.

Sinking fund provisions

The Company’s shares are not subject to any sinking fund provisions.

Future capital calls

Shareholders are not liable to the Company for further capital calls on their shares.

Preferential subscription rights

Holders of shares have preferential rights to subscribe on a pro rata basis for additional shares issued for cash. Shareholders may waive their preferential rights, either individually or, under certain circumstances, as a specifically named group at an extraordinary shareholders’ meeting. During the subscription period relating to a particular offering of shares, shareholders may transfer their preferential subscription rights that they have not previously waived.

Changes in share capital

Under French Company Law, the Company may increase its share capital only with the approval of its shareholders at an extraordinary shareholders’ meeting (or with a delegation of authority from its shareholders). There are two methods to increase share capital: (i) by issuing additional shares, including the creation of a new class of securities and (ii) by increasing the nominal value of existing shares. The Company may issue additional shares for cash or for assets contributed in kind, upon the conversion of debt securities, or other securities giving access to its share capital, that it may have issued, by capitalization of its reserves, profits or issuance premiums or, subject to certain conditions, in satisfaction of its indebtedness.

 

 

135


Table of Contents

Under French Company Law, the Company may decrease its share capital only with the approval of its shareholders at an extraordinary shareholders’ meeting (or with a delegation of authority from its shareholders). There are two methods to reduce share capital: (i) by reducing the number of shares outstanding, and (ii) by decreasing the nominal value of existing shares. The conditions under which the share capital may be reduced will vary depending upon whether the reduction is attributable to losses. The Company may reduce the number of outstanding shares either by an exchange of shares or by the repurchase and cancellation of its shares. If the reduction is attributable to losses, shares are cancelled through offsetting the Company’s losses. Any decrease must meet the requirements of French Company Law, which states, among other things, that all the holders of shares in each class of shares must be treated equally, unless the affected shareholders otherwise agree.

Form of shares

The Company has only one class of shares, par value 2.50 per share. Shares may be held in either bearer or registered form. Shares traded on Euronext Paris are cleared and settled through Euroclear France. The Company may use any lawful means to identify holders of shares, including a procedure known as titres au porteur identifiable according to which Euroclear France will, upon the Company’s request, disclose to the Company the name, nationality, address and number of shares held by each shareholder in bearer form. The information may only be requested by the Company and may not be communicated to third parties.

Holding of shares

Under French Company Law and since the “dematerialization” of securities, the ownership rights of shareholders are represented by book entries instead of share certificates (other than certificates representing French securities, which are outstanding exclusively outside the territory of France and are not held by French residents). Registered shares are entered into an account maintained by the Company or by a representative that it has nominated, while shares in bearer form must be held in an account maintained by an accredited financial intermediary on the shareholder’s behalf.

For all shares in registered form, the Company maintains a share account with Euroclear France which is administered by BNP Paribas Securities Services. In addition, the Company maintains accounts in the name of each registered shareholder either directly or, at a shareholder’s request, through a shareholder’s accredited intermediary,

in separate accounts maintained by BNP Paribas Securities Services on behalf of the Company. Each shareholder’s account shows the name and number of shares held and, in the case of shares registered through an accredited financial intermediary, the fact that they are so held. BNP Paribas Securities Services, as a matter of course, issues confirmations to each registered shareholder as to shares registered in a shareholder’s account, but these confirmations do not constitute documents of title.

Shares held in bearer form are held and registered on the shareholder’s behalf in an account maintained by an accredited financial intermediary and are credited to an account at Euroclear France maintained by the intermediary. Each accredited financial intermediary maintains a record of shares held through it and will issue certificates of inscription for the shares that it holds. Transfers of shares held in bearer form only may be made through accredited financial intermediaries and Euroclear France.

Cancellation of treasury shares

After receiving authorization through a shareholders’ meeting, the Board of Directors of the Company may cancel treasury shares owned by the Company in accordance with French Company Law up to a maximum of 10% of the share capital within any period of twenty-four months.

Description of TOTAL share certificates

The TOTAL share certificates are issued by Euroclear France. French law allows Euroclear France to create certificates representing French securities provided that these certificates are intended to be outstanding exclusively outside the territory of France and cannot be held by residents of France. Furthermore, TOTAL share certificates may not be held by a foreign resident in France, either personally or in the form of a bank deposit, but the coupons and rights may be exercised in France.

Certificates for TOTAL shares are either in bearer form or registered in a securities trading account. Under Euroclear France regulations applicable to bearer stock certificates, TOTAL share certificates cannot be categorized as secondary securities, such as ADSs, issued by a foreign company to represent TOTAL shares.

TOTAL share certificates have the characteristics of a bearer security, meaning they are:

 

 

negotiable outside France;

 

transmitted by delivery; and

 

 

136


Table of Contents
 

fungible with TOTAL share certificates, which may be converted freely from bearer form to registration in an account.

 

All rights attached to TOTAL shares must be exercised directly by the bearer of the TOTAL share certificates.

 

 

Share capital history

 

Fiscal 2009

  

July 30, 2009

   Reduction of the share capital from 5,929,520,185 to 5,867,520,185, through the cancellation of 24,800,000 treasury shares, par value 2.50.

January 1, 2010

   Certification of the issuance of 1,414,810 new shares, par value 2.50 per share, between January 1 and December 31, 2009, raising the share capital by 3,537,025 from 5,867,520,185 to 5,871,057,210 (of which 934,780 new shares issued through the exercise of the Company’s stock options and 480,030 new shares through the exchange of 80,005 shares of Elf Aquitaine stock resulting from the exercise of Elf Aquitaine stock options and eligible for a guaranteed exchange for TOTAL shares).

Fiscal 2010

  

January 12, 2011

   Certification of the issuance of 1,218,047 new shares, par value 2.50, through the exercise of the Company’s stock options between January 1 and December 31, 2010, raising the share capital by 3,045,117.50 from 5,871,057,210 to 5,874,102,327.50.

Fiscal 2011

  

April 28, 2011

   Certification of the subscription to 8,902,717 new shares, par value 2.50, as part of the capital increase reserved for Group employees approved by the Board of Directors on October 28, 2010, raising the share capital by 22,256,792.50, from 5,874,102,327.50 to 5,896,359,120.

January 12, 2012

   Certification of the issuance of 5,223,665 new shares, par value 2.50, through the exercise of the Company’s stock options between January 1 and December 31, 2011, raising the share capital by 13,059,162.50 from 5,896,359,120 to 5,909,418,282.50.

 

Authorized share capital not issued as of December 31, 2011

The following is a summary of the currently valid delegations and authorizations to increase share capital that have been granted by the Shareholders’ Meeting to the Board of Directors.

Seventeenth resolution of the Shareholders’ Meeting held on May 21, 2010

Delegation of authority granted by the Shareholders’ Meeting to the Board of Directors to increase the share capital by issuing common shares or other securities granting immediate or future rights to the Company’s share capital, maintaining shareholders’ pre-emptive subscription rights up to a maximum nominal amount of 2.5 billion, i.e., 1 billion shares (delegation of authority valid for twenty-six months).

Furthermore, the maximum nominal amount of the debt securities granting rights to the Company’s share capital that may be issued pursuant to the seventeenth resolution and the eighteenth resolution (mentioned below) may not exceed 10 billion, or their exchange value, on the date of issuance.

Eighteenth resolution of the Shareholders’ Meeting held on May 21, 2010

Delegation of authority granted by the Shareholders’ Meeting to the Board of Directors to increase the share capital by issuing common shares or other securities granting immediate or future rights to the Company’s share capital, canceling shareholders’ pre-emptive subscription rights, including the compensation comprised of securities as part of a public exchange offer, provided that they meet the requirements of Article L. 225-148 of the French Commercial Code. This resolution grants the Board of Directors the authority to grant a priority period for shareholders to subscribe to these securities pursuant to the provisions of Article L. 225-135 of the French Commercial Code. The total amount of the capital increases without pre-emptive subscription rights likely to occur immediately or in the future cannot exceed the nominal amount of 850 million, i.e., 340 million shares, par value 2.50 (delegation of authority valid for twenty-six months). The nominal amount of the capital increases is counted against the maximum aggregate nominal amount of 2.5 billion authorized by the seventeenth resolution of the Shareholders’ Meeting held on May 21, 2010.

 

 

137


Table of Contents

Furthermore, the maximum nominal amount of the debt securities granting rights to the Company’s share capital that may be issued pursuant to the above mentioned seventeenth and eighteenth resolutions may not exceed 10 billion, or their exchange value, on the date of issuance.

Nineteenth resolution of the Shareholders’ Meeting held on May 21, 2010

Delegation of power granted by the Shareholders’ Meeting to the Board of Directors to increase the share capital by issuing new ordinary shares or other securities granting immediate or future rights to the Company’s share capital as compensation of in-kind contribution granted to the Company, by an amount not exceeding 10% of the share capital outstanding at the date of the Shareholders’ Meeting on May 21, 2010 (delegation of authority valid for twenty-six months). The nominal amount of the capital increases is counted against the maximum aggregate nominal amount of 850 million authorized by the eighteenth resolution of the Shareholders’ Meeting held on May 21, 2010.

Twentieth resolution of the Shareholders’ Meeting held on May 21, 2010

Delegation of authority to the Board of Directors to complete capital increases reserved for employees participating in the Company Savings Plan (Plan d’épargne d’entreprise), up to a maximum amount equal to 1.5% of the outstanding share capital on the date of the decision of the Board of Directors to proceed with the issue (delegation of authority valid for twenty-six months). It is being specified that the amount of the capital increase is counted against the maximum aggregate nominal amount of 2.5 billion authorized by the seventeenth resolution of the Shareholders’ Meeting held on May 21, 2010.

Given that the Board of Directors made use of this delegation of authority on October 28, 2010, under which 8,902,717 new TOTAL shares were issued in 2011, the authorized share capital not issued with respect to capital increases reserved for employees participating in a Company Savings Plan was 66,384,480 as of December 31, 2011, representing 26,553,792 shares.

As a result of the use of the delegation authorizing capital increases reserved for employees decided by the Board on October 28, 2010, and given that the Board of Directors did not make use of the delegations of authority granted by the seventeenth, eighteenth and nineteenth resolutions of the Shareholders’ Meeting held on May 21, 2010, the

authorized capital not issued was 2.48 billion as of December 31, 2011, representing 991 million shares.

Eleventh resolution of the Shareholders’ Meeting held on May 13, 2011

Authority to grant restricted outstanding or new TOTAL shares to employees of the Group and to executive officers up to a maximum of 0.8% of the share capital outstanding on the date of the meeting of the Board of Directors that approves the restricted share grants. In addition, the shares granted to the Company’s executive officers cannot exceed 0.01% of the outstanding share capital on the date of the meeting of the Board of Directors that approves the grants (authorization valid for thirty-eight months).

Pursuant to this authorization:

 

 

3,700,000 outstanding shares were awarded by the Board of Directors on September 14, 2011, including 16,000 outstanding shares awarded to the Chairman and Chief Executive.

As of December 31, 2011, 15,210,138 shares, including 220,376 to the Company’s corporate executive officers could, therefore, still be awarded pursuant to this authorization.

Twenty-first resolution of the Shareholders’ Meeting held on May 21, 2010

Authority to grant stock options reserved for TOTAL employees and to executive and officers up to a maximum of 1.5% of the share capital outstanding on the date of the meeting of the Board of Directors that approves the stock option grant. In addition, the options granted to the Company’s corporate executive officers cannot exceed 0.1% of the outstanding share capital on the date of the meeting of the Board of Directors that approves the grants (authorization valid for thirty-eight months).

Pursuant to this authorization:

 

 

4,925,000 stock options were awarded by the Board of Directors at its meeting on September 14, 2010, including 240,000 stock options to the Chairman and Chief Executive Officer;

 

1,600,000 stock options were awarded by the Board of Directors at its meeting on September 14, 2011, including 160,000 stock options to the Chairman and Chief Executive Officer.

As of December 31, 2011, 28,931,509 stock options, including 1,963,767 to the Company’s corporate executive officers, could still be awarded pursuant to this authorization.

 

 

138


Table of Contents

Seventeenth resolution of the Shareholders’ Meeting held on May 11, 2007

Authority to cancel shares up to a maximum of 10% of the share capital of the Company existing as of the date of the operation within a twenty-four-month period. This authorization is effective until the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2011. The Board did not make use of this delegation of authority during fiscal year 2011.

Based on 2,363,767,313 shares outstanding on December 31, 2011, the Company may, up until the conclusion of the Shareholders’ Meeting called to approve the financial statements for the fiscal year ending on December 31, 2011, cancel a maximum of 236,376,731 shares before reaching the cancellation threshold of 10% of share capital canceled during a twenty-four-month period.

Other issues

Shareholders’ meetings

French companies may hold either ordinary or extraordinary shareholders’ meetings. Ordinary shareholders’ meetings are required for matters that are not specifically reserved by law to extraordinary shareholders’ meetings: the election of the members of the Board of Directors, the appointment of statutory auditors, the approval of a management report prepared by the Board of Directors, the approval of the annual financial statements, the declaration of dividends and the issuance of bonds (if the bylaws so provide). Extraordinary shareholders’ meetings are required for approval of amendments to a company’s bylaws, modification of shareholders’ rights, mergers, increases or decreases in share capital, including a waiver of preferential subscription rights, the creation of a new class of shares, the authorization of the issuance of investment certificates or securities convertible, exchangeable or redeemable into shares and for the sale or transfer of substantially all of a company’s assets.

The Company’s Board of Directors is required to convene an annual shareholders’ meeting for approval of the annual financial statements. This meeting must be held within six months of the end of the fiscal year. However, the president of the Tribunal de Commerce of Nanterre, the local French commercial court, may grant an extension of this six-month period. The Company may convene other ordinary and extraordinary meetings at any time during the year. Meetings of shareholders may be convened by the Board of Directors or, if it fails to call a meeting, by the Company’s statutory auditors or by a court-appointed

agent. A shareholder or group of shareholders holding at least 5% of the share capital, the employee committee or another interested party under certain exceptional circumstances, may request that the court appoint an agent. The notice of meeting must state the agenda for the meeting.

French Company Law requires that a preliminary notice of a listed company’s shareholders’ meeting be published in the Bulletin des annonces légales obligatoires (“BALO”) at least thirty-five days prior to the meeting (or fifteen days in the event the Company is subject to a tender offer and the Company calls a shareholders’ meeting to approve measures, the implementation of which would be likely to cause such tender offer to fail). The preliminary notice must first be sent to the French Financial Markets Authority (Autorité des marchés financiers) (“AMF”) with an indication of the date it is to be published in the BALO.

The preliminary notice must include the agenda of the meeting and the proposed resolutions that will be submitted to a shareholders’ vote.

One or more shareholders holding a certain percentage of the Company’s share capital determined on the basis of a formula related to capitalization may propose to add on the shareholders’ meeting’s agenda additional resolutions to be submitted to a shareholders’ vote and/or matters without a shareholders’ vote (points), provided that the text of additional resolutions or matters be received by the Company on at least the twenty-fifth day preceding the meeting (or at least the tenth day in the event the Company is subject to a tender offer and the Company calls a shareholders’ meeting to approve measures that, if implemented, would likely cause such tender offer to fail). The demand of the shareholders’ that are eligible to require for the inscription of matters on the meeting agenda has to be duly motivated.

French Company Law also requires that the preliminary notice of a listed company’s shareholders’ meeting, as well as the additional resolutions and/or matters presented by the shareholders under the terms and conditions prescribed under French law, be published on the Company’s Web site during a period starting at the latest on the twenty-first day prior to the meeting (or the fifteenth day in the event the Company is subject to a tender offer and the Company calls a shareholders’ meeting to approve measures that, if implemented, would likely cause such tender offer to fail).

Notice of a shareholders’ meeting is sent by postal or electronic mail at least fifteen days (or six days in the event of shareholders’ meetings convened in the situation where the Company was subject to a tender offer to approve

 

 

139


Table of Contents

measures, the implementation of which would be likely to cause such tender offer to fail) before the meeting to all holders of registered shares who have held their shares for more than one month. However, in the case where the original meeting was adjourned because a quorum was not met, this time period is reduced to ten days (or four days in the event of shareholders’ meetings convened in the situation where the Company were subject to a tender offer to approve measures, the implementation of which would be likely to cause such tender offer to fail).

Attendance and the exercise of voting rights at both ordinary and extraordinary shareholders’ meetings are subject to certain conditions. Pursuant to French Company Law, participation at shareholders’ meetings is subject to the condition that an entry of registration has been made, for the owner of registered shares, in the records maintained by the Company, or, for the owner of bearer shares, in the records of an authorized intermediary, in each case at 12:00 a.m. (Paris time) on the third trading day preceding the shareholders’ meeting. For the owner of bearer shares, the registration is evidenced by a certificate of participation (attestation de participation) issued by the authorized intermediary.

Subject to the above restrictions, all of the Company’s shareholders have the right to participate in the Company’s shareholders’ meetings, either in person or by proxy. Each shareholder may delegate voting authority to another shareholder, the shareholder’s spouse, or the companion with whom the shareholder has registered a civil partnership (PACS). Every shareholder may also delegate voting authority to any other individual or legal entity he or she may choose, provided, among other things, that a written proxy be provided to the Company. Shareholders may vote, either in person, by proxy, or by postal or electronic mail, and each is entitled to as many votes as he or she possesses or as many shares as he or she holds proxies for, subject to the voting rights limitations provided by the Company’s bylaws. If the shareholder is a legal entity, it may be represented by a legal representative. A shareholder may grant a proxy to the Company by returning a blank proxy form. In this last case, the chairman of the shareholders’ meeting may vote the shares in favor of all resolutions proposed or agreed to by the Board of Directors and against all others. The Company will send proxy forms to shareholders upon request. In order to be counted, proxies must be received at least three days prior to the shareholders’ meeting at the Company’s registered office or at another address indicated in the notice convening the meeting, or by 3:00 p.m. on the day prior to the shareholders’ meeting for electronic proxy forms. Under French Company Law, shares held by the Company or by entities controlled directly or indirectly by the

Company are not entitled to voting rights. There is no requirement that a shareholder have a minimum number of shares in order to be able to attend or be represented at shareholders’ meetings.

Under French Company Law, a quorum requires the presence, in person or by proxy, including those voting by mail, of shareholders having at least 20% of the shares entitled to vote in the case of (i) an ordinary shareholders’ meeting, (ii) an extraordinary meeting where shareholders are voting on a capital increase by capitalization of reserves, profits or share premium, or (iii) an extraordinary general meeting of shareholders convened in the situation where the Company is subject to a tender offer in order to approve an issuance of warrants allowing the subscription, at preferential conditions, of shares of the Company and the free allotment of such warrants to existing shareholders of the Company, the implementation of which would be likely to cause such tender offer to fail, or 25% of the shares entitled to vote in the case of any other extraordinary shareholders’ meeting. If a quorum is not present at any meeting, the meeting is adjourned. There is no quorum requirement when an ordinary shareholders’ meeting is reconvened, but the reconvened meeting may consider only questions that were on the agenda of the adjourned meeting. When an extraordinary shareholders’ meeting is reconvened, the quorum required is 20% of the shares entitled to vote, except where the reconvened meeting is considering capital increases through capitalization of reserves, profits or share premium or an issuance of warrants allowing the subscription, at preferential conditions, of shares of the Company and the free allotment of such warrants to existing shareholders of the Company, the implementation of which would be likely to cause such tender offer to fail. For these matters, no quorum is required at the reconvened meeting. If a quorum is not present at a reconvened meeting requiring a quorum, then the meeting may be adjourned for a maximum of two months.

At an ordinary shareholders’ meeting, approval of any resolution requires the affirmative vote of a simple majority of the votes of the shareholders present or represented by proxy. The approval of any resolution at an extraordinary shareholders’ meeting requires the affirmative vote of a two-thirds majority of the votes cast, except that (i) any resolution to approve a capital increase by capitalization of reserves profits, or share premium, or (ii) any resolution, in the situation where the Company is subject to a tender offer in order to approve an issuance of warrants allowing the subscription, at preferential conditions, of shares of the Company and the free allotment of such warrants to existing shareholders of the Company, the implementation of which would be likely to cause such tender offer to fail,

 

 

140


Table of Contents

only requires the affirmative vote of a simple majority of the votes cast. Notwithstanding these rules, a unanimous vote is required to increase shareholders’ liabilities. Abstention from voting by those present or represented by proxy is counted as a vote against any resolution submitted to a vote.

As set forth in the Company’s bylaws, shareholders’ meetings are held at the Company’s registered office or at any other location specified in the written notice.

Requirements for temporary transfer of securities

French Company Law provides that any legal entity or individual (with the exception of those described in paragraph IV- 3°of Article L. 233-7 of the French Commercial Code) holding alone or in concert a number of

shares representing more than 0.5% of the Company’s voting rights as a result of one or several temporary stock transfers or assimilated transactions within the meaning of Article L. 225-126 of the French Commercial Code is required to inform the Company and the AMF of the number of the shares that are temporarily possessed no later than the third business day preceding the shareholders’ meeting at midnight.

If such declaration is not made, the shares bought under any of the above described temporary stock transfers or assimilated transactions shall be deprived of their voting rights at the relevant shareholders’ meeting and at any shareholders’ meeting that would be held until such shares are transferred again or returned.

Ownership of shares by non-French persons

There is no limitation on the right of non-resident or foreign shareholders to own securities of the Company, either under French Company Law or under the bylaws of the Company.

Requirement for holdings exceeding certain percentages

French Company Law provides that any individual or entity, acting alone or in concert with others, that holds, directly or indirectly, more than 5%, 10%, 15%, 20%, 25%, 30%, 1/3, 50%, 2/3, 90% or 95% of the outstanding shares or of the voting rights(1) attached to the shares, or that increases or decreases its shareholding or voting rights by any of the above percentages must notify the Company by registered letter, with return receipt, within four business days of crossing any of the above-mentioned thresholds, of the number of shares and voting rights it holds. An individual or entity must also notify the AMF, the self-

regulatory organization that has general regulatory authority over the French stock exchanges and whose members include representatives of French stockbrokers, within four trading days of crossing any of the above-mentioned thresholds. In addition, every shareholder who, directly or indirectly, acting alone or in concert with others, acquires ownership or control of shares representing 10%, 15%, 20% or 25% of the Company’s share capital must notify the Company and the AMF of its intentions for the six months following such an acquisition. Any shareholder who fails to comply with the above requirements (thresholds and intentions notifications) will have its voting rights in excess of such thresholds suspended for a period of two years from the date such shareholder complies with the notification requirements and may have all or part of its voting rights suspended for up to five years by the commercial court at the request of the Company’s Chairman, any of the Company’s shareholders or the AMF.

In addition, the Company’s bylaws provide that any person, whether a natural person or a legal entity, who comes to hold, directly or indirectly, 1% or more, or any multiple of 1%, of the Company’s share capital or voting rights or of securities that may give access to the Company’s share capital must notify the Company by registered letter with return receipt requested, within fifteen calendar days of crossing any such threshold. Failure to comply with these notification provisions will result in the suspension of the voting rights attached to the shares exceeding this 1% threshold held by the shareholder if acknowledged at a shareholders’ meeting and if requested at such shareholders’ meeting by one or more shareholders together holding shares representing at least 3% of the share capital or voting rights.

Any individual or legal entity whose direct or indirect holding of shares falls below each of the levels mentioned must also notify the Company in the manner and within the time limits set forth above.

Subject to certain limited exemptions, any person, or persons acting in concert, owning in excess of 1/3 of the share capital or voting rights of the Company must initiate a public tender offer for the balance of the share capital, voting rights and securities giving access to such share capital or voting rights.

Material Contracts

There have been no material contracts (not entered into in the ordinary course of business) entered into by members of the Group since March 23, 2010.

 

 

 

(1)

For purposes of shareholding threshold declarations, pursuant to Article 223-11 of the General Regulation of the AMF, voting rights are calculated on the basis of all outstanding shares, whether or not these shares would have rights to vote at a shareholders’ meeting.

 

141


Table of Contents

Exchange Controls

Under current French exchange control regulations, no limits exist on the amount of payments that TOTAL may remit to residents of the United States. Laws and regulations concerning foreign exchange controls do require, however, that an accredited intermediary must handle all payments or transfer of funds made by a French resident to a non-resident.

Taxation

General

This section generally summarizes the material U.S. federal income tax and French tax consequences of owning and disposing of shares and ADSs of TOTAL to U.S. Holders that hold their shares or ADSs as capital assets for tax purposes. A U.S. Holder is a beneficial owner of shares or ADSs that is (i) a citizen or resident of the United States for U.S. federal income tax purposes, (ii) a domestic corporation or other domestic entity treated as a corporation for U.S. federal income tax purposes, (iii) an estate whose income is subject to U.S. federal income tax regardless of its source, or (iv) a trust if a U.S. court can exercise primary supervision over the trust’s administration and one or more U.S. persons are authorized to control all substantial decisions of the trust.

This section does not apply to members of special classes of holders subject to special rules, including:

 

 

dealers in securities;

 

traders in securities that elect to use a mark-to-market method of accounting for their securities holdings;

 

tax-exempt organizations;

 

life insurance companies;

 

persons liable for alternative minimum tax;

 

persons that actually or constructively own 10% or more of the share capital or voting rights in TOTAL;

 

persons that purchase or sell shares or ADSs as part of a wash sale for U.S. federal income tax purposes;

 

persons that hold the shares or ADSs as part of a straddle or a hedging or conversion transaction; or

 

persons whose functional currency is not the U.S. dollar.

If a partnership holds ordinary shares or ADSs, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. Partners of a partnership holding these ordinary shares or ADSs should consult their tax advisors as to the tax consequences of owning or disposing of ordinary shares or ADSs, as applicable.

In addition, the discussion of the material French tax consequences is limited to U.S. Holders that (i) are residents of the United States for purposes of the Treaty (as defined below), (ii) do not maintain a permanent establishment or fixed base in France to which the shares or ADSs are attributable and through which the respective U.S. Holders carry on, or have carried on, a business (or, if the holder is an individual, performs or has performed independent personal services), and (iii) are otherwise eligible for the benefits of the Treaty in respect of income and gain from the shares or ADSs. In addition, this section is based in part upon the representations of the Depositary and the assumption that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms.

This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations, published rulings and court decisions, and with respect to the description of the material French tax consequences, the laws of the Republic of France and French tax regulations, all as currently in effect, as well as on the Convention Between the United States and the Republic of France for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with respect to Taxes on Income and Capital dated August 31, 1994 as amended (the “Treaty”). These laws, regulations and the Treaty are subject to change, possibly on a retroactive basis.

This discussion is intended only as a descriptive summary and does not purport to be a complete analysis or listing of all potential tax effects of the ownership or disposition of the shares and ADSs and is not intended to substitute competent professional advice. Individual situations of holders of shares and ADSs may vary from the description made below. The following summary does not address the French tax treatment applicable to dividends transferred to so-called “Non Cooperative Countries and Territories” within the meaning of Section 238-0 A of the French Tax Code.

Holders are urged to consult their own tax advisors regarding the U.S. federal, state and local, and French and other tax consequences of owning and disposing shares or ADSs of TOTAL in their respective circumstances. In particular, a holder is encouraged to confirm with its advisor whether the holder is a U.S. Holder eligible for the benefits of the Treaty.

 

 

142


Table of Contents

Taxation of dividends

French taxation

The term “dividends” used in the following discussion means dividends within the meaning of applicable income tax treaties, or, where not defined by such treaties, within the meaning of the French domestic tax law as set forth in administrative guidelines dated February 25, 2005 (4 J-1-05) (the “Administrative Guidelines”).

Dividends paid to non-residents of France are subject to French withholding tax at a rate of 30%. This withholding tax is reduced to 21% with respect to dividends received as from January 1, 2012 by non-residents of France who are residents of certain States located within the European Economic Area.

However, the rate may be reduced pursuant to a tax treaty or similar agreement. Under the Treaty, a U.S. Holder is generally entitled to a reduced rate of French withholding tax of 15% with respect to dividends, provided the ownership of shares or ADSs is not effectively attributable to a permanent establishment or to a fixed base in France and certain other requirements are satisfied.

U.S. Holders should consult their own tax advisors in order to determine the effect of the Treaty and the applicable procedures in respect of the Administrative Guidelines, in light of such particular circumstances.

The Administrative Guidelines set forth the conditions under which the reduced French withholding tax at the rate of 15% may be available. The immediate application of the reduced 15% rate is available to those U.S. Holders that may benefit from the so-called “simplified procedure” (within the meaning of the Administrative Guidelines).

Under the “simplified procedure”, U.S. Holders may claim the immediate application of withholding tax at the rate of 15% on the dividends to be received by them, provided that:

 

(i) they furnish to the U.S. financial institution managing their securities account a certificate of residence conforming with the model attached to the Administrative Guidelines. The immediate application of the 15% withholding tax will be available only if the certificate of residence is sent to the U.S. financial institution managing their securities account before the dividend payment date. Furthermore, each financial institution managing the U.S. Holders’ securities account must also send to the French paying agent the figure of the total amount of dividends to be received which are eligible to the reduced withholding tax rate before the dividend payment date;
(ii) the U.S. financial institution managing the U.S. Holder’s securities account provides to the French paying agent a list of the eligible U.S. Holders and other pieces of information set forth in the Administrative Guidelines. Furthermore, the financial institution managing the U.S. Holders’ securities account should certify that each U.S. Holder is, to the best of its knowledge, a United States resident within the meaning of the Treaty. These documents must be sent as soon as possible, in all cases before the end of the third month computed as from the end of the month of the dividend payment date.

Where the U.S. Holder’s identity and tax residence are known by the French paying agent, the latter may release such U.S. Holder from furnishing to (i) the financial institution managing its securities account, or (ii) as the case may be, the Internal Revenue Service, the abovementioned certificate of residence, and apply the 15% withholding tax rate to dividends it pays to such U.S. Holder.

U.S. Pension Funds and Other Tax-Exempt Entities created and operating in accordance with the provisions of Sections 401(a), 403(b), 457 or 501(c)(3) of the U.S. Internal Revenue Code (IRC) are subject to the same general filing requirements except that, in addition, they have to supply a certificate issued by the U.S. Internal Revenue Service (“IRS”) or any other document stating that they have been created and are operating in accordance with the provisions of the above-mentioned Code Sections. This certificate must be produced together with the first request of application of the reduced rate, once together with the first request of immediate application of the 15% withholding tax and at French Tax Authorities’s specific request.

In the same way, regulated companies such as RIC, REIT or REMIC will have to send to the financial institution managing their securities account a certificate from the IRS indicating that they are classified as Regulated Companies (RIC, REIT or REMIC) within the provisions of the relevant sections of the IRC. In principle, this certification must be produced each year and before the dividend payment.

For a U.S. Holder that is not entitled to the “simplified” procedure and whose identity and tax residence are not known by the paying agent at the time of the payment, the 30% French withholding tax will be levied at the time the dividends are paid. Such U.S. Holder, however, may be entitled to a refund of the withholding tax in excess of the 15% rate under the “standard”, as opposed to the “simplified”, procedure, provided that the U.S. Holder furnishes to the French paying agent an application for refund on forms No. 5000-FR and/or 5001-FR (or any

 

 

143


Table of Contents

other relevant form to be issued by the French tax authorities) certified by the U.S. financial institution managing the U.S. Holder’s securities account (or, if not, by the competent U.S. tax authorities) before December 31 of the second year following the date of payment of the withholding tax at the 30% rate to the French tax authorities, according to the requirements provided by the Administrative Guidelines.

Copies of forms No. 5000-FR and 5001-FR (or any other relevant form to be issued by the French tax authorities) as well as the form of the certificate of residence and the U.S. financial institution certification, together with instructions, are available from the U.S. Internal Revenue Service and the French Centre des Impôts des Non-Residents at 10, rue du Centre, 93463 Noisy le Grand, France.

These forms, together with instructions, will also be provided by the Depositary to all U.S. Holders of ADRs registered with the Depositary. The Depositary will use reasonable efforts to follow the procedures established by the French tax authorities for U.S. Holders to benefit from the immediate application of the 15% French withholding tax rate or, as the case may be, to recover the excess 15% French withholding tax initially withheld and deducted in respect of dividends distributed to them by TOTAL. To effect such benefit or recovery, the Depositary shall advise such U.S. Holder to return the relevant forms to it, properly completed and executed. Upon receipt of the relevant forms properly completed and executed by such U.S. Holder, the Depositary shall cause them to be filed with the appropriate French tax authorities, and upon receipt of any resulting remittance, the Depositary shall distribute to the U.S. Holder entitled thereto, as soon as practicable, the proceeds thereof in U.S. dollars.

The identity and address of the French paying agent are available from TOTAL.

U.S. taxation

For U.S. federal income tax purposes and subject to the passive foreign investment company rules discussed below, the gross amount of any dividend a U.S. Holder must include in gross income equals the amount paid by TOTAL to the extent of the current and accumulated earnings and profits of TOTAL (as determined for U.S. federal income tax purposes). The dividend will be income from foreign sources. Dividends paid to a non-corporate U.S. Holder in taxable years beginning before January 1, 2013, that constitute qualified dividend income will be taxable to the holder at a maximum tax rate

of 15%, provided that the shares or ADSs are held for more than sixty days during the 121-day period beginning sixty days before the ex-dividend date and the holder meets other holding period requirements. TOTAL believes that dividends paid by TOTAL with respect to its shares or ADSs will be qualified dividend income. The dividend will not be eligible for the dividends-received deduction allowed to a U.S. corporation under Section 243 of the Code. The dividend is taxable to the U.S. Holder when the holder, in the case of shares, or the Depositary, in the case of ADSs, receives the dividend, actually or constructively. To the extent that an amount received by a U.S. Holder exceeds the allocable share of TOTAL’s current and accumulated earnings and profits, it will be applied first to reduce such holder’s tax basis in shares or ADSs owned by such holder and then, to the extent it exceeds the holder’s tax basis, it will constitute capital gain.

The amount of any dividend distribution includible in the income of a U.S. Holder equals the U.S. dollar value of the euro payment made, determined at the spot euro/dollar exchange rate on the date the dividend distribution is includible in the U.S. Holder’s income, regardless of whether the payment is in fact converted into U.S. dollars. Any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend payment is includible in the U.S. Holder’s income to the date the payment is converted into U.S. dollars will generally be treated as ordinary income or loss from sources within the United States and will not be eligible for the special tax rate applicable to qualified dividend income.

Subject to certain conditions and limitations, French taxes withheld in accordance with the Treaty will generally be eligible for credit against the U.S. Holder’s U.S. federal income tax liability. The limitation on foreign taxes eligible for credit is calculated separately with respect to specific classes of income. In addition, special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the maximum 15% tax rate. To the extent a refund of the tax withheld is available to a U.S. Holder under French law or under the Treaty, the amount of tax withheld that is refundable will not be eligible for credit against such an individual’s United States federal income tax liability.

For this purpose, dividends distributed by TOTAL will constitute “passive income”, or, in the case of certain U.S. Holders, “general income”, which are treated separately from one another for purposes of computing the foreign tax credit allowable to the U.S. Holder. Alternatively, a U.S. Holder may claim all foreign taxes paid as an itemized deduction in lieu of claiming a foreign tax credit.

 

 

144


Table of Contents

Taxation of disposition of shares

In general, a U.S. Holder who is eligible for the benefits of the Treaty will not be subject to French tax on any capital gain from the sale or exchange of the ADSs or redemption of the underlying shares unless those ADSs or shares form part of a business property of a permanent establishment or fixed base that the U.S. Holder has in France. Special rules may apply to individuals who are residents of more than one country.

A transfer tax assessed on the higher of the purchase price and the fair market value of the shares applies to certain transfers of shares in French companies. Such transfer tax is equal to:

 

 

3% for the portion of the purchase price (or the fair market value, if higher) below 200,000;

 

0.5% for the portion of the purchase price (or the fair market value, if higher) between 200,000 and 500 million;

 

0.25% for the portion of the purchase price (or the fair market value, if higher) above 500 million.

The transfer tax does not apply to transfers of shares in TOTAL, provided that the transfer is not evidenced by a written agreement.

Recently enacted legislation applicable as from August 1, 2012, has introduced, under certain conditions, a financial transaction tax on the acquisition of shares of publicly traded companies registered in France having a market capitalization over 1 billion. A list of the companies within the scope of the financial transaction tax will be published in a forthcoming decree. We expect that TOTAL will be included in this list. The financial transaction tax will be due at a rate of 0.1% on the value of the acquired shares. Transactions that are subject to the financial transaction tax are exempt from the above-mentioned transfer tax (which was also modified by the same legislation). U.S. Holders should consult their tax advisors as to the tax consequences of such reforms.

For U.S. federal income tax purposes and subject to the passive foreign investment company rules discussed below, a U.S. Holder generally will recognize capital gain or loss upon the sale or disposition of shares or ADSs equal to the difference between the U.S. dollar value of the amount realized on the sale or disposition and the holder’s tax basis, determined in U.S. dollars, in the shares or ADSs. The gain or loss generally will be U.S. source gain or loss and will be long-term capital gain or loss if the U.S. Holder’s holding period of the shares or ADSs is more than one year at the time of the disposition. Long-term capital gain of a non-corporate U.S. Holder is generally

taxed at preferential rates. The deductibility of capital losses is subject to limitation.

Passive foreign investment status

TOTAL believes that the shares or ADSs will not be treated as stock of a passive foreign investment company, or PFIC, for United States federal income tax purposes, but this conclusion is a factual determination that is made annually and thus is subject to change. If TOTAL is treated as a PFIC, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the shares or ADSs, gain realized on the sale or other disposition of the shares or ADSs would in general not be treated as capital gain. Instead, a U.S. Holder would be treated as if he or she had realized such gain and certain “excess distributions” ratably over the holding period for the shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, in addition to which an interest charge in respect of the tax attributable to each such year would apply. With certain exceptions, a U.S. Holder’s shares or ADSs will be treated as stock in a PFIC if TOTAL were a PFIC at any time during his or her holding period in the shares or ADSs. Dividends paid will not be eligible for the special tax rates applicable to qualified dividend income if TOTAL is treated as a PFIC with respect to a U.S. Holder either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.

French estate and gift taxes

In general, a transfer of ADSs or shares by gift or by reason of the death of a U.S. Holder that would otherwise be subject to French gift or inheritance tax, respectively, will not be subject to such French tax by reason of the Convention between the United States of America and the French Republic for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Estates, Inheritances and Gifts, dated November 24, 1978 as amended, unless the donor or the transferor is domiciled in France at the time of making the gift, or at the time of his death, or if the ADSs or shares were used in, or held for use in, the conduct of a business through a permanent establishment or a fixed base in France.

French wealth tax

The French wealth tax does not apply to a U.S. Holder (i) that is not an individual, or (ii) in the case of individuals who are eligible for the benefits of the Treaty and who own, alone or with related persons, directly or indirectly, TOTAL shares which give right to less than 25% of TOTAL’s earnings.

 

 

145


Table of Contents

U.S. state and local taxes

In addition to U.S. federal income tax, U.S. Holders of shares or ADSs may be subject to U.S. state and local taxes with respect to their shares or ADSs. U.S. Holders should consult their own tax advisors.

Dividends and Paying Agents

After BNP Paribas Securities Services performs centralizing procedures, dividends are paid through the accounts of financial intermediaries participating in Euroclear France’s direct payment procedures. The Bank of New York Mellon acts as paying agent for dividends distributed to ADS holders.

Documents on Display

TOTAL files annual, periodic, and other reports and information with the Securities and Exchange Commission. You may inspect any reports, statements or other information TOTAL files with the United States Securities and Exchange Commission (“SEC”) at the SEC’s public reference rooms by calling the SEC for more information at 1-800-SEC-0330. All of TOTAL’s SEC filings made after December 31, 2001, are available to the public at the SEC Web site at http://www.sec.gov and from certain commercial document retrieval services. You may also inspect any document the Company files with the SEC at the offices of The New York Stock Exchange, 20 Broad Street, New York, New York 10005.

 

 

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Please refer to Note 31 to the Consolidated Financial Statements included elsewhere herein for a qualitative and quantitative discussion of the Group’s exposure to market risks. Please also refer to Notes 29 and 30 to the Consolidated Financial Statements included elsewhere herein for details of the different derivatives owned by the Group in these markets.

As part of its financing and cash management activities, the Group uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Group may also use, on a less frequent basis, futures and options contracts. These operations and their accounting treatment are detailed in Note 1 paragraph M and Notes 20, 28 and 29 to the

Consolidated Financial Statements included elsewhere herein.

The financial performance of TOTAL is sensitive to a number of factors, the most significant being oil and gas prices, generally expressed in dollars, and exchange rates, in particular that of the dollar versus the euro. Generally, a rise in the price of crude oil has a positive effect on earnings as a result of an increase in revenues from oil and gas production. Conversely, a decline in crude oil prices reduces revenues. The impact of changes in crude oil prices on Downstream and Chemicals operations depends upon the speed at which the prices of finished products adjust to reflect these changes. All of the Group’s activities are, to various degrees, sensitive to fluctuations in the dollar/euro exchange rate.

 

 

146


Table of Contents

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

American Depositary Receipts fees and charges

The Bank of New York Mellon, as a depositary, collects its fees for delivery and surrender of ADRs directly from investors depositing shares or surrendering ADRs for the purpose of withdrawal or from intermediaries acting for them. The depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The depositary may generally refuse to provide fee-attracting services until its fees for those services are paid.

 

Investors must pay:    For:
$5.00 (or less) per 100 ADSs (or portion of 100 ADSs)   

•     Issuance of ADRs, including issuances resulting from a distribution of shares or rights or other property, stocks splits or merger

•     Cancellation of ADRs for the purpose of withdrawal, including if the deposit agreement terminates

A fee equivalent to the fee that would be payable if securities distributed to the investor had been shares and the shares had been deposited for issuance of ADSs   

•     Distribution of securities distributed to holders of deposited securities that are distributed by the depositary to ADS registered holders

Registration or transfer fees   

•     Transfer and registration of shares on the Company’s share register to or from the name of the depositary or its agent when the investor deposits or withdraws shares

Expenses of the depositary   

•     Cable, telex and facsimile transmissions (when expressly provided in the deposit agreement)

•     Converting foreign currency to U.S. dollars

Taxes and other governmental charges the depositary or the custodian have to pay on any ADS or share underlying an ADS, for example, stock transfer taxes, stamp duty or withholding taxes   

•     As necessary

Any charges incurred by the depositary or its agents for servicing the deposited securities

  

•     As necessary

 

The depositary has agreed to reimburse expenses (“Reimbursed Expenses”) incurred by the Company for the establishment and maintenance of the ADS program that include, but are not limited to, exchange listing fees, annual meeting expenses, standard out-of-pocket maintenance costs for the ADRs (e.g., the expenses of postage and envelopes for mailing annual and interim financial reports, printing and distributing dividend checks, electronic filing of U.S. Federal tax information, mailing required tax forms, stationery, postage, facsimile, and telephone calls), shareholder identification, investor relations activities or programs in North America, accounting fees (such as external audit fees incurred in connection with the Sarbanes-Oxley Act, the preparation of the Company’s Form 20-F and paid to the FASB and the PCAOB), legal

fees and other expenses incurred in connection with the preparation of regulatory filings and other documentation related to ongoing SEC, NYSE and U.S. securities law compliance. In certain instances, the depositary has agreed to provide additional payments to the Company based on certain applicable performance indicators relating to the ADR facility. There are limits on the amount of expenses for which the depositary will reimburse the Company, but the amount of reimbursement available to the Company is not necessarily tied to the amount of fees the depositary collects from investors.

From March 16, 2011 to March 15, 2012, the Company received from the depositary a payment of $3,327,796.00 with respect to certain Reimbursed Expenses.

 

 

147


Table of Contents

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF

SECURITY HOLDERS AND USE OF PROCEEDS

None.

ITEM 15. CONTROLS AND PROCEDURES

 

Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of the Group’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness, as of the end of the period covered by this report, of the design and operation of the Group’s disclosure controls and procedures, which are defined as those controls and procedures designed to ensure that information required to be disclosed in reports filed under the U.S. Securities Exchange Act of 1934, as amended, is recorded, summarized and reported within specified time periods. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that the Company files under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

The Group’s management is responsible for establishing and maintaining adequate internal control over financial

reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time.

The Group’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of internal control over financial reporting using the criteria set forth in the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2011.

The effectiveness of internal control over financial reporting as of December 31, 2011, was audited by KPMG S.A. and Ernst & Young Audit, independent registered public accounting firms, as stated in their report on page F-2 of this Annual Report.

Changes in Internal Control Over Financial Reporting

There were no changes in the Group’s internal control over financial reporting that occurred during the period covered by this report that have materially affected, or that were reasonably likely to materially affect, the Group’s internal control over financial reporting.

 

 

148


Table of Contents

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

 

Ms. Patricia Barbizet is the Audit Committee financial expert. Ms. Barbizet is an independent member of the Board of Directors in accordance with the NYSE listing

standards applicable to TOTAL, as are the other members of the Audit Committee.

 

 

ITEM 16B. CODE OF ETHICS

 

At its meeting on February 18, 2004, the Board of Directors adopted a code of ethics that applies to its Chief Executive Officer, Chief Financial Officer, Chief Accounting

Officer and the financial and accounting officers for its principal activities. A copy of this code of ethics is included as an exhibit to this Annual Report.

 

 

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

During the fiscal years ended December 31, 2011 and 2010, fees for services provided by Ernst & Young Audit and KPMG were as follows:

 

     

KPMG

Year Ended December 31,

    

Ernst & Young Audit

Year Ended December 31,

 
(M)    2011      2010      2011      2010  

Audit Fees

     14.1         15.1         15.6         15.2   

Audit-Related Fees(a)

     3.8         3.6         1.9         0.7   

Tax Fees(b)

     1.6         1.2         1.4         1.7   

All Other Fees(c)

     0.2         0.1         0.2         0.2   

Total

     19.7         20.0         19.1         17.8   

 

(a) Audit-related fees are generally fees billed for services that are closely related to the performance of the audit or review of financial statements. These include due diligence services related to business combinations, attestation services not required by statute or regulation, agreed upon or expanded auditing procedures related to accounting or billing records required to respond to or comply with financial, accounting or regulatory reporting matters, consultations concerning financial accounting and reporting standards, information system reviews, internal control reviews and assistance with internal control reporting requirements.
(b) Tax fees are fees for services related to international and domestic tax compliance, including the preparation of tax returns and claims for refund, tax planning and tax advice, including assistance with tax audits and tax appeals, and tax services regarding statutory, regulatory or administrative developments and expatriate tax assistance and compliance.
(c) All other fees are principally for risk management advisory services.

 

Audit Committee Pre-Approval Policy

The Audit Committee has adopted an Audit and Non-Audit Services Pre-Approval Policy that sets forth the procedures and the conditions pursuant to which services proposed to be performed by the statutory auditors may be pre-approved and that are not prohibited by regulatory or other professional requirements. This policy provides for both pre-approval of certain types of services through the use of an annual budget approved by the Audit Committee

for these types of services and special pre-approval of services by the Audit Committee on a case-by-case basis. The Audit Committee reviews on an annual basis the services provided by the statutory auditors. During 2011, no audit-related fees, tax fees or other non-audit fees were approved by the Audit Committee pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

 

 

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

None.

 

149


Table of Contents

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

 

Period   

Total Number Of

Shares

Purchased

    

Average Price

Paid Per

Share ()

    

Total Number Of

Shares Purchased,

As Part Of Publicly

Announced

Plans Or

Programs(a)

    

Maximum Number

Of Shares  That May

Yet Be Purchased

Under The Plans Or

Programs(b)

 

January 2011

                             122,526,633   

February 2011

                             122,588,776   

March 2011

                             122,626,999   

April 2011

                             123,539,732   

May 2011

                             123,567,601   

June 2011

                             123,655,175   

July 2011

                             123,891,589   

August 2011

                             123,892,274   

September 2011

                             126,818,649   

October 2011

                             126,819,834   

November 2011

                             126,822,199   

December 2011

                             126,822,558   

January 2012

                             126,824,217   

February 2012

                             126,836,267   

 

(a) The shareholders’ meeting of May 13, 2011, cancelled and replaced the previous resolution from the shareholders’ meeting of May 21, 2010, authorizing the Board of Directors to trade in the Company’s own shares on the market for a period of 18 months within the framework of the stock purchase program. The maximum number of shares that may be purchased by virtue of this authorization or under the previous authorization may not exceed 10% of the total number of shares constituting the share capital, this amount being periodically adjusted to take into account operations modifying the share capital after each shareholders’ meeting. Under no circumstances may the total number of shares the Company holds, either directly or indirectly through its subsidiaries, exceed 10% of the share capital.
(b) Based on 10% of the Company’s share capital, and after deducting the shares held by the Company for cancellation and the shares held by the Company to cover the share purchase option plans for Company employees and restricted share grants for Company employees, as well as after deducting the shares held by the subsidiaries.

ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

 

Summary of Significant Differences between French Corporate Governance Practices and the NYSE’s Corporate Governance Standards

Overview

The following paragraphs provide a brief, general summary of significant differences between the corporate governance standards followed by TOTAL under French law and guidelines, and those required by the listing standards of the New York Stock Exchange (the “NYSE”) for U.S. companies that have common stock listed on the NYSE.

The principal sources of corporate governance standards in France are the French Commercial Code (Code de Commerce), the French Financial and Monetary Code (Code monétaire et financier), as amended from time to time, and the regulations and recommendations provided by the French Financial Markets Authority (Autorité des marchés financiers, AMF), as well as a number of general

recommendations and guidelines on corporate governance, most notably the Corporate Governance Code for Listed Companies published in December 2008 (as amended in April 2010) by the principal French business confederations, the Association Française des Entreprises Privées (AFEP) and the Mouvement des Entreprises de France (MEDEF) (the “AFEP-MEDEF Code”). The AFEP-MEDEF Code includes, among other things, recommendations relating to the role and operation of the board of directors (creation, composition and evaluation of the board of directors and the audit, compensation and nominating committees) and the independence criteria for board members. Articles L. 820-1 et seq. of the French Commercial Code prohibits statutory auditors from providing certain non-audit services and defines certain criteria for the independence of statutory auditors. In France, the independence of statutory auditors is also monitored by an independent body, the High Council for Statutory Auditors (Haut Conseil du commissariat aux comptes).

 

 

150


Table of Contents

Composition of Board of Directors; Independence

The NYSE listing standards provide that the board of directors of a U.S. listed company must consist of a majority of independent directors and that certain committees must consist solely of independent directors. A director qualifies as independent only if the board affirmatively determines that the director has no material relationship with the company, either directly or indirectly. In addition, the listing standards enumerate a number of relationships that preclude independence.

French law does not contain any independence requirement for the members of the board of directors of a French company, unless the board establishes an audit committee, as described below. Under French law, the functions of board chairman and chief executive officer may be performed by the same person. The AFEP- MEDEF Code recommends, however, that (i) at least half of the members of the board of directors be independent in companies that have a dispersed ownership structure and no controlling shareholder, and (ii) at least a third of the members of the board of directors be independent in companies that have a controlling shareholder. The AFEP-MEDEF Code states that a director is independent when “he or she has no relationship of any nature with the company, its group or the management of either, that may compromise the exercise of his or her freedom of judgment.” The AFEP-MEDEF Code also enumerates specific criteria for determining independence, which are on the whole consistent with the goals of the NYSE’s rules although the specific tests under the two standards may vary on some points.

Based on the proposal of TOTAL’s Nominating & Corporate Governance Committee, the Board of Directors of TOTAL at its meeting on February 9, 2012, examined the independence of the Company’s directors as of December 31, 2011, and considered that all of the directors of the Company are independent, with the exceptions of Mr. de Margerie, Chairman and Chief Executive Officer of the Company since May 21, 2010, Mr. Desmarest, Chairman of the Board of Directors until May 21, 2010, and Mr. Clément, director representing employee shareholders.

Representation of women on corporate boards

The French Journal Officiel published law No. 2011-103 dated January 27, 2011, relating to the representation of women on the boards of certain French companies, including French companies listed on Euronext Paris.

New rules provide for legally binding quotas to boost the percentage of women on boards of directors of French listed

companies, requiring that women represent: (i) at least 20% within two years (following the first ordinary shareholders’ meeting held after January 1, 2014), and (ii) at least 40% within five years (following the first ordinary shareholders’ meeting held after January 1, 2017). When the board of directors consists of less than nine members, the difference between the number of directors of each gender at the end of the five-year period should not be higher than two. Any appointment of a director made in violation of these rules shall be declared null and void and the payment of the directors’ compensation shall be suspended until the board composition complies with the law’s requirements (the management report shall also indicate the suspension of the directors’ compensation until the board composition complies with the law’s requirements). However, decisions of a board of directors that fails to comply with these quotas may not be declared null and void.

Board committees

Overview. The NYSE listing standards require that a U.S. listed company have an audit committee, a nominating/corporate governance committee and a compensation committee. Each of these committees must consist solely of independent directors and must have a written charter that addresses certain matters specified in the listing standards.

With the exception of an audit committee, as described below, French law requires neither the establishment of board committees nor the adoption of written charters.

The AFEP-MEDEF Code recommends, however, that the board of directors sets up, in addition to an audit committee, a nominating committee and a compensation committee, indicating that the nominating and compensation committees may form only one committee. The AFEP-MEDEF Code also recommends that at least two-thirds of the audit committee members and a majority of the members of each of the compensation committee and the nominating committee be independent directors.

TOTAL has established an Audit Committee, a Nominating & Corporate Governance Committee and a Compensation Committee, and considers all of the members of these committees to be independent with the exception of Mr. Desmarest, who is a member of the Compensation Committee and chairs the Nominating & Corporate Governance Committee. For the membership of each committee, see “Item 6. Corporate Governance”. Each of these committees has a charter that defines the scope of its activity.

Audit committee. The NYSE listing standards contain detailed requirements for the audit committees of U.S. listed companies. Some, but not all, of these

 

 

151


Table of Contents

requirements also apply to non-U.S. listed companies, such as TOTAL.

French law requires the board of directors of companies listed in France to establish an audit committee (Article L. 823-19 of the French Commercial Code), at least one member of which must be an independent director and must be competent in finance or accounting.

Pursuant to French law and the AFEP-MEDEF Code, the audit committee is responsible for, among other things, reviewing the financial statements and ensuring the relevance and consistency of accounting methods used in drawing up the consolidated and corporate accounts, examining the company’s risk exposure and material off-balance sheet commitments and the scope of consolidation, monitoring the process for the preparation of financial information, monitoring the efficiency of internal control procedures and risk management systems, managing the process of selecting statutory auditors, expressing an opinion on the amount of their fees and monitoring compliance with rules designed to ensure auditor independence, regularly interviewing statutory auditors without the executive management being present and calling upon outside experts if necessary.

Although the audit committee requirements under French law and recommendations under the AFEP-MEDEF Code are less detailed than those contained in the NYSE listing standards, the NYSE listing standards, French law and the AFEP-MEDEF Code share the goal of establishing a system for overseeing the company’s accounting that is independent from management and that ensures auditor independence. As a result, they address similar topics, and there is some overlap.

For the specific tasks performed by the Audit Committee of TOTAL that exceed those required by French law and those recommended by the AFEP-MEDEF Code, see “Item 6. Corporate Governance — Audit Committee”.

One structural difference between the legal status of the audit committee of a U.S. listed company and that of a French listed company concerns the degree of the committee’s involvement in managing the relationship between the company and the auditor. French law requires French companies that publish consolidated financial statements, such as TOTAL, to have two co-auditors. While the NYSE listing standards require that the audit committee of a U.S. listed company have direct responsibility for the appointment, compensation, retention, and oversight of the work of the auditor, French law provides that the election of the co-auditors is the sole responsibility of the shareholders’ meeting. In making its decision, the shareholders’ meeting may rely on proposals submitted to it by the board of

directors, the decision of the latter being taken upon consultation with the audit committee. The shareholders’ meeting elects the auditors for an audit period of six fiscal years. The auditors may only be dismissed by a court and only on grounds of professional negligence or incapacity to perform their mission.

Disclosure

The NYSE listing standards require U.S. listed companies to adopt, and post on their websites, a set of corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession, and an annual performance evaluation of the board. In addition, the chief executive officer of a U.S. listed company must certify to the NYSE annually that he or she is not aware of any violations by the company of the NYSE’s corporate governance listing standards.

French law requires neither the adoption of such guidelines nor the provision of such certification. The AFEP-MEDEF Code recommends, however, that the board of directors of a French listed company perform an annual review of its operation and that a formal evaluation, possibly with the assistance of an outside consultant, be undertaken every three years, which for TOTAL took place in early 2012 without the assistance of an outside consultant, and that shareholders be informed each year in the annual report of the evaluations. In addition, the AFEP-MEDEF Code addresses deontology rules that the directors are expected to comply with.

Code of business conduct and ethics

The NYSE listing standards require each U.S. listed company to adopt, and post on its website, a code of business conduct and ethics for its directors, officers and employees. There is no similar requirement or recommendation under French law. However, under the SEC’s rules and regulations, all companies required to submit periodic reports to the SEC, including TOTAL, must disclose in their annual reports whether they have adopted a code of ethics for their principal executive officer and senior financial officers. In addition, they must file a copy of the code with the SEC, post the text of the code on their website or undertake to provide a copy upon request to any person without charge. There is significant, though not complete, overlap between the code of ethics required by the NYSE listing standards and the code of ethics for senior financial officers required by the SEC’s rules. For a discussion of the code of ethics adopted by TOTAL, see “Item 6. Corporate Governance” and “Item 16B. Code of Ethics”.

 

 

152


Table of Contents

ITEM 17. FINANCIAL STATEMENTS

Not applicable.

ITEM 18. FINANCIAL STATEMENTS

The following financial statements, together with the report of Ernst & Young Audit and KPMG S.A. thereon, are held as part of this annual report.

 

     Page  

Report of Independent Registered Public Accounting Firms on the Consolidated Financial Statements

     F-1   

Report of Independent Registered Public Accounting Firms on the Internal Control over Financial Reporting

     F-2   

Consolidated Statement of Income for the Years Ended December 31, 2011, 2010 and 2009

     F-3   

Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009

     F-4   

Consolidated Balance Sheet at December 31, 2011, 2010 and 2009

     F-5   

Consolidated Statement of Cash Flow for the Years Ended December 31, 2011, 2010 and 2009

     F-6   

Consolidated Statement of Changes in Shareholders’ Equity for the Years Ended December  31, 2011, 2010 and 2009

     F-7   

Notes to the Consolidated Financial Statements

     F-8   

Supplemental Oil and Gas Information (Unaudited)

     S-1   

Schedules have been omitted since they are not required under the applicable instructions or the substance of the required information is shown in the financial statements.

ITEM 19. EXHIBITS

The following documents are filed as part of this annual report:

 

1

   Bylaws (Statuts) of TOTAL S.A. (as amended through December 31, 2011)

8

   List of Subsidiaries (see Note 35 to the Consolidated Financial Statements included in this Annual Report)

11

   Code of Ethics (incorporated by reference to the Company’s Annual Report on Form 20-F for the year ended December 31, 2005)

12.1

   Certification of Chairman and Chief Executive Officer

12.2

   Certification of Chief Financial Officer

13.1

   Certification of Chairman and Chief Executive Officer

13.2

   Certification of Chief Financial Officer

15

   Consent of ERNST & YOUNG AUDIT and of KPMG S.A.

SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

 

TOTAL S.A.

By:

 

/s/ CHRISTOPHE DE MARGERIE

  Name: Christophe de Margerie
  Title: Chairman and Chief Executive Officer

Date: March 26, 2012

 

153


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

ON THE CONSOLIDATED FINANCIAL STATEMENTS

Year ended December 31, 2011

The Board of Directors and Shareholders

We have audited the accompanying consolidated balance sheets of TOTAL S.A. and subsidiaries (the “Company”) as of December 31, 2011, 2010 and 2009, and the related consolidated statements of income, comprehensive income, cash flows and changes in shareholders’ equity for each of the three years in the period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2011, 2010 and 2009, and the consolidated results of its operations and its consolidated cash flows for each of the three years in the period ended December 31, 2011, in conformity with International Financial Reporting Standards as adopted by the European Union and in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria) and our report dated March 7, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Paris La Défense, March 7, 2012

 

KPMG Audit

A division of KPMG S.A.

   ERNST & YOUNG Audit

/s/    JAY NIRSIMLOO

  

/s/    PASCAL MACIOCE

  

/s/    LAURENT VITSE

Jay Nirsimloo    Pascal Macioce    Laurent Vitse
Partner    Partner    Partner

 

F-1


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

ON THE INTERNAL CONTROL OVER FINANCIAL REPORTING

Year ended December 31, 2011

The Board of Directors and Shareholders

We have audited TOTAL S.A. and subsidiaries’ (“the Company”) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management’s annual report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2011, 2010 and 2009 and the related consolidated statements of income, comprehensive income, cash flows and changes in shareholders’ equity for each of the three years in the period ended December 31, 2011, and our report dated March 7, 2012 expressed an unqualified opinion on those consolidated financial statements.

Paris La Défense, March 7, 2012

 

KPMG Audit

A division of KPMG S.A.

   ERNST & YOUNG Audit

/s/    JAY NIRSIMLOO

  

/s/    PASCAL MACIOCE

  

/s/    LAURENT VITSE

Jay Nirsimloo    Pascal Macioce    Laurent Vitse
Partner    Partner    Partner

 

F-2


Table of Contents

CONSOLIDATED STATEMENT OF INCOME

 

TOTAL

 

For the year ended December 31, (M)(a)           2011     2010     2009  

Sales

     (Notes 4 & 5     184,693        159,269        131,327   

Excise taxes

       (18,143     (18,793     (19,174

Revenues from sales

       166,550        140,476        112,153   

Purchases net of inventory variation

     (Note 6     (113,892     (93,171     (71,058

Other operating expenses

     (Note 6     (19,843     (19,135     (18,591

Exploration costs

     (Note 6     (1,019     (864     (698

Depreciation, depletion and amortization of tangible assets and mineral interests

       (7,506     (8,421     (6,682

Other income

     (Note 7     1,946        1,396        314   

Other expense

     (Note 7     (1,247     (900     (600

Financial interest on debt

       (713     (465     (530

Financial income from marketable securities & cash equivalents

       273        131        132   

Cost of net debt

     (Note 29     (440     (334     (398

Other financial income

     (Note 8     609        442        643   

Other financial expense

     (Note 8     (429     (407     (345

Equity in income (loss) of affiliates

     (Note 12     1,925        1,953        1,642   

Income taxes

     (Note 9     (14,073     (10,228     (7,751

Consolidated net income

             12,581        10,807        8,629   

Group share

       12,276        10,571        8,447   

Non-controlling interests

             305        236        182   

Earnings per share ()

       5.46        4.73        3.79   

Fully-diluted earnings per share ()

             5.44        4.71        3.78   

 

(a)

Except for per share amounts.

 

F-3


Table of Contents

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

 

TOTAL

 

For the year ended December 31, (M)    2011     2010     2009  

Consolidated net income

     12,581        10,807        8,629   

Other comprehensive income

      

Currency translation adjustment

     1,498        2,231        (244

Available for sale financial assets

     337        (100     38   

Cash flow hedge

     (84     (80     128   

Share of other comprehensive income of associates, net amount

     (15     302        234   

Other

     (2     (7     (5

Tax effect

     (55     28        (38

Total other comprehensive income (net amount) (note 17)

     1,679        2,374        113   

Comprehensive income

     14,260        13,181        8,742   

— Group share

     13,911        12,936        8,500   

— Non-controlling interests

     349        245        242   

 

F-4


Table of Contents

CONSOLIDATED BALANCE SHEET

 

TOTAL

 

As of December 31, (M)           2011     2010     2009  

ASSETS

        

Non-current assets

        

Intangible assets, net

     (Notes 5 & 10     12,413        8,917        7,514   

Property, plant and equipment, net

     (Notes 5 & 11     64,457        54,964        51,590   

Equity affiliates: investments and loans

     (Note 12     12,995        11,516        13,624   

Other investments

     (Note 13     3,674        4,590        1,162   

Hedging instruments of non-current financial debt

     (Note 20     1,976        1,870        1,025   

Other non-current assets

     (Note 14     4,871        3,655        3,081   

Total non-current assets

       100,386        85,512        77,996   

Current assets

        

Inventories, net

     (Note 15     18,122        15,600        13,867   

Accounts receivable, net

     (Note 16     20,049        18,159        15,719   

Other current assets

     (Note 16     10,767        7,483        8,198   

Current financial assets

     (Note 20     700        1,205        311   

Cash and cash equivalents

     (Note 27     14,025        14,489        11,662   

Total current assets

             63,663        56,936        49,757   

Assets classified as held for sale

     (Note 34            1,270          

Total assets

             164,049        143,718        127,753   

LIABILITIES & SHAREHOLDERS’ EQUITY

        

Shareholders’ equity

        

Common shares

       5,909        5,874        5,871   

Paid-in surplus and retained earnings

       66,506        60,538        55,372   

Currency translation adjustment

       (988     (2,495     (5,069

Treasury shares

             (3,390     (3,503     (3,622

Total shareholders’ equity — Group share

     (Note 17     68,037        60,414        52,552   

Non-controlling interests

             1,352        857        987   

Total shareholders’ equity

       69,389        61,271        53,539   

Non-current liabilities

        

Deferred income taxes

     (Note 9     12,260        9,947        8,948   

Employee benefits

     (Note 18     2,232        2,171        2,040   

Provisions and other non-current liabilities

     (Note 19     10,909        9,098        9,381   

Non-current financial debt

     (Note 20     22,557        20,783        19,437   

Total non-current liabilities

             47,958        41,999        39,806   

Current liabilities

        

Accounts payable

       22,086        18,450        15,383   

Other creditors and accrued liabilities

     (Note 21     14,774        11,989        11,908   

Current borrowings

     (Note 20     9,675        9,653        6,994   

Other current financial liabilities

     (Note 20     167        159        123   

Total current liabilities

             46,702        40,251        34,408   

Liabilities directly associated with the assets classified as held for sale

     (Note 34            197          

Total liabilities and shareholders’ equity

             164,049        143,718        127,753   

 

F-5


Table of Contents

CONSOLIDATED STATEMENT OF CASH FLOW

 

TOTAL

(Note 27)

 

For the year ended December 31, (M)    2011     2010     2009  

CASH FLOW FROM OPERATING ACTIVITIES

      

Consolidated net income

     12,581        10,807        8,629   

Depreciation, depletion and amortization

     8,628        9,117        7,107   

Non-current liabilities, valuation allowances, and deferred taxes

     1,665        527        441   

Impact of coverage of pension benefit plans

            (60       

(Gains) losses on disposals of assets

     (1,590     (1,046     (200

Undistributed affiliates’ equity earnings

     (107     (470     (378

(Increase) decrease in working capital

     (1,739     (496     (3,316

Other changes, net

     98        114        77   

Cash flow from operating activities

     19,536        18,493        12,360   

CASH FLOW USED IN INVESTING ACTIVITIES

      

Intangible assets and property, plant and equipment additions

     (17,950     (13,812     (11,849

Acquisitions of subsidiaries, net of cash acquired

     (854     (862     (160

Investments in equity affiliates and other securities

     (4,525     (654     (400

Increase in non-current loans

     (1,212     (945     (940

Total expenditures

     (24,541     (16,273     (13,349

Proceeds from disposals of intangible assets and property, plant and equipment

     1,439        1,534        138   

Proceeds from disposals of subsidiaries, net of cash sold

     575        310          

Proceeds from disposals of non-current investments

     5,691        1,608        2,525   

Repayment of non-current loans

     873        864        418   

Total divestments

     8,578        4,316        3,081   

Cash flow used in investing activities

     (15,963     (11,957     (10,268

CASH FLOW USED IN FINANCING ACTIVITIES

      

Issuance (repayment) of shares:

      

— Parent company shareholders

     481        41        41   

— Treasury shares

            49        22   

Dividends paid:

      

— Parent company shareholders

     (5,140     (5,098     (5,086

— Non-controlling interests

     (172     (152     (189

Other transactions with non-controlling interests

     (573     (429       

Net issuance (repayment) of non-current debt

     4,069        3,789        5,522   

Increase (decrease) in current borrowings

     (3,870     (731     (3,124

Increase (decrease) in current financial assets and liabilities

     896        (817     (54

Cash flow used in financing activities

     (4,309     (3,348     (2,868

Net increase (decrease) in cash and cash equivalents

     (736     3,188        (776

Effect of exchange rates

     272        (361     117   

Cash and cash equivalents at the beginning of the period

     14,489        11,662        12,321   

Cash and cash equivalents at the end of the period

     14,025        14,489        11,662   

 

F-6


Table of Contents

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

 

TOTAL

 

     Common shares
issued
    Paid-in surplus
and retained
earnings
    Currency
translation
adjustment
    Treasury shares     Shareholders’
equity - Group
share
   

Non-controlling
interests

    Total
shareholders’
equity
 
(M)   Number     Amount         Number     Amount        

As of Janurary 1, 2009

    2,371,808,074        5,930        52,947        (4,876     (143,082,095     (5,009     48,992        958        49,950   

Net income 2009

                  8,447                             8,447        182        8,629   

Other comprehensive income (Note 17)

                  246        (193                   53        60        113   

Comprehensive income

                  8,693        (193                   8,500        242        8,742   

Dividend

                  (5,086                          (5,086     (189     (5,275

Issuance of common shares (Note 17)

    1,414,810        3        38                             41               41   

Purchase of treasury shares

                                                              

Sale of treasury shares(a)

                  (143            2,874,905        165        22               22   

Share-based payments (Note 25)

                  106                             106               106   

Share cancellation (Note 17)

    (24,800,000     (62     (1,160            24,800,000        1,222                        

Other operations with non-controlling interests

                  (23                          (23     (24     (47

Other items

                                                              

As of December 31, 2009

    2,348,422,884        5,871        55,372        (5,069     (115,407,190     (3,622     52,552        987        53,539   

Net income 2010

                  10,571                             10,571        236        10,807   

Other comprehensive income (Note 17)

                  (216     2,581                      2,365        9        2,374   

Comprehensive income

                  10,355        2,581                      12,936        245        13,181   

Dividend

                  (5,098                          (5,098     (152     (5,250

Issuance of common shares (Note 17)

    1,218,047        3        38                             41               41   

Purchase of treasury shares

                                                              

Sale of treasury shares(a)

                  (70            2,919,511        119        49               49   

Share-based payments (Note 25)

                  140                             140               140   

Share cancellation (Note 17)

                                                              

Other operations with non-controlling interests

                  (199     (7                   (206     (223     (429

Other items

                                                              

As of December 31, 2010

    2,349,640,931        5,874        60,538        (2,495     (112,487,679     (3,503     60,414        857        61,271   

Net income 2011

                  12,276                             12,276        305        12,581   

Other comprehensive income (Note 17)

                  231        1,404                      1,635        44        1,679   

Comprehensive income

                  12,507        1,404                      13,911        349        14,260   

Dividend

                  (6,457                          (6,457     (172     (6,629

Issuance of common shares (Note 17)

    14,126,382        35        446                             481               481   

Purchase of treasury shares

                                                              

Sale of treasury shares(a)

                  (113            2,933,506        113                        

Share-based payments (Note 25)

                  161                             161               161   

Share cancellation (Note 17)

                                                              

Other operations with non-controlling interests

                  (553     103                      (450     (123     (573

Other items

                  (23                          (23     441        418   

As of December 31, 2011

    2,363,767,313        5,909        66,506        (988     (109,554,173     (3,390     68,037        1,352        69,389   

 

(a) Treasury shares related to the stock option purchase plans and restricted stock grants.

 

F-7


Table of Contents

TOTAL

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

 

On February 9, 2012, the Board of Directors established and authorized the publication of the Consolidated Financial Statements of TOTAL S.A. for the year ended December 31, 2011, which will be submitted for approval to the shareholders’ meeting to be held on May 11, 2012.

INTRODUCTION

The Consolidated Financial Statements of TOTAL S.A. and its subsidiaries (the Group) are presented in Euros and have been prepared on the basis of IFRS (International Financial Reporting Standards) as adopted by the European Union and IFRS as issued by the IASB (International Accounting Standard Board) as of December 31, 2011.

The accounting principles applied in the Consolidated Financial Statements as of December 31, 2011 were the same as those that were used as of December 31, 2010 except for amendments and interpretations of IFRS which were mandatory for the periods beginning after January 1, 2011 (and not early adopted). Their adoption has no material impact on the Consolidated Financial Statements as of December 31, 2011.

The preparation of financial statements in accordance with IFRS requires the management to make estimates and assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of preparation of the financial statements and reported income and expenses for the period. The management reviews these estimates and assumptions on an ongoing basis, by reference to past experience and various other factors considered as reasonable which form the basis for assessing the carrying amount of assets and liabilities. Actual results may differ significantly from these estimates, if different assumptions or circumstances apply. These judgments and estimates relate principally to the application of the successful efforts method for the oil and gas accounting, the valuation of long-lived assets, the provisions for asset retirement obligations and environmental remediation, the pensions and post-retirements benefits and the income tax computation.

Furthermore, where the accounting treatment of a specific transaction is not addressed by any accounting standard or interpretation, the management applies its judgment to

define and apply accounting policies that will lead to relevant and reliable information, so that the financial statements:

 

 

give a true and fair view of the Group’s financial position, financial performance and cash flows;

 

 

reflect the substance of transactions;

 

 

are neutral;

 

 

are prepared on a prudent basis; and

 

 

are complete in all material aspects.

1) ACCOUNTING POLICIES

Pursuant to the accrual basis of accounting followed by the Group, the financial statements reflect the effects of transactions and other events when they occur. Assets and liabilities such as property, plant and equipment and intangible assets are usually measured at amortized cost. Assets and liabilities are measured at fair value when required by the standards.

Accounting policies used by the Group are described below:

 

A)   PRINCIPLES OF CONSOLIDATION

Subsidiaries that are directly controlled by the parent company or indirectly controlled by other consolidated subsidiaries are fully consolidated.

Investments in jointly-controlled entities are consolidated under the equity method. The Group accounts for jointly-controlled operations and jointly-controlled assets by recognising its share of assets, liabilities, income and expenses.

Investments in associates, in which the Group has significant influence, are accounted for by the equity method. Significant influence is presumed when the Group holds, directly or indirectly (e.g. through subsidiaries), 20% or more of the voting rights. Companies in which ownership interest is less than 20%, but over which the Company is deemed to exercise significant influence, are also accounted for by the equity method.

All significant intercompany balances, transactions and income are eliminated.

 

 

F-8


Table of Contents
B)   BUSINESS COMBINATIONS

Business combinations are accounted for using the acquisition method. This method implies the recognition of the acquired identifiable assets, assumed liabilities and any non-controlling interests in the companies acquired by the Group at their fair value.

The acquirer shall recognize goodwill at the acquisition date, being the excess of:

 

 

The consideration transferred, the amount of non-controlling interests and, in business combinations achieved in stages, the fair value at the acquisition date of the investment previously held in the acquired company;

 

 

Over the fair value at the acquisition date of acquired identifiable assets and assumed liabilities.

If the consideration transferred is lower than the fair value of acquired identifiable assets and assumed liabilities, an additional analysis is performed on the identification and valuation of the identifiable elements of the assets and liabilities. Any residual badwill is recorded as income.

In transactions with non-controlling interests, the difference between the price paid (received) and the book value of non-controlling interests acquired (sold) is recognized directly in equity.

The purchase price allocation is finalized within one year from the acquisition date.

Non-monetary contributions by venturers to a jointly-controlled entity in exchange for an equity interest in the jointly-controlled entity are accounted for by applying guidance provided in SIC 13 “Jointly Controlled Entities — Non-Monetary Contributions by Venturers”. A gain or loss on disposal of the previously held investment is recorded up to the share of the co-venturer in the jointly controlled entity.

 

C)   FOREIGN CURRENCY TRANSLATION

The financial statements of subsidiaries are prepared in the currency that most clearly reflects their business environment. This is referred to as their functional currency.

 

(i) Monetary transactions

Transactions denominated in foreign currencies other than the functional currency of the entity are translated at the exchange rate on the transaction date. At each balance sheet date, monetary assets and liabilities are translated at the closing rate and the resulting exchange differences are recognized in the statement of income.

(ii) Translation of financial statements denominated in foreign currencies

Assets and liabilities of foreign entities are translated into euros on the basis of the exchange rates at the end of the period. The income and cash flow statements are translated using the average exchange rates for the period. Foreign exchange differences resulting from such translations are either recorded in shareholders’ equity under “Currency translation adjustments” (for the Group share) or under “Non-controlling interests” (for the share of non-controlling interests) as deemed appropriate.

 

D)   SALES AND REVENUES FROM SALES

Sales figures include excise taxes collected by the Group within the course of its oil distribution operations. Excise taxes are deducted from sales in order to obtain the “Revenues from sales” indicator.

 

(i) Sale of goods

Revenues from sales are recognized when the significant risks and rewards of ownership have been passed to the buyer and when the amount is recoverable and can be reasonably measured.

Revenues from sales of crude oil, natural gas and coal are recorded upon transfer of title, according to the terms of the sales contracts.

Revenues from the production of crude oil and natural gas properties, in which the Group has an interest with other producers, are recognized based on actual volumes sold during the period. Any difference between volumes sold and entitlement volumes, based on the Group net working interest, is recognized as “Crude oil and natural gas inventories” or “Other current assets” or “Other creditors and accrued liabilities”, as appropriate.

Quantities delivered that represent production royalties and taxes, when paid in cash, are included in oil and gas sales, except for the United States and Canada.

Certain transactions within the trading activities (contracts involving quantities that are purchased to third parties then resold to third parties) are shown at their net value in sales.

Exchanges of crude oil and petroleum products within normal trading activities do not generate any income and therefore these flows are shown at their net value in both the statement of income and the balance sheet.

 

(ii) Sale of services

Revenues from services are recognized when the services have been rendered.

 

 

F-9


Table of Contents

Revenues from gas transport are recognized when services are rendered. These revenues are based on the quantities transported and measured according to procedures defined in each service contract.

Shipping revenues and expenses from time-charter activities are recognized on a pro rata basis over a period that commences upon the unloading of the previous voyage and terminates upon the unloading of the current voyage. Shipping revenue recognition starts only when a charter has been agreed to by both the Group and the customer.

 

E)   SHARE-BASED PAYMENTS

The Group may grant employees stock options, create employee share purchase plans and offer its employees the opportunity to subscribe to reserved capital increases. These employee benefits are recognized as expenses with a corresponding credit to shareholders’ equity.

The expense is equal to the fair value of the instruments granted. The fair value of the options is calculated using the Black-Scholes model at the grant date. The expense is recognized on a straight-line basis between the grant date and vesting date.

For restricted share plans, the expense is calculated using the market price at the grant date after deducting the expected distribution rate during the vesting period.

The cost of employee-reserved capital increases is immediately expensed. A discount reduces the expense in order to account for the nontransferability of the shares awarded to the employees over a period of five years.

 

F)   INCOME TAXES

Income taxes disclosed in the statement of income include the current tax expenses and the deferred tax expenses.

The Group uses the method whereby deferred income taxes are recorded based on the temporary differences between the carrying amounts of assets and liabilities recorded in the balance sheet and their tax bases, and on carry-forwards of unused tax losses and tax credits.

Deferred tax assets and liabilities are measured using the tax rates that have been enacted or substantially enacted at the balance sheet date. The tax rates used depend on the timing of reversals of temporary differences, tax losses and other tax credits. The effect of a change in tax rate is recognized either in the Consolidated Statement of Income or in shareholders’ equity depending on the item it relates to.

 

Deferred tax assets are recognized when future recovery is probable.

Asset retirement obligations and finance leases give rise to the recognition of assets and liabilities for accounting purposes as described in paragraph K “Leases” and paragraph Q “Asset retirement obligations” of this Note. Deferred income taxes resulting from temporary differences between the carrying amounts and tax bases of such assets and liabilities are recognized.

Deferred tax liabilities resulting from temporary differences between the carrying amounts of equity-method investments and their tax bases are recognized. The deferred tax calculation is based on the expected future tax effect (dividend distribution rate or tax rate on the gain or loss upon disposal of these investments).

 

G)   EARNINGS PER SHARE

Earnings per share is calculated by dividing net income (Group share) by the weighted-average number of common shares outstanding during the period, excluding TOTAL shares held by TOTAL S.A. (Treasury shares) and TOTAL shares held by the Group subsidiaries which are deducted from consolidated shareholders’ equity.

Diluted earnings per share is calculated by dividing net income (Group share) by the fully-diluted weighted-average number of common shares outstanding during the period. Treasury shares held by the parent company, TOTAL S.A., and TOTAL shares held by the Group subsidiaries are deducted from consolidated shareholders’ equity. These shares are not considered outstanding for purposes of this calculation which also takes into account the dilutive effect of stock options, share grants and capital increases with a subscription period closing after the end of the fiscal year.

The weighted-average number of fully-diluted shares is calculated in accordance with the treasury stock method provided for by IAS 33. The proceeds, which would be recovered in the event of an exercise of rights related to dilutive instruments, are presumed to be a share buyback at the average market price over the period. The number of shares thereby obtained leads to a reduction in the total number of shares that would result from the exercise of rights.

H) OIL AND GAS EXPLORATION AND PRODUCING PROPERTIES AND MINING ACTIVITY

The Group applies IFRS 6 “Exploration for and Evaluation of Mineral Resources”. Oil and gas exploration and production properties and assets are accounted for in accordance with the successful efforts method.

 

 

F-10


Table of Contents
(i) Exploration costs

Geological and geophysical costs, including seismic surveys for exploration purposes are expensed as incurred.

Mineral interests are capitalized as intangible assets when acquired. These acquired interests are tested for impairment on a regular basis, property-by-property, based on the results of the exploratory activity and the management’s evaluation.

In the event of a discovery, the unproved mineral interests are transferred to proved mineral interests at their net book value as soon as proved reserves are booked.

Exploratory wells are tested for impairment on a well-by-well basis and accounted for as follows:

 

 

Costs of exploratory wells which result in proved reserves are capitalized and then depreciated using the unit-of-production method based on proved developed reserves;

 

 

Costs of dry exploratory wells and wells that have not found proved reserves are charged to expense;

 

 

Costs of exploratory wells are temporarily capitalized until a determination is made as to whether the well has found proved reserves if both of the following conditions are met:

 

   

The well has found a sufficient quantity of reserves to justify its completion as a producing well, if appropriate, assuming that the required capital expenditures are made;

 

   

The Group is making sufficient progress assessing the reserves and the economic and operating viability of the project. This progress is evaluated on the basis of indicators such as whether additional exploratory works are under way or firmly planned (wells, seismic or significant studies), whether costs are being incurred for development studies and whether the Group is waiting for governmental or other third-party authorization of a proposed project, or availability of capacity on an existing transport or processing facility.

Costs of exploratory wells not meeting these conditions are charged to expense.

 

(ii) Oil and Gas producing assets

Development costs incurred for the drilling of development wells and for the construction of production facilities are capitalized, together with borrowing costs incurred during

the period of construction and the present value of estimated future costs of asset retirement obligations. The depletion rate is usually equal to the ratio of oil and gas production for the period to proved developed reserves (unit-of-production method).

With respect to production sharing contracts, this computation is based on the portion of production and reserves assigned to the Group taking into account estimates based on the contractual clauses regarding the reimbursement of exploration, development and production costs (cost oil) as well as the sharing of hydrocarbon rights (profit oil).

Transportation assets are depreciated using the unit-of-production method based on throughput or by using the straight-line method whichever best reflects the economic life of the asset.

Proved mineral interests are depreciated using the unit-of-production method based on proved reserves.

 

(iii) Mining activity

Before an assessment can be made on the existence of resources, exploration costs, including studies and core drilling campaigns as a whole, are expensed.

When the assessment concludes that resources exist, the costs engaged subsequently to this assessment are capitalized temporarily while waiting for the field final development decision, if a positive decision is highly probable. Otherwise, these costs are expensed.

Once the development decision is taken, the predevelopment costs capitalized temporarily are integrated with the cost of development and depreciated from the start of production at the same pace than development assets.

Mining development costs include the initial stripping costs and all costs incurred to access resources, and particularly the costs of:

 

 

Surface infrastructures;

 

 

Machinery and mobile equipment which are significantly costly;

 

 

Utilities and off-sites.

These costs are capitalized and depreciated either on a straight line basis or depleted using the UOP method from the start of production.

I) GOODWILL AND OTHER INTANGIBLE ASSETS EXCLUDING MINERAL INTERESTS

Other intangible assets include goodwill, patents, trademarks, and lease rights.

 

 

F-11


Table of Contents

Intangible assets are carried at cost, after deducting any accumulated depreciation and accumulated impairment losses.

Guidance for calculating goodwill is presented in Note 1 paragraph B to the Consolidated Financial Statements. Goodwill is not amortized but is tested for impairment annually or as soon as there is any indication of impairment (see Note 1 paragraph L to the Consolidated Financial Statements).

In equity affiliates, goodwill is included in the investment book value.

Other intangible assets (except goodwill) have a finite useful life and are amortized on a straight-line basis over 3 to 20 years depending on the useful life of the assets.

Research and development

Research costs are charged to expense as incurred.

Development expenses are capitalized when the following can be demonstrated:

 

 

the technical feasibility of the project and the availability of the adequate resources for the completion of the intangible asset;

 

 

the ability of the asset to generate probable future economic benefits;

 

 

the ability to measure reliably the expenditures attributable to the asset; and

 

 

the feasibility and intention of the Group to complete the intangible asset and use or sell it.

Advertising costs are charged to expense as incurred.

 

J)   OTHER PROPERTY, PLANT AND EQUIPMENT

Other property, plant and equipment are carried at cost, after deducting any accumulated depreciation and accumulated impairment losses. This cost includes borrowing costs directly attributable to the acquisition or production of a qualifying asset incurred until assets are placed in service. Borrowing costs are capitalized as follows:

 

 

if the project benefits from a specific funding, the capitalization of borrowing costs is based on the borrowing rate;

 

 

if the project is financed by all the Group’s debt, the capitalization of borrowing costs is based on the weighted average borrowing cost for the period.

Routine maintenance and repairs are charged to expense as incurred. The costs of major turnarounds of refineries

and large petrochemical units are capitalized as incurred and depreciated over the period of time between two consecutive major turnarounds.

Other property, plant and equipment are depreciated using the straight-line method over their useful lives, which are as follows:

 

•    Furniture, office equipment, machinery and tools

     3-12 years   

•    Transportation equipments

     5-20 years   

•    Storage tanks and related equipment

     10-15 years   

•    Specialized complex installations and pipelines

     10-30 years   

•    Buildings

     10-50 years   

 

K)   LEASES

A finance lease transfers substantially all the risks and rewards incidental to ownership from the lessor to the lessee. These contracts are capitalized as assets at fair value or, if lower, at the present value of the minimum lease payments according to the contract. A corresponding financial debt is recognized as a financial liability. These assets are depreciated over the corresponding useful life used by the Group.

Leases that are not finance leases as defined above are recorded as operating leases.

Certain arrangements do not take the legal form of a lease but convey the right to use an asset or a group of assets in return for fixed payments. Such arrangements are accounted for as leases and are analyzed to determine whether they should be classified as operating leases or as finance leases.

 

L)   IMPAIRMENT OF LONG-LIVED ASSETS

The recoverable amounts of intangible assets and property, plant and equipment are tested for impairment as soon as any indication of impairment exists. This test is performed at least annually for goodwill.

The recoverable amount is the higher of the fair value (less costs to sell) or its value in use.

Assets are grouped into cash-generating units (or CGUs) and tested. A cash-generating unit is a homogeneous group of assets that generates cash inflows that are largely independent of the cash inflows from other groups of assets.

The value in use of a CGU is determined by reference to the discounted expected future cash flows, based upon the management’s expectation of future economic and operating conditions. When this value is less than the carrying amount of the CGU, an impairment loss is

 

 

F-12


Table of Contents

recorded. It is allocated first to goodwill in counterpart of “Other expenses”. These impairment losses are then allocated to “Depreciation, depletion and amortization of tangible assets and mineral interests” for property, plant and mineral interests and to “Other expenses” for other intangible assets.

Impairment losses recognized in prior periods can be reversed up to the original carrying amount, had the impairment loss not been recognized. Impairment losses recognized for goodwill cannot be reversed.

 

M)   FINANCIAL ASSETS AND LIABILITIES

Financial assets and liabilities are financial loans and receivables, investments in non-consolidated companies, publicly traded equity securities, derivatives instruments and current and non-current financial liabilities.

The accounting treatment of these financial assets and liabilities is as follows:

 

(i) Loans and receivables

Financial loans and receivables are recognized at amortized cost. They are tested for impairment, by comparing the carrying amount of the assets to estimates of the discounted future recoverable cash flows. These tests are conducted as soon as there is any evidence that their fair value is less than their carrying amount, and at least annually. Any impairment loss is recorded in the statement of income.

 

(ii) Other investments

These assets are classified as financial assets available for sale and therefore measured at their fair value. For listed securities, this fair value is equal to the market price. For unlisted securities, if the fair value is not reliably determinable, securities are recorded at their historical value. Changes in fair value are recorded in shareholders’ equity. If there is any evidence of a significant or long-lasting impairment loss, a loss is recorded in the Statement of Income. This impairment is reversed in the statement of income only when the securities are sold.

 

(iii) Derivative instruments

The Group uses derivative instruments to manage its exposure to risks of changes in interest rates, foreign exchange rates and commodity prices. Changes in fair value of derivative instruments are recognized in the statement of income or in shareholders’ equity and are recognized in the balance sheet in the accounts corresponding to their nature, according to the risk management strategy described in Note 31 to the

Consolidated Financial Statements. The derivative instruments used by the Group are the following:

 

 

Cash management

Financial instruments used for cash management purposes are part of a hedging strategy of currency and interest rate risks within global limits set by the Group and are considered to be used for transactions (held for trading). Changes in fair value are systematically recorded in the statement of income. The balance sheet value of those instruments is included in “Current financial assets” or “Other current financial liabilities”.

 

 

Long-term financing

When an external long-term financing is set up, specifically to finance subsidiaries, and when this financing involves currency and interest rate derivatives, these instruments are qualified as:

 

  i. Fair value hedge of the interest rate risk on the external debt and of the currency risk of the loans to subsidiaries. Changes in fair value of derivatives are recognized in the statement of income as are changes in fair value of underlying financial debts and loans to subsidiaries.

The fair value of those hedging instruments of long-term financing is included in the assets under “Hedging instruments on non-current financial debt” or in the liabilities under “Non-current financial debt “for the non-current portion. The current portion (less than one year) is accounted for in “Current financial assets” or “Other current financial liabilities”.

In case of the anticipated termination of derivative instruments accounted for as fair value hedges, the amount paid or received is recognized in the statement of income and:

 

   

If this termination is due to an early cancellation of the hedged items, the adjustment previously recorded as revaluation of those hedged items is also recognized in the statement of income;

 

   

If the hedged items remain in the balance sheet, the adjustment previously recorded as a revaluation of those hedged items is spread over the remaining life of those items.

 

  ii.

Cash flow hedge of the currency risk of the external debt. Changes in fair value are recorded in equity for the effective portion of the hedging and in the statement of income for the ineffective portion of the hedging. Amounts recorded in

 

 

F-13


Table of Contents
  equity are transferred to the income statement when the hedged transaction affects profit or loss.

The fair value of those hedging instruments of long-term financing is included in the assets under “Hedging instruments on non-current financial debt” or in the liabilities under “Non-current financial debt” for the non-current portion. The current portion (less than one year) is accounted for in “Current financial assets” or “Other current financial liabilities”.

If the hedging instrument expires, is sold or terminated by anticipation, gains or losses previously recognized in equity remain in equity. Amounts are recycled in the income statement only when the hedged transaction affects profit or loss.

 

 

Foreign subsidiaries’ equity hedge

Certain financial instruments hedge against risks related to the equity of foreign subsidiaries whose functional currency is not the euro (mainly the dollar). These instruments qualify as “net investment hedges”. Changes in fair value are recorded in shareholders’ equity.

The fair value of these instruments is recorded under “Current financial assets” or “Other current financial liabilities”.

 

 

Financial instruments related to commodity contracts

Financial instruments related to commodity contracts, including crude oil, petroleum products, gas, power and coal purchase/sales contracts within the trading activities, together with the commodity contract derivative instruments such as energy contracts and forward freight agreements, are used to adjust the Group’s exposure to price fluctuations within global trading limits. According to the industry practice, these instruments are considered as held for trading. Changes in fair value are recorded in the statement of income. The fair value of these instruments is recorded in “Other current assets” or “Other creditors and accrued liabilities” depending on whether they are assets or liabilities.

Detailed information about derivatives positions is disclosed in Notes 20, 28, 29, 30 and 31 to the Consolidated Financial Statements.

 

(iv) Current and non-current financial liabilities

Current and non-current financial liabilities (excluding derivatives) are recognized at amortized cost, except those

for which a hedge accounting can be applied as described in the previous paragraph.

 

(v) Fair value of financial instruments

Fair values are estimated for the majority of the Group’s financial instruments, with the exception of publicly traded equity securities and marketable securities for which the market price is used.

Estimated fair values, which are based on principles such as discounting future cash flows to present value, must be weighted by the fact that the value of a financial instrument at a given time may be influenced by the market environment (liquidity especially), and also the fact that subsequent changes in interest rates and exchange rates are not taken into account.

As a consequence, the use of different estimates, methodologies and assumptions could have a material effect on the estimated fair value amounts.

The methods used are as follows:

 

 

Financial debts, swaps

The market value of swaps and of bonds that are hedged by those swaps has been determined on an individual basis by discounting future cash flows with the zero coupon interest rate curves existing at year-end.

 

 

Financial instruments related to commodity contracts

The valuation methodology is to mark to market all open positions for both physical and paper transactions. The valuations are determined on a daily basis using observable market data based on organized and over the counter (OTC) markets. In particular cases when market data are not directly available, the valuations are derived from observable data such as arbitrages, freight or spreads and market corroboration. For valuation of risks which are the result of a calculation, such as options for example, commonly known models are used to compute the fair value.

 

 

Other financial instruments

The fair value of the interest rate swaps and of FRA (Forward Rate Agreement) are calculated by discounting future cash flows on the basis of zero coupon interest rate curves existing at year-end after adjustment for interest accrued but unpaid.

Forward exchange contracts and currency swaps are valued on the basis of a comparison of the negociated

 

 

F-14


Table of Contents

forward rates with the rates in effect on the financial markets at year-end for similar maturities.

Exchange options are valued based on the Garman-Kohlhagen model including market quotations at year-end.

 

 

Fair value hierarchy

IFRS 7 “Financial instruments: disclosures”, amended in 2009, introduces a fair value hierarchy for financial instruments and proposes the following three-level classification :

 

   

level 1: quotations for assets and liabilities (identical to the ones that are being valued) obtained at the valuation date on an active market to which the entity has access;

 

   

level 2: the entry data are observable data but do not correspond to quotations for identical assets or liabilities;

 

   

level 3: the entry data are not observable data. For example: these data come from extrapolation. This level applies when there is no market or observable data and the company has to use its own hypotheses to estimate the data that other market players would have used to determine the fair value of the asset.

Fair value hierarchy is disclosed in Notes 29 and 30 to the Consolidated Financial Statements.

 

N)   INVENTORIES

Inventories are measured in the Consolidated Financial Statements at the lower of historical cost or market value. Costs for petroleum and petrochemical products are determined according to the FIFO (First-In, First-Out) method and other inventories are measured using the weighted-average cost method.

Downstream (Refining — Marketing)

Petroleum product inventories are mainly comprised of crude oil and refined products. Refined products principally consist of gasoline, kerosene, diesel, fuel oil and heating oil produced by the Group’s refineries. The turnover of petroleum products does not exceed two months on average.

Crude oil costs include raw material and receiving costs. Refining costs principally include the crude oil costs, production costs (energy, labor, depreciation of producing assets) and allocation of production overhead (taxes, maintenance, insurance, etc.). Start-up costs and general administrative costs are excluded from the cost price of refined products.

Chemicals

Costs of chemical products inventories consist of raw material costs, direct labor costs and an allocation of production overhead. Start-up costs and general administrative costs are excluded from the cost of inventories of chemicals products.

 

O)   TREASURY SHARES

Treasury shares of the parent company held by its subsidiaries or itself are deducted from consolidated shareholders’ equity. Gains or losses on sales of treasury shares are excluded from the determination of net income and are recognized in shareholders’ equity.

 

P)   PROVISIONS AND OTHER NON-CURRENT LIABILITIES

Provisions and non-current liabilities are comprised of liabilities for which the amount and the timing are uncertain. They arise from environmental risks, legal and tax risks, litigation and other risks.

A provision is recognized when the Group has a present obligation (legal or constructive) as a result of a past event for which it is probable that an outflow of resources will be required and when a reliable estimate can be made regarding the amount of the obligation. The amount of the liability corresponds to the best possible estimate.

 

Q)   ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations, which result from a legal or constructive obligation, are recognized based on a reasonable estimate in the period in which the obligation arises.

The associated asset retirement costs are capitalized as part of the carrying amount of the underlying asset and depreciated over the useful life of this asset.

An entity is required to measure changes in the liability for an asset retirement obligation due to the passage of time (accretion) by applying a risk-free discount rate to the amount of the liability. The increase of the provision due to the passage of time is recognized as “Other financial expense”.

 

R)   EMPLOYEE BENEFITS

In accordance with the laws and practices of each country, the Group participates in employee benefit plans offering retirement, death and disability, healthcare and special termination benefits. These plans provide benefits based on various factors such as length of service, salaries, and contributions made to the governmental bodies responsible for the payment of benefits.

 

 

F-15


Table of Contents

These plans can be either defined contribution or defined benefit pension plans and may be entirely or partially funded with investments made in various non-Group instruments such as mutual funds, insurance contracts, and other instruments.

For defined contribution plans, expenses correspond to the contributions paid.

Defined benefit obligations are determined according to the Projected Unit Method. Actuarial gains and losses may arise from differences between actuarial valuation and projected commitments (depending on new calculations or assumptions) and between projected and actual return of plan assets.

The Group applies the corridor method to amortize its actuarial gains and losses. This method amortizes the net cumulative actuarial gains and losses that exceed 10% of the greater of the present value of the defined benefit obligation and the fair value of plan assets at the opening balance sheet date, over the average expected remaining working lives of the employees participating in the plan.

In case of a change in or creation of a plan, the vested portion of the cost of past services is recorded immediately in the statement of income, and the unvested past service cost is amortized over the vesting period.

The net periodic pension cost is recognized under “Other operating expenses”.

 

S)   CONSOLIDATED STATEMENT OF CASH FLOWS

The Consolidated Statement of Cash Flows prepared in foreign currencies has been translated into euros using the exchange rate on the transaction date or the average exchange rate for the period. Currency translation differences arising from the translation of monetary assets and liabilities denominated in foreign currency into euros using the closing exchange rates are shown in the Consolidated Statement of Cash Flows under “Effect of exchange rates”. Therefore, the Consolidated Statement of Cash Flows will not agree with the figures derived from the Consolidated Balance Sheet.

Cash and cash equivalents

Cash and cash equivalents are comprised of cash on hand and highly liquid short-term investments that are easily convertible into known amounts of cash and are subject to insignificant risks of changes in value.

Investments with maturity greater than three months and less than twelve months are shown under “Current financial assets”.

Changes in current financial assets and liabilities are included in the financing activities section of the Consolidated Statement of Cash Flows.

Non-current financial debt

Changes in non-current financial debt are presented as the net variation to reflect significant changes mainly related to revolving credit agreements.

 

T)   CARBON DIOXIDE EMISSION RIGHTS

In the absence of a current IFRS standard or interpretation on accounting for emission rights of carbon dioxide, the following principles are applied:

 

 

Emission rights are managed as a cost of production and as such are recognized in inventories:

 

   

Emission rights allocated for free are booked in inventories with a nil carrying amount,

 

   

Purchased emission rights are booked at acquisition cost,

 

   

Sales or annual restorations of emission rights consist of decreases in inventories recognized based on a weighted average cost,

 

   

If the carrying amount of inventories at closing date is higher than the market value, an impairment loss is recorded.

 

 

At each closing, a provision is recorded in order to materialize the obligation of emission rights restoration related to the emissions of the period. This provision is calculated based on estimated emissions of the period, valued at weighted average cost of the inventories at the end of the period. It is reversed when the emission rights are restored.

 

 

If emission rights to be delivered at the end of the compliance period are higher than emission rights (allocated and purchased) booked in inventories, the shortage is accounted for as a liability at market value.

 

 

Forward transactions are recognized at their fair market value in the balance sheet. Changes in the fair value of such forward transactions are recognized in the statement of income.

 

U)   NON-CURRENT ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS

Pursuant to IFRS 5 “Non-current assets held for sale and discontinued operations”, assets and liabilities of affiliates that are held for sale are presented separately on the face of the balance sheet.

 

 

F-16


Table of Contents

Net income from discontinued operations is presented separately on the face of the statement of income. Therefore, the notes to the Consolidated Financial Statements related to the statement of income only refer to continuing operations.

A discontinued operation is a component of the Group for which cash flows are independent. It represents a major line of business or geographical area of operations which has been disposed of or is currently being held for sale.

 

V)   ALTERNATIVE IFRS METHODS

For measuring and recognizing assets and liabilities, the following choices among alternative methods allowable under IFRS have been made:

 

 

property, plant and equipment, and intangible assets are measured using historical cost model instead of revaluation model;

 

 

actuarial gains and losses on pension and other post-employment benefit obligations are recognized according to the corridor method (see Note 1 paragraph R to the Consolidated Financial Statements);

 

 

jointly-controlled entities are consolidated under the equity method, as provided for in the alternative method of IAS 31 “Interests in joint ventures”.

W) NEW ACCOUNTING PRINCIPLES NOT YET IN EFFECT

The standards or interpretations published respectively by the International Accounting Standards Board (IASB) and the International Financial Reporting Interpretations Committee (IFRIC) which were not yet in effect and not adopted by the European Union at December 31, 2011, are as follows:

 

 

In November 2009, the IASB issued standard IFRS 9 “Financial Instruments” that introduces new requirements for the classification and measurement of financial assets, and included in October 2010 requirements regarding classification and measurement of financial liabilities. This standard shall be completed with texts on impairment and hedge accounting. Under standard IFRS 9, financial assets and liabilities are generally measured either at fair value through profit or loss or at amortised cost if certain conditions are met. The standard should be applicable for annual periods starting on or after January 1, 2015. The application of the standard as published in 2010 should not have any material effect on the Group’s consolidated balance sheet, statement of income and shareholder’s equity.

 

In May 2011, the IASB issued a package of standards on consolidation : standard IFRS 10 “Consolidated financial statements”, standard IFRS 11 “Joint arrangements”, standard IFRS 12 “Disclosure of interests in other entities”, revised standard IAS 27 “Separate financial statements” and revised standard IAS 28 “Investments in associates and joint ventures”. These standards are applicable for annual periods beginning on or after January 1, 2013. The impact of the application of these standards is currently assessed by the Group.

 

 

In June 2011, the IASB issued revised standard IAS 19 “Employee benefits”, which leads in particular to the full recognition of the net position in respect of employee benefits obligations (liabilities net of assets) in the balance sheet, to the elimination of the corridor approach currently used by the Group and to the obligation to evaluate the expected return on plan assets on a normative basis (via the discount rate used to value the debt). This standard is applicable for annual periods beginning on or after January 1, 2013. The impact of the application of this standard is currently assessed by the Group.

 

 

In addition, the IASB published in May 2011 standard IFRS 13 “Fair value measurement”, applicable for annual periods beginning on or after January 1, 2013, and in June 2011 revised standard IAS 1 “Presentation of financial statements”, applicable for annual periods beginning on or after July 1, 2012. The application of these standards should not have any material effect on the Group’s consolidated balance sheet, statement of income and shareholder’s equity.

2) MAIN INDICATORS — INFORMATION BY BUSINESS SEGMENT

Performance indicators excluding the adjustment items, such as adjusted operating income, adjusted net operating income, and adjusted net income are meant to facilitate the analysis of the financial performance and the comparison of income between periods.

Adjustment items

The detail of these adjustment items is presented in Note 4 to the Consolidated Financial Statements.

Adjustment items include :

 

(i) Special items

Due to their unusual nature or particular significance, certain transactions qualified as “special items” are excluded from the business segment figures. In general,

 

 

F-17


Table of Contents

special items relate to transactions that are significant, infrequent or unusual. However, in certain instances, transactions such as restructuring costs or assets disposals, which are not considered to be representative of the normal course of business, may be qualified as special items although they may have occurred within prior years or are likely to occur again within the coming years.

 

(ii) The inventory valuation effect

The adjusted results of the Downstream and Chemicals segments are presented according to the replacement cost method. This method is used to assess the segments’ performance and facilitate the comparability of the segments’ performance with those of its competitors.

In the replacement cost method, which approximates the LIFO (Last-In, First-Out) method, the variation of inventory values in the statement of income is, depending on the nature of the inventory, determined using either the month-end prices differential between one period and another or the average prices of the period rather than the historical value. The inventory valuation effect is the difference between the results according to the FIFO (First-In, First-Out) and the replacement cost.

 

(iii) Effect of changes in fair value

As from January 1, 2011, the effect of changes in fair value presented as adjustment item reflects for some transactions differences between internal measure of performance used by TOTAL’s management and the accounting for these transactions under IFRS.

IFRS requires that trading inventories be recorded at their fair value using period end spot prices. In order to best reflect the management of economic exposure through derivative transactions, internal indicators used to measure performance include valuations of trading inventories based on forward prices.

Furthermore, TOTAL, in its trading activities, enters into storage contracts, which future effects are recorded at fair value in Group’s internal economic performance. IFRS precludes recognition of this fair value effect.

 

(iv) Until June 30, 2010, TOTAL’s equity share of adjustment items reconciling “Business net income” to Net income attributable to equity holders of Sanofi (see Note 3, paragraph on the sales of Sanofi shares and loss of significant influence over Sanofi)

Main indicators

 

(i) Operating income (measure used to evaluate operating performance)

Revenue from sales after deducting cost of goods sold and inventory variations, other operating expenses,

exploration expenses and depreciation, depletion, and amortization.

Operating income excludes the amortization of intangible assets other than mineral interests, currency translation adjustments and gains or losses on the disposal of assets.

 

(ii) Net operating income (measure used to evaluate the return on capital employed)

Operating income after taking into account the amortization of intangible assets other than mineral interests, currency translation adjustments, gains or losses on the disposal of assets, as well as all other income and expenses related to capital employed (dividends from non-consolidated companies, equity in income of affiliates, capitalized interest expenses), and after income taxes applicable to the above.

The only income and expense not included in net operating income but included in net income are interest expenses related to net financial debt, after applicable income taxes (net cost of net debt) and non-controlling interests.

 

(iii) Adjusted income

Operating income, net operating income, or net income excluding the effect of adjustment items described above.

 

(iv) Fully-diluted adjusted earnings per share

Adjusted net income divided by the fully-diluted weighted-average number of common shares.

 

(v) Capital employed

Non-current assets and working capital, at replacement cost, net of deferred income taxes and non-current liabilities.

 

(vi) ROACE (Return on Average Capital Employed)

Ratio of adjusted net operating income to average capital employed between the beginning and the end of the period.

 

(vii) ROE (Return on Equity)

Ratio of adjusted consolidated net income to average adjusted shareholders’ equity (after distribution) between the beginning and the end of the period.

 

(viii) Net debt

Non-current debt, including current portion, current borrowings, other current financial liabilities less cash and cash equivalents and other current financial assets.

 

 

F-18


Table of Contents
3)   CHANGES IN THE GROUP STRUCTURE, MAIN ACQUISITIONS AND DIVESTMENTS

During 2011, 2010 and 2009, main changes in the Group structure and main acquisitions and divestments were as follows:

2011

 

 

Upstream

 

   

TOTAL finalized in March 2011 the acquisition from Santos of an additional 7.5% interest in Australia’s GLNG project. This increases TOTAL’s overall stake in the project to 27.5%.

The acquisition cost amounts to 202 million ($281 million) and mainly corresponds to the value of mineral interests that have been recognized as intangible assets in the consolidated balance sheet for 227 million.

 

   

In March 2011, Total E&P Canada Ltd., a TOTAL subsidiary, and Suncor Energy Inc. (Suncor) have finalized a strategic oil sands alliance encompassing the Suncor-operated Fort Hills mining project, the TOTAL-operated Joslyn mining project and the Suncor-operated Voyageur upgrader project. All three assets are located in the Athabasca region of the province of Alberta, in Canada.

TOTAL acquired 19.2% of Suncor’s interest in the Fort Hills project, increasing TOTAL’s overall interest in the project to 39.2%. Suncor, as operator, holds 40.8%. TOTAL also acquired a 49% stake in the Suncor-operated Voyageur upgrader project. For those two acquisitions, the Group paid 1,937 million (CAD 2,666 million) mainly representing the value of intangible assets for 474 million and the value of tangible assets for 1,550 million.

Furthermore, TOTAL sold to Suncor 36.75% interest in the Joslyn project for 612 million (CAD 842 million). The Group, as operator, retains a 38.25% interest in the project.

 

   

TOTAL finalized in April 2011 the sale of its 75.8% interest in its upstream Cameroonian affiliate Total E&P Cameroun to Perenco, for an amount of 172 million ($247 million), net of cash sold.

   

TOTAL and the Russian company Novatek signed in March 2011 two Memorandums of Cooperation to develop the cooperation between TOTAL on one side, and Novatek and its main shareholders on the other side.

This cooperation is developed around the two following axes:

 

   

In April 2011, TOTAL took a 12.09% shareholding in Novatek for an amount of 2,901 million ($4,108 million). In December 2011, TOTAL finalized the acquisition of an additional 2% interest in Novatek for an amount of 596 million ($796 million), increasing TOTAL’s overall interest in Novatek to 14.09%. TOTAL considers that it has a significant influence especially through its representation on the Board of Directors of Novatek and its participation in the major Yamal LNG project. Therefore, the interest in Novatek has been accounted for by the equity method since the second quarter of 2011.

 

   

In October 2011, TOTAL finalized the acquisition of a 20% interest in the Yamal LNG project and has become Novatek’s partner in this project.

 

   

After the all-cash tender of $23.25 per share launched on April 28, 2011 and completed on June 21, 2011, TOTAL has acquired a 60% stake in SunPower Corp., a U.S. company listed on Nasdaq with headquarters in San Jose (California), one of the most established players in the American solar industry. Shares of SunPower Corp. continue to be traded on the Nasdaq.

The acquisition cost, whose cash payment occurred on June 21, 2011, amounts to 974 million ($1,394 million). In accordance with revised IFRS 3, TOTAL is currently assessing the fair value of identifiable acquired assets, liabilities and contingent liabilities. Based on available information, provisional fair value of net assets acquired at 100% amounts to $1,512 million.

Given the estimated fair value of instruments that are likely to confer rights to non-controlling interests, provisional goodwill amounts to $533 million. This goodwill must be allocated within twelve months from the acquisition date.

 

 

F-19


Table of Contents

Provisional allocation of the acquisition price and the amount of non-controlling interests at the acquisition date are as follows:

 

(M$)    Fair value at the
acquisition date
        

Intangible assets

     465     

Tangible assets

     589     

Accounts receivable, net

     396     

Other current assets

     223     

Other capital employed

     292     

Net debt

     (453        

Net assets of SunPower (100%) as of June 21, 2011

     1,512           

Share attributable at 100% to non-controlling interests

     (76        

Net assets of SunPower (100%) as of June 21, 2011 to share

     1,436           

Group share 60%

       861   

Goodwill

             533   

Acquisition cost of SunPower’s shares

             1,394   

Non-controlling interests (40%)

       575   

Reinclusion of the share attributable at 100% to non-controlling interests

             76   

Non-controlling interests as of June 21, 2011

             651   

 

Since the acquisition date, sales and net income Group share (before impairment of goodwill) realized by SunPower amount respectively to $1,447 million and $(56) million. The goodwill arising from the acquisition of SunPower has been impaired in 2011 (see Note 4E to the Consolidated Financial Statements).

Acquisition-related costs recognized in the statement of income for the period amount to 9 million.

As part of the transaction, various agreements were signed, including a financial guarantee agreement through which TOTAL guarantees up to $1 billion SunPower’s repayments obligations under letters of credit that would be issued during the next five years for the development of solar power plants and large roofs activities. Furthermore, SunPower’s off-balance sheet commitments and contractual obligations are now included in TOTAL’s notes to the Consolidated Financial Statements (see Note 23 to the Consolidated Financial Statements).

 

   

TOTAL finalized in July 2011 the sale of 10% of its interest in the Colombian pipeline OCENSA. The Group still holds a 5.2% interest in this asset.

 

   

TOTAL finalized in September 2011 the acquisition of Esso Italiana’s interests respectively in the Gorgoglione concession (25% interest), which contains the Tempa Rossa field, and in two exploration licenses located in the same area (51.7% for each one). The acquisition increases TOTAL’s interest in the operated Tempa Rossa field to 75%.

   

TOTAL finalized in December 2011 the sale to Silex Gas Norway AS, a wholly owned subsidiary of Allianz, of its entire stake in Gassled (6.4%) and related entities for an amount of 477 million (NOK 3.7 billion).

 

   

Total E&P USA Inc. signed in December 2011 an agreement to enter into a Joint Venture with Chesapeake Exploration L.L.C., a subsidiary of Chesapeake Energy Corporation, and its partner EnerVest Ltd. Under the terms of this agreement, TOTAL acquired a 25% share in Chesapeake’s and EnerVest’s liquids-rich area of the Utica shale play. TOTAL paid to Chesapeake and EnerVest 500 million ($696 million) in cash for the acquisition of these assets. TOTAL will also be committed to pay additional amounts up to $1.63 billion over a maximum period of 7 years in the form of a 60% carry of Chesapeake and EnerVest’s future capital expenditures on drilling and completion of wells within the Joint Venture. Furthermore, TOTAL will also acquire a 25% share in any new acreage which will be acquired by Chesapeake in the liquids-rich area of the Utica shale play.

 

 

Downstream

 

   

TOTAL and International Petroleum Investment Company (a company wholly-owned by the Government of Abu Dhabi) entered into an agreement on February 15, 2011 for the sale, to International Petroleum Investment Company (IPIC), of the 48.83% equity interest held by TOTAL in the share capital of CEPSA, to be completed within the framework of a public tender

 

 

F-20


Table of Contents
   

offer being launched by IPIC for all the CEPSA shares not yet held by IPIC, at a unit purchase price of 28 per CEPSA share. TOTAL sold to IPIC all of its equity interest in CEPSA and received, as of July 29, 2011, an amount of 3,659 million.

 

   

TOTAL finalized in October 2011 the sale of most of its Marketing assets in the United Kingdom, the Channel Islands and the Isle of Man, to Rontec Investments LLP, a consortium led by Snax 24, one of the leading independent forecourt operators in the United Kingdom, for an amount of 424 million (£368 million).

 

 

Chemicals

 

   

TOTAL finalized in July 2011 the sale of its photocure and coatings resins businesses to Arkema for an amount of 520 million, net of cash sold.

2010

 

 

Upstream

 

   

Total E&P Canada Ltd., a TOTAL subsidiary, signed in July 2010 an agreement with UTS Energy Corporation (UTS) to acquire UTS Corporation with its main asset, a 20% interest in the Fort Hills mining project in the Athabasca region of the Canadian province of Alberta.

Total E&P Canada completed on September 30, 2010 the acquisition of all UTS shares for a cash amount of 3.08 Canadian dollars per share. Taking into account the cash held by UTS and acquired by TOTAL (232 million), the cost of the acquisition for TOTAL amounted to 862 million. This amount mainly represented the value of mineral interests that have been recognized as intangible assets in the consolidated balance sheet for 646 million and the value of tangible assets that have been recognized in the consolidated balance sheet for 217 million.

 

   

TOTAL completed in September 2010 an agreement for the sale to BP and Hess of its interests in the Valhall (15.72%) and Hod (25%) fields, in the Norwegian North Sea, for an amount of 800 million.

 

   

TOTAL signed in September 2010 an agreement with Santos and Petronas to acquire a 20% interest in the GLNG project in Australia. Upon completion of this transaction finalised in October 2010, the project brought together Santos (45%, operator), Petronas (35%) and TOTAL (20%).

The acquisition cost amounted to 566 million and it mainly represented the value of mineral interests that have been recognized as intangible assets in the consolidated balance sheet for 617 million.

In addition, TOTAL announced in December 2010 the signature of an agreement to acquire an additional 7.5% interest in this project.

 

   

TOTAL sold in December 2010 its 5% interest in Block 31, located in the Angolan ultra deep offshore, to the company China Sonangol International Holding Limited.

 

 

Downstream

 

   

TOTAL and ERG announced in January 2010 that they signed an agreement to create a joint venture, named TotalErg, by contribution of the major part of their activities in the refining and marketing business in Italy. TotalErg has been operational since October 1st, 2010. The shareholder pact calls for joint governance as well as operating independence for the new entity. TOTAL’s interest in TotalErg is 49% and is accounted for by the equity method (see Note 12 to the Consolidated Financial Statements).

 

 

Chemicals

 

   

TOTAL closed on April 1, 2010 the sale of its consumer specialty chemicals business, Mapa Spontex, to U.S.-based Jarden Corporation for an enterprise value of 335 million.

 

 

Corporate

 

   

On March 24, 2010, TOTAL S.A. filed a public tender offer followed by a squeeze out with the French Autorité des Marchés Financiers (AMF) in order to buy the 1,468,725 Elf Aquitaine shares that it did not already hold, representing 0.52% of Elf Aquitaine’s share capital and 0.27% of its voting rights, at a price of 305 per share (including the remaining 2009 dividend). On April 13, 2010, the French Autorité des marchés financiers (AMF) issued its clearance decision for this offer.

The public tender offer was open from April 16 to April 29, 2010 inclusive. The Elf Aquitaine shares targeted by the offer which were not tendered to the offer have been transferred to TOTAL S.A. under the squeeze out upon payment to the shareholders equal to the offer price on the first trading day after the offer closing date, i.e. on April 30, 2010.

 

 

F-21


Table of Contents

On April 30, 2010, TOTAL S.A. announced that, following the squeeze out, it held 100% of Elf Aquitaine shares, with the transaction amounting to 450 million.

In application of revised standard IAS 27 “Consolidated and Separate Financial Statements”, effective for annual periods beginning on or after January 1, 2010, transactions with non-controlling interests are accounted for as equity transactions, i.e. in consolidated shareholder’s equity.

As a consequence, following the squeeze out of the Elf Aquitaine shares by TOTAL S.A., the difference between the consideration paid and the book value of non-controlling interests acquired was recognized directly as a decrease in equity.

 

   

During 2010, TOTAL progressively sold 1.88% of Sanofi’s share capital, thus reducing its interest to 5.51%.

As from July 1, 2010, given its reduced representation on the Board of Directors and the decrease in the percentage of voting rights, TOTAL ceased to have a significant influence over Sanofi-Aventis and no longer consolidated this investment under the equity method. The investment in Sanofi is accounted for as a financial asset available for sale in the line “Other investments” of the consolidated balance sheet at its fair value, i.e. at the stock price.

Net income as of December 31, 2010 included a 135 million gain relating to this change in the accounting treatment.

2009

 

 

Upstream

 

   

In December 2009, TOTAL signed an agreement with Chesapeake Energy Corporation whereby TOTAL acquired a 25% share in Chesapeake’s Barnett shale gas portfolio located in the United States (State of Texas). The acquisition cost of these assets amounted to 1,562 million and it represented the value of mineral interests that have been recognized as intangible assets in the consolidated balance sheet for 1,449 million and the value of tangible assets that have been recognized in the consolidated balance sheet for 113 million. As no cash payment has occurred in 2009, a corresponding debt has been recognized

   

in the sections “Provisions and other non-current liabilities” and “Other creditors and accrued liabilities” for 818 million and 744 million respectively.

 

 

Corporate

 

   

During 2009, TOTAL progressively sold 3.99% of Sanofi-Aventis’ share capital, thus reducing its interest to 7.39%. Sanofi-Aventis is accounted for by the equity method in TOTAL’s Consolidated Financial Statements for the year ended December 31, 2009.

4) BUSINESS SEGMENT INFORMATION

Financial information by business segment is reported in accordance with the internal reporting system and shows internal segment information that is used to manage and measure the performance of TOTAL. The Group’s activities are conducted through three business segments:

 

 

the Upstream segment includes the activities of the Exploration & Production division and the Gas & Power division;

 

 

the Downstream segment includes activities of the Refining & Marketing division and the Trading & Shipping division; and

 

 

the Chemicals segment includes Base Chemicals and Specialties.

The Corporate segment includes the operating and financial activities of the holding companies (including the investment in Sanofi).

The operational profit and assets are broken down by business segment prior to the consolidation and inter-segment adjustments.

Sales prices between business segments approximate market prices.

Furthermore, the Group announced in October 2011 a plan of reorganization of its business segments Downstream and Chemicals. The consultation and notification process towards employee representatives is finished and this reorganization became effective as of January 1st, 2012.

This plan changed the organization through the creation of:

 

 

a Refining & Chemicals segment that is a major production hub combining TOTAL’s refining, petrochemicals, fertilizers and specialty chemicals operations. This segment also includes Trading & Shipping activities ;

 

 

a Supply & Marketing segment that is dedicated to the global supply and marketing of petroleum products.

 

 

F-22


Table of Contents
A)   INFORMATION BY BUSINESS SEGMENT

 

For the year ended December 31, 2011
(M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany     Total  

Non-Group sales

     23,298        141,907        19,477        11               184,693   

Intersegment sales

     27,301        5,983        1,234        185        (34,703       

Excise taxes

            (18,143                          (18,143

Revenues from sales

     50,599        129,747        20,711        196        (34,703     166,550   

Operating expenses

     (23,079     (126,145     (19,566     (667     34,703        (134,754

Depreciation, depletion and amortization of tangible assets and mineral interests

     (5,076     (1,908     (487     (35            (7,506

Operating income

     22,444        1,694        658        (506            24,290   

Equity in income (loss) of affiliates and other items

     1,596        401        471        336               2,804   

Tax on net operating income

     (13,506     (409     (225     (38            (14,178

Net operating income

     10,534        1,686        904        (208            12,916   

Net cost of net debt

               (335

Non-controlling interests

                                             (305

Net income

                                             12,276   

 

For the year ended December 31, 2011
(adjustments
(a)) (M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany      Total  

Non-Group sales

     45                 45   

Intersegment sales

                  

Excise taxes

                                                

Revenues from sales

     45                 45   

Operating expenses

            1,156        (33               1,123   

Depreciation, depletion and amortization of tangible assets and mineral interests

     (75     (700     (6                     (781

Operating income(b)

     (30     456        (39                    387   

Equity in income (loss) of affiliates and other items

     191        256        209        90           746   

Tax on net operating income

     (32     (109     (41     (80              (262

Net operating income(b)

     129        603        129        10           871   

Net cost of net debt

                  

Non-controlling interests

                                              (19

Net income

                                              852   

 

(a) Adjustments include special items, inventory valuation effect and, as from January 1st, 2011, the effect of changes in fair value.

(b)    Of which inventory valuation effect

     Upstream         Downstream         Chemicals        Corporate         

           on operating income

             1,224         (9             

           on net operating income

             859         10                

 

F-23


Table of Contents
For the year ended December 31, 2011
(adjusted) (M)
(a)
   Upstream     Downstream     Chemicals     Corporate     Intercompany     Total  

Non-Group sales

     23,253        141,907        19,477        11               184,648   

Intersegment sales

     27,301        5,983        1,234        185        (34,703       

Excise taxes

            (18,143                          (18,143

Revenues from sales

     50,554        129,747        20,711        196        (34,703     166,505   

Operating expenses

     (23,079     (127,301     (19,533     (667     34,703        (135,877

Depreciation, depletion and amortization of tangible assets and mineral interests

     (5,001     (1,208     (481     (35            (6,725

Adjusted operating income

     22,474        1,238        697        (506            23,903   

Equity in income (loss) of affiliates and other items

     1,405        145        262        246               2,058   

Tax on net operating income

     (13,474     (300     (184     42               (13,916

Adjusted net operating income

     10,405        1,083        775        (218            12,045   

Net cost of net debt

               (335

Non-controlling interests

                                             (286

Adjusted net income

                                             11,424   

Adjusted fully-diluted earnings per share ()

                                             5.06   

 

(a) Except for earnings per share

 

For the year ended December 31, 2011
(M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany    Total  

Total expenditures

     21,689        1,870        847        135           24,541   

Total divestments

     2,656        3,235        1,164        1,523           8,578   

Cash flow from operating activities

     17,054        2,165        512        (195        19,536   

Balance sheet as of December 31, 2011

             

Property, plant and equipment, intangible assets, net

     64,069        7,918        4,638        245           76,870   

Investments in equity affiliates

     8,932        699        1,118                  10,749   

Loans to equity affiliates and other non-current assets

     4,793        1,749        1,144        3,105           10,791   

Working capital

     1,240        9,627        2,585        (1,374        12,078   

Provisions and other non-current liabilities

     (20,095     (2,577     (1,593     (1,136        (25,401

Assets and liabilities classified as held for sale

                                      

Capital Employed (balance sheet)

     58,939        17,416        7,892        840           85,087   

Less inventory valuation effect

            (3,615     (419     13           (4,021

Capital Employed (Business segment information)

     58,939        13,801        7,473        853           81,066   

ROACE as a percentage

     20%        7%        10%                     16%   

 

F-24


Table of Contents
For the year ended December 31, 2010
(M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany     Total  

Non-Group sales

     18,527        123,245        17,490        7               159,269   

Intersegment sales

     22,540        4,693        981        186        (28,400       

Excise taxes

            (18,793                          (18,793

Revenues from sales

     41,067        109,145        18,471        193        (28,400     140,476   

Operating expenses

     (18,271     (105,660     (16,974     (665     28,400        (113,170

Depreciation, depletion and amortization of tangible assets and mineral interests

     (5,346     (2,503     (533     (39            (8,421

Operating income

     17,450        982        964        (511            18,885   

Equity in income (loss) of affiliates and other items

     1,533        141        215        595               2,484   

Tax on net operating income

     (10,131     (201     (267     263               (10,336

Net operating income

     8,852        922        912        347               11,033   

Net cost of net debt

               (226

Non-controlling interests

                                             (236

Net income

                                             10,571   

 

For the year ended December 31, 2010
(adjustments
(a)) (M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany    Total  

Non-Group sales

             

Intersegment sales

             

Excise taxes

                                             

Revenues from sales

             

Operating expenses

            923        92                  1,015   

Depreciation, depletion and amortization of tangible assets and mineral interests

     (203     (1,192     (21                 (1,416

Operating income(b)

     (203     (269     71                  (401

Equity in income (loss) of affiliates and other items(c)

     183        (126     (16     227           268   

Tax on net operating income

     275        149               (6          418   

Net operating income(b)

     255        (246     55        221           285   

Net cost of net debt

                  

Non-controlling interests

                                          (2

Net income

                                          283   

 

(a)    Adjustments include special items, inventory valuation effect and, until June 30, 2010, equity share of adjustments related to Sanofi.

(b)    Of which inventory valuation effect

     Upstream         Downstream         Chemicals         Corporate        

       on operating income

             863         130                

       on net operating income

             640         113                

(c)    Of which equity share of adjustments related to Sanofi

                             (81     

 

F-25


Table of Contents
For the year ended December 31, 2010
(adjusted) (M)
(a)
   Upstream     Downstream     Chemicals     Corporate     Intercompany     Total  

Non-Group sales

     18,527        123,245        17,490        7               159,269   

Intersegment sales

     22,540        4,693        981        186        (28,400       

Excise taxes

            (18,793                          (18,793

Revenues from sales

     41,067        109,145        18,471        193        (28,400     140,476   

Operating expenses

     (18,271     (106,583     (17,066     (665     28,400        (114,185

Depreciation, depletion and amortization of tangible assets and mineral interests

     (5,143     (1,311     (512     (39            (7,005

Adjusted operating income

     17,653        1,251        893        (511            19,286   

Equity in income (loss) of affiliates and other items

     1,350        267        231        368               2,216   

Tax on net operating income

     (10,406     (350     (267     269               (10,754

Adjusted net operating income

     8,597        1,168        857        126               10,748   

Net cost of net debt

               (226

Non-controlling interests

                                             (234

Adjusted net income

                                             10,288   

Adjusted fully-diluted earnings per share ()

  

                                    4.58   

 

(a) Except for earnings per share

 

For the year ended December 31, 2010
(M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany    Total  

Total expenditures

     13,208        2,343        641        81           16,273   

Total divestments

     2,067        499        347        1,403           4,316   

Cash flow from operating activities

     15,573        1,441        934        545           18,493   

Balance sheet as of December 31, 2010

             

Property, plant and equipment, intangible assets, net

     50,565        8,675        4,388        253           63,881   

Investments in equity affiliates

     5,002        2,782        1,349                  9,133   

Loans to equity affiliates and other non-current assets

     4,184        1,366        979        4,099           10,628   

Working capital

     (363     9,154        2,223        (211        10,803   

Provisions and other non-current liabilities

     (16,076     (2,328     (1,631     (1,181        (21,216

Assets and liabilities classified as held for sale

     660               413                  1,073   

Capital Employed (balance sheet)

     43,972        19,649        7,721        2,960           74,302   

Less inventory valuation effect

            (4,088     (409     1,061           (3,436

Capital Employed (Business segment information)

     43,972        15,561        7,312        4,021           70,866   

ROACE as a percentage

     21%        8%        12%                     16%   

 

F-26


Table of Contents
For the year ended December 31, 2009
(M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany     Total  

Non-Group sales

     16,072        100,518        14,726        11               131,327   

Intersegment sales

     15,958        3,786        735        156        (20,635       

Excise taxes

            (19,174                          (19,174

Revenues from sales

     32,030        85,130        15,461        167        (20,635     112,153   

Operating expenses

     (14,752     (81,281     (14,293     (656     20,635        (90,347

Depreciation, depletion and amortization of tangible assets and mineral interests

     (4,420     (1,612     (615     (35            (6,682

Operating income

     12,858        2,237        553        (524            15,124   

Equity in income (loss) of affiliates and other items

     846        169        (58     697               1,654   

Tax on net operating income

     (7,486     (633     (92     326               (7,885

Net operating income

     6,218        1,773        403        499               8,893   

Net cost of net debt

               (264

Non-controlling interests

                                             (182

Net income

                                             8,447   

 

For the year ended December 31, 2009
(adjustments
(a)) (M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany    Total  

Non-Group sales

             

Intersegment sales

             

Excise taxes

                                             

Revenues from sales

             

Operating expenses

     (17     1,558        344                  1,885   

Depreciation, depletion and amortization of tangible assets and mineral interests

     (4     (347     (40                 (391

Operating income(b)

     (21     1,211        304                  1,494   

Equity in income (loss) of affiliates and other items(c)

     (160     22        (123     (117        (378

Tax on net operating income

     17        (413     (50     (3          (449

Net operating income(b)

     (164     820        131        (120        667   

Net cost of net debt

                  

Non-controlling interests

                                          (4

Net income

                                          663   

 

(a) Adjustments include special items, inventory valuation effect and equity share of adjustments related to Sanofi.

(b)    Of which inventory valuation effect

     Upstream         Downstream         Chemicals         Corporate        

       on operating income

             1,816         389                

       on net operating income

             1,285         254                

(c)    Of which equity share of adjustments related to Sanofi

                             (300     

 

F-27


Table of Contents
For the year ended December 31, 2009
(adjusted) (M)
(a)
   Upstream     Downstream     Chemicals     Corporate     Intercompany     Total  

Non-Group sales

     16,072        100,518        14,726        11               131,327   

Intersegment sales

     15,958        3,786        735        156        (20,635       

Excise taxes

            (19,174                          (19,174

Revenues from sales

     32,030        85,130        15,461        167        (20,635     112,153   

Operating expenses

     (14,735     (82,839     (14,637     (656     20,635        (92,232

Depreciation, depletion and amortization of tangible assets and mineral interests

     (4,416     (1,265     (575     (35            (6,291

Adjusted operating income

     12,879        1,026        249        (524            13,630   

Equity in income (loss) of affiliates and other items

     1,006        147        65        814               2,032   

Tax on net operating income

     (7,503     (220     (42     329               (7,436

Adjusted net operating income

     6,382        953        272        619               8,226   

Net cost of net debt

               (264

Non-controlling interests

                                             (178

Adjusted net income

                                             7,784   

Adjusted fully-diluted earnings per share ()

  

                                    3.48   

 

(a) Except for earnings per share

 

For the year ended December 31, 2009
(M)
   Upstream     Downstream     Chemicals     Corporate     Intercompany    Total  

Total expenditures

     9,855        2,771        631        92           13,349   

Total divestments

     398        133        47        2,503           3,081   

Cash flow from operating activities

     10,200        1,164        1,082        (86        12,360   

Balance sheet as of December 31, 2009

             

Property, plant and equipment, intangible assets, net

     43,997        9,588        5,248        271           59,104   

Investments in equity affiliates

     4,260        2,110        652        4,235           11,257   

Loans to equity affiliates and other non-current assets

     3,844        1,369        850        547           6,610   

Working capital

     660        7,624        2,151        58           10,493   

Provisions and other non-current liabilities

     (15,364     (2,190     (1,721     (1,094        (20,369

Assets and liabilities classified as held for sale

                                      

Capital Employed (balance sheet)

     37,397        18,501        7,180        4,017           67,095   

Less inventory valuation effect

            (3,202     (282     840           (2,644

Capital Employed (Business segment information)

     37,397        15,299        6,898        4,857           64,451   

ROACE as a percentage

     18%        7%        4%                     13%   

 

F-28


Table of Contents
B)   ROE (RETURN ON EQUITY)

The Group evaluates the return on equity as the ratio of adjusted consolidated net income to average adjusted shareholders’ equity between the beginning and the end of

the period. Thus, adjusted shareholders’ equity for the year ended December 31, 2011 is calculated after payment of a dividend of 2.28 per share, subject to approval by the shareholders’ meeting on May 11, 2012.

 

 

The ROE is calculated as follows:

 

For the year ended December 31, (M)    2011     2010     2009  

Adjusted net income — Group share

     11,424        10,288        7,784   

Adjusted non-controlling interests

     286        234        178   

Adjusted consolidated net income

     11,710        10,522        7,962   

Shareholders’ equity — Group share

     68,037        60,414        52,552   

Distribution of the income based on existing shares at the closing date

     (1,255     (2,553     (2,546

Non-controlling interests

     1,352        857        987   

Adjusted shareholders’ equity(a)

     68,134        58,718        50,993   

ROE

     18%        19%        16%   

 

(a) Adjusted shareholders’ equity as of December 31, 2008 amounted to 47,410 million.

 

C)   RECONCILIATION OF THE INFORMATION BY BUSINESS SEGMENT WITH CONSOLIDATED FINANCIAL STATEMENTS

The table below presents the impact of adjustment items on the Consolidated Statement of Income:

 

For the year ended December 31, 2011 (M)    Adjusted     Adjustments(a)     Consolidated
statement of
income
 

Sales

     184,648        45        184,693   

Excise taxes

     (18,143            (18,143

Revenues from sales

     166,505        45        166,550   

Purchases, net of inventory variation

     (115,107     1,215        (113,892

Other operating expenses

     (19,751     (92     (19,843

Exploration costs

     (1,019            (1,019

Depreciation, depletion and amortization of tangible assets and mineral interests

     (6,725     (781     (7,506

Other income

     430        1,516        1,946   

Other expense

     (536     (711     (1,247

Financial interest on debt

     (713            (713

Financial income from marketable securities & cash equivalents

     273               273   

Cost of net debt

     (440            (440

Other financial income

     609               609   

Other financial expense

     (429            (429

Equity in income (loss) of affiliates

     1,984        (59     1,925   

Income taxes

     (13,811     (262     (14,073

Consolidated net income

     11,710        871        12,581   

Group share

     11,424        852        12,276   

Non-controlling interests

     286        19        305   

 

(a) Adjustments include special items, inventory valuation effect and, as from January 1st, 2011, the effect of changes in fair value.

 

F-29


Table of Contents
For the year ended December 31, 2010 (M)    Adjusted     Adjustments(a)     Consolidated
statement of
income
 

Sales

     159,269               159,269   

Excise taxes

     (18,793            (18,793

Revenues from sales

     140,476               140,476   

Purchases, net of inventory variation

     (94,286     1,115        (93,171

Other operating expenses

     (19,035     (100     (19,135

Exploration costs

     (864            (864

Depreciation, depletion and amortization of tangible assets and mineral interests

     (7,005     (1,416     (8,421

Other income

     524        872        1,396   

Other expense

     (346     (554     (900

Financial interest on debt

     (465            (465

Financial income from marketable securities & cash equivalents

     131               131   

Cost of net debt

     (334            (334

Other financial income

     442               442   

Other financial expense

     (407            (407

Equity in income (loss) of affiliates

     2,003        (50     1,953   

Income taxes

     (10,646     418        (10,228

Consolidated net income

     10,522        285        10,807   

Group share

     10,288        283        10,571   

Non-controlling interests

     234        2        236   

 

(a) Adjustments include special items, inventory valuation effect and, until June 30, 2010, equity share of adjustments related to Sanofi.

 

For the year ended December 31, 2009 (M)    Adjusted     Adjustments(a)     Consolidated
statement of
income
 

Sales

     131,327               131,327   

Excise taxes

     (19,174            (19,174

Revenues from sales

     112,153               112,153   

Purchases, net of inventory variation

     (73,263     2,205        (71,058

Other operating expenses

     (18,271     (320     (18,591

Exploration costs

     (698            (698

Depreciation, depletion and amortization of tangible assets and mineral interests

     (6,291     (391     (6,682

Other income

     131        183        314   

Other expense

     (315     (285     (600

Financial interest on debt

     (530            (530

Financial income from marketable securities & cash equivalents

     132               132   

Cost of net debt

     (398            (398

Other financial income

     643               643   

Other financial expense

     (345            (345

Equity in income (loss) of affiliates

     1,918        (276     1,642   

Income taxes

     (7,302     (449     (7,751

Consolidated net income

     7,962        667        8,629   

Group share

     7,784        663        8,447   

Non-controlling interests

     178        4        182   

 

(a) Adjustments include special items, inventory valuation effect and equity share of adjustments related to Sanofi.

 

 

F-30


Table of Contents
D)   ADJUSTMENT ITEMS BY BUSINESS SEGMENT

The adjustment items for income as per Note 2 to the Consolidated Financial Statements are detailed as follows:

 

Adjustments to operating income
For the year ended December 31, 2011 (M)
   Upstream     Downstream     Chemicals     Corporate      Total  

Inventory valuation effect

            1,224        (9             1,215   

Effect of changes in fair value

     45                              45   

Restructuring charges

                                    

Asset impairment charges

     (75     (700     (6             (781

Other items

            (68     (24             (92

Total

     (30     456        (39             387   

 

Adjustments to net income, Group share
For the year ended December 31, 2011 (M)
   Upstream     Downstream     Chemicals     Corporate     Total  

Inventory valuation effect

            824        10               834   

Effect of changes in fair value

     32                             32   

Restructuring charges

            (113     (9            (122

Asset impairment charges

     (531     (478     (5            (1,014

Gains (losses) on disposals of assets

     843        412        209        74        1,538   

Other items

     (202     (74     (76     (64     (416

Total

     142        571        129        10        852   

 

 

Adjustments to operating income
For the year ended December 31, 2010 (M)
   Upstream     Downstream     Chemicals     Corporate      Total  

Inventory valuation effect

            863        130                993   

Restructuring charges

                                    

Asset impairment charges

     (203     (1,192     (21             (1,416

Other items

            60        (38             22   

Total

     (203     (269     71                (401

 

Adjustments to net income, Group share
For the year ended December 31, 2010 (M)
   Upstream     Downstream     Chemicals     Corporate     Total  

Inventory valuation effect

            635        113               748   

TOTAL’s equity share of adjustments related to Sanofi

                          (81     (81

Restructuring charges

            (12     (41            (53

Asset impairment charges

     (297     (913     (14            (1,224

Gains (losses) on disposals of assets

     589        122        33        302        1,046   

Other items

     (37     (83     (33            (153

Total

     255        (251     58        221        283   

 

F-31


Table of Contents

Adjustments to operating income

For the year ended December 31, 2009 (M)

   Upstream     Downstream     Chemicals     Corporate     Total  

Inventory valuation effect

            1,816        389               2,205   

Restructuring charges

                                   

Asset impairment charges

     (4     (347     (40            (391

Other items

     (17     (258     (45            (320

Total

     (21     1,211        304               1,494   
           

Adjustments to net income, Group share

For the year ended December 31, 2009 (M)

   Upstream     Downstream     Chemicals     Corporate     Total  

Inventory valuation effect

            1,279        254               1,533   

TOTAL’s equity share of adjustments related to Sanofi

                          (300     (300

Restructuring charges

            (27     (102            (129

Asset impairment charges

     (52     (253     (28            (333

Gains (losses) on disposals of assets

                          179        179   

Other items

     (112     (182     7               (287

Total

     (164     817        131        (121     663   

 

E)   ADDITIONAL INFORMATION ON IMPAIRMENTS

In the Upstream, Downstream and Chemicals segments, impairments of assets have been recognized for the year ended December 31, 2011, with an impact of 781 million in operating income and 1,014 million in net income, Group share. These impairments have been disclosed as adjustments to operating income and adjustments to net income, Group share. These items are identified in paragraph 4D above as adjustment items with the heading “Asset impairment charges”.

The impairment losses impact certain Cash Generating Units (CGU) for which there were indications of impairment, due mainly to changes in the operating conditions or the economic environment of their specific businesses.

The principles applied are the following:

 

 

the recoverable amount of CGUs has been based on their value in use, as defined in Note 1 paragraph L to the Consolidated Financial Statements “Impairment of long-lived assets”;

 

 

future cash flows have been determined with the assumptions in the long-term plan of the Group. These assumptions (including future prices of products, supply and demand for products, future production volumes) represent the best estimate by management of the Group of all economic conditions during the remaining life of assets;

 

 

future cash flows, based on the long-term plan, are prepared over a period consistent with the life of the assets within the CGU. They are prepared post-tax and include specific risks attached to CGU assets. They are discounted using an 8% post-tax discount rate, this rate being a weighted-average capital cost estimated from historical market data. This rate has been applied consistently for the years ending in 2009, 2010 and 2011.

SunPower is a CGU acquired in 2011 for which specific assumptions were applied because of its own financing and its listing on Nasdaq. Thus, future cash flows of this CGU have been discounted using a 14% post-tax discount rate, corresponding to the weighted-average capital cost of this CGU.

 

 

value in use calculated by discounting the above post-tax cash flows using an 8% post-tax discount rate is not materially different from value in use calculated by discounting pre-tax cash flows using a pre-tax discount rate determined by an iterative computation from the post-tax value in use. These pre-tax discount rates are in a range from 10% to 13% in 2011. SunPower’s pre-tax discount rate is 16%.

The CGUs of the Upstream segment affected by these impairments are oil fields, assets in solar energy and investments in associates accounted for by the equity method. For the year ended December 31, 2011, the Group has recognized impairments with an impact of 75 million in operating income and 531 million in net income, Group share. A 10% decrease in hydrocarbons prices would not lead to additional impairment losses. In 2011, impairment losses accounted for mainly include the impairment of the whole goodwill arising from the acquisition of SunPower for 383 million. Indeed, the stress on public debt markets of some European states during the second half of 2011, successive austerity plans adopted by these states and their impact on financial incentives specific to the solar industry have greatly worsened the financial situation and forecasts of future cash flows of the solar industry companies, including SunPower. The market capitalization of these companies fell sharply in 2011, thus the share price of SunPower as of December 31, 2011 stood at $6.23 per share, down 73% compared to the share price at the acquisition date.

 

 

F-32


Table of Contents

The CGUs of the Downstream segment are affiliates or groups of affiliates (or industrial assets) organized mostly by country for the refining activities and by relevant geographical area for the marketing activities. For the refining activities, the unfavorable trends observed in 2010 have continued in 2011, with a worldwide context of surplus in refining capacities compared to the demand for petroleum products. This surplus is still based in Europe with a falling demand, whereas the emerging countries (Middle East and Asia) report a strong growth in the consumption of petroleum products. In this persistent context of deteriorated margins, the refining CGUs in France and in the United Kingdom have suffered substantial operating losses despite the constant efforts to improve operations. This situation, coupled with less favorable outlooks, led the Group to recognize impairments within the CGUs Refining France and United Kingdom with an impact of 700 million in operating income and 478 million in net income, Group share. A variation of +5% of projections of gross margin in identical operating conditions would have a positive impact of 676 million in operating income and 443 million in net income, Group share. A variation of (1) % of the discount rate would have a positive impact of 335 million in operating income and 219 million in net income, Group share. Inverse variations of projections of gross margin and discount rate would have impacts of respectively

(683) million and (249) million in operating income and (448) million and (164) million in net income, Group share.

The CGUs of the Chemicals segment are worldwide business units, including activities or products with common strategic, commercial and industrial characteristics. The different scenarios of sensitivity would not lead to additional impairment losses.

For the year ended December 31, 2010, impairments of assets have been recognized in the Upstream, Downstream and Chemicals segments with an impact of 1,416 million in operating income and 1,224 million in net income, Group share. These impairments have been disclosed as adjustments to operating income and adjustments to net income, Group share.

For the year ended December 31, 2009, impairments of assets have been recognized in the Upstream, Downstream and Chemicals segments with an impact of 413 million in operating income and 382 million in net income, Group share. These impairments have been disclosed as adjustments to operating income for 391 million and adjustments to net income, Group share for 333 million.

For the years ended December 31, 2011, 2010 and 2009, no reversal of impairment has been recognized.

 

 

5) INFORMATION BY GEOGRAPHICAL AREA

 

(M)    France      Rest of
Europe
     North
America
     Africa      Rest of the
world
     Total  

For the year ended December 31, 2011

                 

Non-Group sales

     42,626         81,453         15,917         15,077         29,620         184,693   

Property, plant and equipment, intangible assets, net

     5,637         15,576         14,518         23,546         17,593         76,870   

Capital expenditures

     1,530         3,802         5,245         5,264         8,700         24,541   

For the year ended December 31, 2010

                 

Non-Group sales

     36,820         72,636         12,432         12,561         24,820         159,269   

Property, plant and equipment, intangible assets, net

     5,666         14,568         9,584         20,166         13,897         63,881   

Capital expenditures

     1,062         2,629         3,626         4,855         4,101         16,273   

For the year ended December 31, 2009

                 

Non-Group sales

     32,437         60,140         9,515         9,808         19,427         131,327   

Property, plant and equipment, intangible assets, net

     6,973         15,218         8,112         17,312         11,489         59,104   

Capital expenditures

     1,189         2,502         1,739         4,651         3,268         13,349   

6) OPERATING EXPENSES

 

For the year ended December 31, (M)    2011     2010     2009  

Purchases, net of inventory variation(a)

     (113,892 )(b)      (93,171     (71,058

Exploration costs

     (1,019     (864     (698

Other operating expenses(c)

     (19,843     (19,135     (18,591

of which non-current operating liabilities (allowances) reversals

     615        387        515   

of which current operating liabilities (allowances) reversals

     (150     (101     (43

Operating expenses

     (134,754     (113,170     (90,347

 

(a) Includes taxes paid on oil and gas production in the Upstream segment, namely royalties.

 

F-33


Table of Contents
(b) As of December 31, 2011, the Group valued under / over lifting at market value. The impact in operating expenses is 577 million and 103 million in net income, Group share as of December 31, 2011.
(c) Principally composed of production and administrative costs (see in particular the payroll costs as detailed in Note 26 to the Consolidated Financial Statements “Payroll and staff”).

 

7)   OTHER INCOME AND OTHER EXPENSE

 

For the year ended
December 31, (M)
   2011     2010     2009  

Gains (losses) on disposal of assets

     1,650        1,117        200   

Foreign exchange gains

     118                 

Other

     178        279        114   

Other income

     1,946        1,396        314   

Foreign exchange losses

                   (32

Amortization of other intangible assets (excl. mineral interests)

     (592     (267     (142

Other

     (655     (633     (426

Other expense

     (1,247     (900     (600

Other income

In 2011, gains and losses on disposal of assets are mainly related to the sale of the interest in CEPSA, to the sale of assets in the Upstream segment (especially the sale of 10% Group’s interest in the Colombian pipeline OCENSA) and to the sale of photocure and coatings resins businesses. These disposals are described in Note 3 to the Consolidated Financial Statements.

In 2010, gains and losses on disposal of assets were mainly related to sales of assets in the Upstream segment (sale of the interests in the Valhall and Hod fields in Norway and sale of the interest in Block 31 in Angola, see Note 3 to the Consolidated Financial Statements), as well as the change in the accounting treatment and the disposal of shares of Sanofi (see Note 3 to the Consolidated Financial Statements).

In 2009, gains and losses on disposal of assets were mainly related to the disposal of shares of Sanofi.

Other expense

In 2011, the heading “Other” is mainly comprised of 243 million of restructuring charges in the Upstream, Downstream and Chemicals segments.

In 2010, the heading “Other” was mainly comprised of 248 million of restructuring charges in the Downstream and Chemicals segments.

In 2009, the heading “Other” was mainly comprised of 190 million of restructuring charges in the Downstream and Chemicals segments.

8)   OTHER FINANCIAL INCOME AND EXPENSE

 

As of December 31, (M)    2011     2010     2009  

Dividend income on non-consolidated subsidiaries

     330        255        210   

Capitalized financial expenses

     171        113        117   

Other

     108        74        316   

Other financial income

     609        442        643   

Accretion of asset retirement obligations

     (344     (338     (283

Other

     (85     (69     (62

Other financial expense

     (429     (407     (345

9) INCOME TAXES

Since 1966, the Group had been taxed in accordance with the consolidated income tax treatment approved on a three-year renewable basis by the French Ministry of Economy, Finance and Industry. The approval for the period 2008-2010 expired on December 31, 2010 and TOTAL S.A. announced in July 2011 that it took the decision not to proceed with its initial application for the renewal of this agreement.

As a consequence, TOTAL S.A. is taxed in accordance with the common tax regime as from 2011. The exit of the consolidated income tax treatment has no significant impact, neither on the Group’s financial situation nor on the consolidated results.

No deferred tax is recognized for the temporary differences between the carrying amounts and tax bases of investments in foreign subsidiaries which are considered to be permanent investments. Undistributed earnings from foreign subsidiaries considered to be reinvested indefinitely amounted to 27,444 million as of December 31, 2011. The determination of the tax effect relating to such reinvested income is not practicable.

In addition, no deferred tax is recognized on unremitted earnings (approximately 22,585 million) of the Group’s French subsidiaries since the remittance of such earnings would be tax exempt for the subsidiaries in which the Company owns 95% or more of the outstanding shares.

Income taxes are detailed as follows:

 

For the year ended
December 31, (M)
   2011     2010     2009  

Current income taxes

     (12,495     (9,934     (7,213

Deferred income taxes

     (1,578     (294     (538

Total income taxes

     (14,073     (10,228     (7,751
 

 

F-34


Table of Contents

Before netting deferred tax assets and liabilities by fiscal entity, the components of deferred tax balances are as follows:

 

As of December 31, (M)    2011     2010     2009  

Net operating losses and tax carry forwards

     1,584        1,145        1,114   

Employee benefits

     621        535        517   

Other temporary non-deductible provisions

     3,521        2,757        2,184   

Gross deferred tax assets

     5,726        4,437        3,815   

Valuation allowance

     (667     (576     (484

Net deferred tax assets

     5,059        3,861        3,331   

Excess tax over book depreciation

     (12,831     (10,966     (9,791

Other temporary tax deductions

     (2,721     (1,339     (1,179

Gross deferred tax liability

     (15,552     (12,305     (10,970

Net deferred tax liability

     (10,493     (8,444     (7,639

Net operating losses and tax carry forwards only come from foreign subsidiaries.

After netting deferred tax assets and liabilities by fiscal entity, deferred taxes are presented on the balance sheet as follows:

 

As of December 31, (M)    2011     2010     2009  

Deferred tax assets, non-current (note 14)

     1,767        1,378        1,164   

Deferred tax assets, current (note 16)

            151        214   

Deferred tax liabilities, non-current

     (12,260     (9,947     (8,948

Deferred tax liabilities, current

            (26     (69

Net amount

     (10,493     (8,444     (7,639

The net deferred tax variation in the balance sheet is analyzed as follows:

 

As of December 31, (M)    2011     2010     2009  

Opening balance

     (8,444     (7,639     (6,857

Deferred tax on income

     (1,578     (294     (538

Deferred tax on shareholders’ equity(a)

     (55     28        (38

Changes in scope of consolidation

     (17     (59     (1

Currency translation adjustment

     (399     (480     (205

Closing balance

     (10,493     (8,444     (7,639

 

(a) This amount includes mainly current income taxes and deferred taxes for changes in fair value of listed securities classified as financial assets available for sale as well as deferred taxes related to the cash flow hedge (see Note 17 to the Consolidated Financial Statements).

Reconciliation between provision for income taxes and pre-tax income:

 

For the year ended December 31, (M)    2011     2010     2009  

Consolidated net income

     12,581        10,807        8,629   

Provision for income taxes

     14,073        10,228        7,751   

Pre-tax income

     26,654        21,035        16,380   

French statutory tax rate

     36.10%        34.43%        34.43%   

Theoretical tax charge

     (9,622     (7,242     (5,640

Difference between French and foreign income tax rates

     (5,740     (4,921     (3,214

Tax effect of equity in income (loss) of affiliates

     695        672        565   

Permanent differences

     889        1,375        597   

Adjustments on prior years income taxes

     (19     (45     (47

Adjustments on deferred tax related to changes in tax rates

     (201     2        (1

Changes in valuation allowance of deferred tax assets

     (71     (65     (6

Other

     (4     (4     (5

Net provision for income taxes

     (14,073     (10,228     (7,751

The French statutory tax rate includes the standard corporate tax rate (33.33%) and additional applicable taxes that bring the overall tax rate to 36.10% in 2011 (versus 34.43% in 2010 and 2009).

Permanent differences are mainly due to impairment of goodwill and to dividends from non-consolidated companies as well as the specific taxation rules applicable to certain activities.

 

F-35


Table of Contents

Net operating losses and tax credit carryforwards

Deferred tax assets related to net operating losses and tax carryforwards expire in the following years:

 

      2011      2010      2009  

As of December 31, (M)

   Basis      Tax      Basis      Tax      Basis      Tax  

2010

                                     258         126   

2011

                     225         110         170         83   

2012

     242         115         177         80         121         52   

2013

     171         81         146         59         133         43   

2014(a)

     104         47         1,807         602         1,804         599   

2015(b)

     8         2         190         62                   

2016 and after

     2,095         688                                   

Unlimited

     2,119         651         774         232         661         211   

Total

     4,739         1,584         3,319         1,145         3,147         1,114   

 

(a)

Net operating losses and tax credit carryforwards in 2014 and after for 2009.

(b)

Net operating losses and tax credit carryforwards in 2015 and after for 2010.

10) INTANGIBLE ASSETS

 

As of December 31, 2011 (M)    Cost      Amortization and
impairment
    Net  

Goodwill

     1,903         (993     910   

Proved and unproved mineral interests

     13,719         (3,181     10,538   

Other intangible assets

     3,377         (2,412     965   
Total intangible assets    18,999      (6,586)     12,413  

 

As of December 31, 2010 (M)    Cost      Amortization and
impairment
    Net  

Goodwill

     1,498         (596     902   

Proved and unproved mineral interests

     10,099         (2,712     7,387   

Other intangible assets

     2,803         (2,175     628   

Total intangible assets

     14,400         (5,483     8,917   

 

As of December 31, 2009 (M)    Cost      Amortization and
impairment
    Net  

Goodwill

     1,776         (614     1,162   

Proved and unproved mineral interests

     8,204         (2,421     5,783   

Other intangible assets

     2,712         (2,143     569   

Total intangible assets

     12,692         (5,178     7,514   

Changes in net intangible assets are analyzed in the following table:

 

(M)    Net
amount
as of
January 1,
     Acquisitions      Disposals     Amortization
and
impairment
    Currency
translation
adjustment
     Other     Net amount
as of
December 31,
 

2011

     8,917         2,504         (428     (991     358         2,053        12,413   

2010

     7,514         2,466         (62     (553     491         (939     8,917   

2009

     5,341         629         (64     (345     2         1,951        7,514   

 

In 2011, the heading “Other” mainly includes Chesapeake’s Barnett shale mineral interests reclassified into the acquisitions for (649) million, the not yet paid part of the acquisition of Chesapeake’s mineral interests in Utica for 1,216 million, the reclassification of Joslyn’s mineral interests sold in 2011 and formerly classified in accordance with IFRS 5 “Non-current assets held for sale and discontinued operations” for 384 million, and 697 million related to the acquisition of SunPower.

In 2010, the heading “Other” mainly included Chesapeake’s Barnett shale mineral interests reclassified

into the acquisitions for (975) million and the reclassification of Joslyn’s mineral interests in accordance with IFRS 5 “Non-current assets held for sale and discontinued operations” for (390) million, including the currency translation adjustment, partially compensated by the acquisition of UTS for 646 million (see Note 3 to the Consolidated Financial Statements).

In 2009, the heading “Other” mainly included Chesapeake’s Barnett shale mineral interests for 1,449 million (see Note 3 to the Consolidated Financial Statements).

 

 

F-36


Table of Contents

A summary of changes in the carrying amount of goodwill by business segment for the year ended December 31, 2011 is as follows:

 

(M)    Net goodwill as of
January 1, 2011
     Increases      Impairments     Other     Net goodwill as of
December 31, 2011
 

Upstream

     78         396         (383     (2     89   

Downstream

     82                 (1     (12     69   

Chemicals

     717         23         (4     (9     727   

Corporate

     25                               25   

Total

     902         419         (388     (23     910   

In 2011, impairments of goodwill in the Upstream segment amount to 383 million and correspond to the impairment of the whole goodwill arising from the acquisition of SunPower (see Note 4E to the Consolidated Financial Statements).

11) PROPERTY, PLANT AND EQUIPMENT

 

As of December 31, 2011 (M)    Cost      Depreciation and
impairment
    Net  

Upstream properties

       

Proved properties

     84,222         (54,589     29,633   

Unproved properties

     209                209   

Work in progress

     21,190         (15     21,175   

Subtotal

     105,621         (54,604     51,017   

Other property, plant and equipment

       

Land

     1,346         (398     948   

Machinery, plant and equipment (including transportation equipment)

     25,838         (18,349     7,489   

Buildings

     6,241         (4,131     2,110   

Work in progress

     1,534         (306     1,228   

Other

     6,564         (4,899     1,665   

Subtotal

     41,523         (28,083     13,440   

Total property, plant and equipment

     147,144         (82,687     64,457   

 

As of December 31, 2010 (M)    Cost      Depreciation and
impairment
    Net  

Upstream properties

       

Proved properties

     77,183         (50,582     26,601   

Unproved properties

     347         (1     346   

Work in progress

     14,712         (37     14,675   

Subtotal

     92,242         (50,620     41,622   

Other property, plant and equipment

       

Land

     1,304         (393     911   

Machinery, plant and equipment (including transportation equipment)

     23,831         (17,010     6,821   

Buildings

     6,029         (3,758     2,271   

Work in progress

     2,350         (488     1,862   

Other

     6,164         (4,687     1,477   

Subtotal

     39,678         (26,336     13,342   

Total property, plant and equipment

     131,920         (76,956     54,964   

 

F-37


Table of Contents
As of December 31, 2009 (M)    Cost      Depreciation and
impairment
    Net  

Upstream properties

       

Proved properties

     71,082         (44,718     26,364   

Unproved properties

     182         (1     181   

Work in progress

     10,351         (51     10,300   

Subtotal

     81,615         (44,770     36,845   

Other property, plant and equipment

       

Land

     1,458         (435     1,023   

Machinery, plant and equipment (including transportation equipment)

     22,927         (15,900     7,027   

Buildings

     6,142         (3,707     2,435   

Work in progress

     2,774         (155     2,619   

Other

     6,506         (4,865     1,641   

Subtotal

     39,807         (25,062     14,745   

Total property, plant and equipment

     121,422         (69,832     51,590   

Changes in net property, plant and equipment are analyzed in the following table:

 

(M)    Net amount as
of January 1,
     Acquisitions      Disposals     Depreciation and
impairment
    Currency
translation
adjustment
     Other     Net amount as of
December 31,
 

2011

     54,964         15,443         (1,489     (7,636     1,692         1,483        64,457   

2010

     51,590         11,346         (1,269     (8,564     2,974         (1,113     54,964   

2009

     46,142         11,212         (65     (6,765     397         669        51,590   

 

In 2011, the heading “Disposals” mainly includes the impact of sales of assets in the Upstream segment (disposal of the interests in Gassled in Norway and in Joslyn’s field in Canada) and in the Downstream segment (disposal of Marketing assets in the United Kingdom) (see Note 3 to the Consolidated Financial Statements).

In 2011, the heading “Depreciation and impairment” includes the impact of impairments of assets recognized for 781 million (see Note 4D to the Consolidated Financial Statements).

In 2011, the heading “Other” corresponds to the increase of the asset for sites restitution for an amount of 653 million. It also includes 428 million related to the reclassification of tangible assets of Joslyn and resins businesses sold in 2011 and formerly classified in accordance with IFRS 5 “Non-current assets held for sale and discontinued operations”.

In 2010, the heading “Disposals” mainly included the impact of sales of assets in the Upstream segment (sale of

the interests in the Valhall and Hod fields in Norway and sale of the interest in Block 31 in Angola, see Note 3 to the Consolidated Financial Statements).

In 2010, the heading “Depreciation and impairment” included the impact of impairments of assets recognized for 1,416 million (see Note 4D to the Consolidated Financial Statements).

In 2010, the heading “Other” mainly corresponded to the change in the consolidation method of Samsung Total Petrochemicals (see Note 12 to the Consolidated Financial Statements) for (541) million and the reclassification for (537) million, including the currency translation adjustment, of property, plant and equipment related to Joslyn, Total E&P Cameroun, and resins businesses subject to a disposal project in accordance with IFRS 5 “Non-current assets held for sale and discontinued operations”, partially compensated by the acquisition of UTS for 217 million (see Note 3 to the Consolidated Financial Statements).

 

 

F-38


Table of Contents

In 2009, the heading “Other” mainly included changes in net property, plant and equipment related to asset retirement obligations and Chesapeake’s Barnett shale tangible assets for 113 million (see Note 3 to the Consolidated Financial Statements).

Property, plant and equipment presented above include the following amounts for facilities and equipment under finance leases that have been capitalized:

 

As of December 31, 2011 (M)    Cost      Depreciation and
impairment
    Net  

Machinery, plant and equipment

     414         (284     130   

Buildings

     54         (25     29   

Other

                      

Total

     468         (309     159   
As of December 31, 2010 (M)    Cost      Depreciation and
impairment
    Net  

Machinery, plant and equipment

     480         (332     148   

Buildings

     54         (24     30   

Other

                      

Total

     534         (356     178   
As of December 31, 2009 (M)    Cost      Depreciation and
impairment
    Net  

Machinery, plant and equipment

     548         (343     205   

Buildings

     60         (30     30   

Other

                      

Total

     608         (373     235   

 

F-39


Table of Contents

12) EQUITY AFFILIATES: INVESTMENTS AND LOANS

 

             As of December 31,  

Equity value (M)

 

   2011     2010     2009     2011      2010      2009  
   % owned     equity value  

NLNG

     15.00     15.00     15.00     953         1,108         1,136   

PetroCedeño — EM

     30.32     30.32     30.32     1,233         1,136         874   

CEPSA (Upstream share)(d)

            48.83     48.83             340         385   

Angola LNG Ltd.

     13.60     13.60     13.60     869         710         490   

Qatargas

     10.00     10.00     10.00     97         85         83   

Société du Terminal Méthanier de Fos Cavaou

     27.60     28.03     28.79     119         125         124   

Dolphin Energy Ltd (Del) Abu Dhabi

     24.50     24.50     24.50     208         172         118   

Qatar Liquefied Gas Company Limited II (Train B)

     16.70     16.70     16.70     209         184         143   

Yemen LNG Co

     39.62     39.62     39.62     169         25         (15

Shtokman Development AG

     25.00     25.00     25.00     248         214         162   

AMYRIS(a)

     21.37     22.03            79         101           

Novatek(e)

     14.09                   3,368                   

Other

                          803         724         760   

Total associates

           8,355         4,924         4,260   

Yamal LNG(e)

     20.01                   495                   

Ichthys LNG Ltd(e)

     24.00                   82                   

Other

                                  78           

Total jointly-controlled entities

                             577         78           

Total Upstream

           8,932         5,002         4,260   

CEPSA (Downstream share)(d)

            48.83     48.83             2,151         1,927   

Saudi Aramco Total Refining & Petrochemicals (Downstream share)

     37.50     37.50     37.50     112         47         60   

Other

                          166         159         123   

Total associates

           278         2,357         2,110   

SARA(c)

     50.00     50.00            125         134           

TotalErg(a)

     49.00     49.00            296         289           

Other

                                  2           

Total jointly-controlled entities

                             421         425           

Total Downstream

           699         2,782         2,110   

CEPSA (Chemicals share)(d)

            48.83     48.83             411         396   

Qatar Petrochemical Company Ltd.

     20.00     20.00     20.00     240         221         205   

Saudi Aramco Total Refining & Petrochemicals (Chemicals share)

     37.50     37.50     37.50     9         4         5   

Qatofin Company Limited

     36.36     36.36     36.36     136         27         9   

Other

                          27         41         37   

Total associates

           412         704         652   

Samsung Total Petrochemicals(c)

     50.00     50.00            706         645           

Total jointly-controlled entities

                             706         645           

Total Chemicals

           1,118         1,349         652   

Sanofi(b)

                   7.39                     4,235   

Total associates

                           4,235   

Total jointly-controlled entities

                                               

Total Corporate

                                             4,235   

Total investments

           10,749         9,133         11,257   

Loans

                             2,246         2,383         2,367   

Total investments and loans

                             12,995         11,516         13,624   

 

(a) Investment accounted for by the equity method as from 2010.
(b)

End of the accounting for by the equity method of Sanofi as of July 1st, 2010 (see Note 3 to the Consolidated Financial Statements).

(c)

Change in the consolidation method as of January 1st, 2010.

(d)

Sale of CEPSA on July 29th, 2011.

(e) Investment accounted for by the equity method as from 2011.

 

F-40


Table of Contents
      As of December 31,     For the year ended December 31,  
      2011     2010     2009     2011     2010     2009  
Equity in income (loss) (M)    % owned     Equity in income (loss)  

NLNG

     15.00     15.00     15.00     374        207        227   

PetroCedeño — EM

     30.32     30.32     30.32     55        195        166   

CEPSA (Upstream share)(d)

            48.83     48.83     15        57        23   

Angola LNG Ltd.

     13.60     13.60     13.60     6        8        9   

Qatargas

     10.00     10.00     10.00     196        136        114   

Société du Terminal Méthanier de Fos Cavaou

     27.60     28.03     28.79     13                 

Dolphin Energy Ltd (Del) Abu Dhabi

     24.50     24.50     24.50     131        121        94   

Qatar Liquefied Gas Company Limited II (Train B)

     16.70     16.70     16.70     446        288        8   

Yemen LNG Co

     39.62     39.62     39.62     130        37        34   

Shtokman Development AG

     25.00     25.00     25.00     1        (5     4   

AMYRIS(a)

     21.37     22.03            (23     (3       

Novatek(e)

     14.09                   24                 

Other

                          274        140        180   

Total associates

           1,642        1,181        859   

Yamal LNG(e)

     20.01                                   

Ichthys LNG Ltd(e)

     24.00                   (7              

Other

                          (56     6          

Total jointly-controlled entities

                             (63     6          

Total Upstream

           1,579        1,187        859   

CEPSA (Downstream share)(d)

            48.83     48.83     26        172        149   

Saudi Aramco Total Refining & Petrochemicals (Downstream share)

     37.50     37.50     37.50     (27     (19     (12

Other

                          24        76        81   

Total associates

           23        229        218   

SARA(c)

     50.00     50.00            11        31          

TotalErg(a)

     49.00     49.00            7        (11       

Other

                          1        2          

Total jointly-controlled entities

                             19        22          

Total Downstream

           42        251        218   

CEPSA (Chemicals share)(d)

            48.83     48.83     19        78        10   

Qatar Petrochemical Company Ltd.

     20.00     20.00     20.00     89        84        74   

Saudi Aramco Total Refining & Petrochemicals (Chemicals share)

     37.50     37.50     37.50     (3     (1     (1

Qatofin Company Limited

     36.36     36.36     36.36     98        36        (5

Other

                          (13     5        1   

Total associates

           190        202        79   

Samsung Total Petrochemicals(c)

     50.00     50.00            114        104          

Total jointly-controlled entities

                             114        104          

Total Chemicals

           304        306        79   

Sanofi(b)

                   7.39            209        486   

Total associates

                  209        486   

Total jointly-controlled entities

                                             

Total Corporate

                                    209        486   

Total investments

                             1,925        1,953        1,642   

 

(a) Investment accounted for by the equity method as from 2010.
(b)

End of the accounting for by the equity method of Sanofi as of July 1st, 2010 (see Note 3 to the Consolidated Financial Statements).

(c)

Change in the consolidation method as of January 1st, 2010.

(d)

Sale of CEPSA on July 29th, 2011.

(e) Investment accounted for by the equity method as from 2011.

The market value of the Group’s share in Novatek amounts to 4,034 million as of December 31, 2011 for an equity value of 3,368 million.

 

F-41


Table of Contents

In Group share, the main financial items of the equity affiliates are as follows:

 

As of December 31,

(M)

   2011     2010     2009  

  

   Associates     Jointly-
controlled
entities
    Associates     Jointly-
controlled
entities
    Associates     Jointly-
controlled
entities
 

Assets

     18,088        3,679        19,192        2,770        22,681          

Shareholders’ equity

     9,045        1,704        7,985        1,148        11,257          

Liabilities

     9,043        1,975        11,207        1,622        11,424          
                                                  
      2011     2010     2009  
For the year ended December 31, (M)    Associates     Jointly-
controlled
entities
    Associates     Jointly-
controlled
entities
    Associates     Jointly-
controlled
entities
 

Revenues from sales

     9,948        5,631        16,529        2,575        14,434          

Pre-tax income

     2,449        119        2,389        166        2,168          

Income tax

     (594     (49     (568     (34     (526       

Net income

     1,855        70        1,821        132        1,642           

13) OTHER INVESTMENTS

The investments detailed below are classified as “Financial assets available for sale” (see Note 1 paragraph M(ii) to the Consolidated Financial Statements).

 

As of December 31, 2011

(M)

   Carrying
amount
     Unrealized gain (loss)     Balance sheet value  

Sanofi(a)

     2,100         351        2,451   

Areva(b)

     69         1        70   

Arkema

                      

Chicago Mercantile Exchange Group

     1         6        7   

Olympia Energy Fund — energy investment fund

     38         (5     33   

Gevo

     15         (3     12   

Other publicly traded equity securities

     3         (1     2   

Total publicly traded equity securities(c)

     2,226         349        2,575   

BBPP

     62                62   

Ocensa(d)

     85                85   

BTC Limited

     132                132   

Other equity securities

     820                820   

Total other equity securities(c)

     1,099                1,099   

Other investments

     3,325         349        3,674   
                           

As of December 31, 2010

(M)

   Carrying
amount
     Unrealized gain (loss)     Balance sheet value  

Sanofi(a)

     3,510         (56     3,454   

Areva(b)

     69         63        132   

Arkema

                      

Chicago Mercantile Exchange Group

     1         9        10   

Olympia Energy Fund — energy investment fund

     37         (3     34   

Other publicly traded equity securities

     2         (1     1   

Total publicly traded equity securities(c)

     3,619         12        3,631   

BBPP

     60                60   

BTC Limited

     141                141   

Other equity securities

     758                758   

Total other equity securities(c)

     959                959   

Other investments

     4,578         12        4,590   

 

F-42


Table of Contents

As of December 31, 2009

(M)

   Carrying
amount
     Unrealized gain (loss)     Balance sheet value  

Areva(b)

     69         58        127   

Arkema

     15         47        62   

Chicago Mercantile Exchange Group

     1         9        10   

Olympia Energy Fund — energy investment fund

     35         (2     33   

Other publicly traded equity securities

                      

Total publicly traded equity securities(c)

     120         112        232   

BBPP

     72                72   

BTC Limited

     144                144   

Other equity securities

     714                714   

Total other equity securities(c)

     930                930   

Other investments

     1,050         112        1,162   

 

(a) End of the accounting for by the equity method of Sanofi as of July 1st, 2010 (see Note 3 to the Consolidated Financial Statements).
(b) Unrealized gain based on the investment certificate.
(c) Including cumulative impairments of 604 million in 2011, 597 million in 2010 and 599 million in 2009.
(d) End of the accounting for by the equity method of Ocensa in July 2011 (see Note 3 to the Consolidated Financial Statements).

14) OTHER NON-CURRENT ASSETS

 

As of December 31, 2011

(M)

   Gross value      Valuation
allowance
    Net value  

Deferred income tax assets

     1,767                1,767   

Loans and advances(a)

     2,454         (399     2,055   

Other

     1,049                1,049   

Total

     5,270         (399     4,871   

 

As of December 31, 2010

(M)

   Gross value      Valuation
allowance
    Net value  

Deferred income tax assets

     1,378                1,378   

Loans and advances(a)

     2,060         (464     1,596   

Other

     681                681   

Total

     4,119         (464     3,655   

 

As of December 31, 2009

(M)

   Gross value      Valuation
allowance
    Net value  

Deferred income tax assets

     1,164                1,164   

Loans and advances(a)

     1,871         (587     1,284   

Other

     633                633   

Total

     3,668         (587     3,081   

 

(a) Excluding loans to equity affiliates.

Changes in the valuation allowance on loans and advances are detailed as follows:

 

For the year ended December 31,

(M)

   Valuation
allowance as
of January 1,
    Increases     Decreases      Currency
translation
adjustment and
other variations
    Valuation
allowance as of
December 31,
 

2011

     (464     (25     122         (32     (399

2010

     (587     (33     220         (64     (464

2009

     (529     (19     29         (68     (587

15) INVENTORIES

 

As of December 31, 2011

(M)

   Gross value      Valuation
allowance
    Net value  

Crude oil and natural gas

     4,735         (24     4,711   

Refined products

     9,706         (36     9,670   

Chemicals products

     1,489         (103     1,386   

Other inventories

     2,761         (406     2,355   

Total

     18,691         (569     18,122   

 

F-43


Table of Contents
As of December 31, 2010 (M)    Gross value      Valuation
allowance
    Net value  

Crude oil and natural gas

     4,990                4,990   

Refined products

     7,794         (28     7,766   

Chemicals products

     1,350         (99     1,251   

Other inventories

     1,911         (318     1,593   

Total

     16,045         (445     15,600   

 

As of December 31, 2009 (M)    Gross value      Valuation
allowance
    Net value  

Crude oil and natural gas

     4,581                4,581   

Refined products

     6,647         (18     6,629   

Chemicals products

     1,234         (113     1,121   

Other inventories

     1,822         (286     1,536   

Total

     14,284         (417     13,867   

Changes in the valuation allowance on inventories are as follows:

 

For the year ended December 31, (M)    Valuation
allowance as
of January 1,
    Increase (net)     Currency
translation
adjustment and
other variations
    Valuation
allowance as of
December 31,
 

2011

     (445     (83     (41     (569

2010

     (417     (39     11        (445

2009

     (1,115     700        (2     (417

16) ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS

 

As of December 31, 2011 (M)    Gross
value
     Valuation
allowance
    Net
value
 

Accounts receivable

     20,532         (483     20,049   

Recoverable taxes

     2,398                2,398   

Other operating receivables

     7,750         (283     7,467   

Deferred income tax

                      

Prepaid expenses

     840                840   

Other current assets

     62                62   

Other current assets

     11,050         (283     10,767   

 

As of December 31, 2010 (M)    Gross
value
     Valuation
allowance
    Net
value
 

Accounts receivable

     18,635         (476     18,159   

Recoverable taxes

     2,227                2,227   

Other operating receivables

     4,543         (136     4,407   

Deferred income tax

     151                151   

Prepaid expenses

     657                657   

Other current assets

     41                41   

Other current assets

     7,619         (136     7,483   

 

As of December 31, 2009 (M)    Gross
value
     Valuation
allowance
    Net
value
 

Accounts receivable

     16,187         (468     15,719   

Recoverable taxes

     2,156                2,156   

Other operating receivables

     5,214         (69     5,145   

Deferred income tax

     214                214   

Prepaid expenses

     638                638   

Other current assets

     45                45   

Other current assets

     8,267         (69     8,198   

 

F-44


Table of Contents

Changes in the valuation allowance on “Accounts receivable” and “Other current assets” are as follows:

 

(M)    Valuation
allowance
as of
January 1,
    Increase
(net)
    Currency
translation
adjustments
and other
variations
    Valuation
allowance as of
December 31,
 

Accounts receivable

        

2011

     (476     4        (11     (483

2010

     (468     (31     23        (476

2009

     (460     (17     9        (468

Other current assets

        

2011

     (136     (132     (15     (283

2010

     (69     (66     (1     (136

2009

     (19     (14     (36     (69

 

As of December 31, 2011, the net portion of the overdue receivables includes in “Accounts receivable” and “Other current assets” is 3,556 million, of which 1,857 million has expired for less than 90 days, 365 million has expired between 90 days and 6 months, 746 million has expired between 6 and 12 months and 588 million has expired for more than 12 months.

As of December 31, 2010, the net portion of the overdue receivables includes in “Accounts receivable” and “Other current assets” is 3,141 million, of which 1,885 million has expired for less than 90 days, 292 million has expired between 90 days and 6 months, 299 million has expired between 6 and 12 months and 665 million has expired for more than 12 months.

As of December 31, 2009, the net portion of the overdue receivables included in “Accounts receivable” and “Other current assets” is 3,610 million, of which 2,116 million has expired for less than 90 days, 486 million has expired between 90 days and 6 months, 246 million has expired between 6 and 12 months and 762 million has expired for more than 12 months.

17) SHAREHOLDERS’ EQUITY

Number of TOTAL shares

The Company’s common shares, par value 2.50, as of December 31, 2011 are the only category of shares. Shares may be held in either bearer or registered form.

Double voting rights are granted to holders of shares that are fully-paid and held in the name of the same shareholder for at least two years, with due consideration for the total portion of the share capital represented. Double voting rights are also assigned to restricted shares in the event of an increase in share capital by incorporation of reserves, profits or premiums based on shares already held that are entitled to double voting rights.

Pursuant to the Company’s bylaws (Statuts), no shareholder may cast a vote at a shareholders’ meeting, either by himself or through an agent, representing more than 10% of the total voting rights for the Company’s shares. This limit applies to the aggregated amount of voting rights held directly, indirectly or through voting proxies. However, in the case of double voting rights, this limit may be extended to 20%.

These restrictions no longer apply if any individual or entity, acting alone or in concert, acquires at least two-thirds of the total share capital of the Company, directly or indirectly, following a public tender offer for all of the Company’s shares.

The authorized share capital amounts to 3,446,401,650 shares as of December 31, 2011 compared to 3,439,391,697 shares as of December 31, 2010 and 3,381,921,458 as of December 31, 2009.

 

 

F-45


Table of Contents

Variation of the share capital

 

As of January 1, 2009

          2,371,808,074   

Shares issued in connection with:

   Exercise of TOTAL share subscription options      934,780   
   Exchange guarantee offered to the beneficiaries of Elf Aquitaine share subscription options      480,030   

Cancellation of shares(a)

          (24,800,000

As of January 1, 2010

          2,348,422,884   

Shares issued in connection with:

   Exercise of TOTAL share subscription options      1,218,047   

As of January 1, 2011

          2,349,640,931   

Shares issued in connection with:

   Capital increase reserved for employees      8,902,717   
     Exercise of TOTAL share subscription options      5,223,665   

As of December 31, 2011(b)

          2,363,767,313   

 

(a) Decided by the Board of Directors on July 30, 2009.
(b) Including 109,554,173 treasury shares deducted from consolidated shareholders’ equity.

The variation of both weighted-average number of shares and weighted-average number of diluted shares respectively used in the calculation of earnings per share and fully-diluted earnings per share is detailed as follows:

 

      2011     2010     2009  

Number of shares as of January 1,

     2,349,640,931        2,348,422,884        2,371,808,074   

Number of shares issued during the year (pro rated)

           

Exercise of TOTAL share subscription options

     3,412,123        412,114        221,393   

Exercise of TOTAL share purchase options

            984,800        93,827   

Exchange guarantee offered to the beneficiaries of Elf Aquitaine share subscription options

                   393,623   

TOTAL performance shares

     978,503        416,420        1,164,389   

Global free TOTAL share plan(a)

     506        15          

Capital increase reserved for employees

     5,935,145                 

TOTAL shares held by TOTAL S.A. or by its subsidiaries and deducted from shareholders’ equity

     (112,487,679     (115,407,190     (143,082,095

Weighted-average number of shares

     2,247,479,529        2,234,829,043        2,230,599,211   

Dilutive effect

           

TOTAL share subscription and purchase options

     470,095        1,758,006        1,711,961   

TOTAL performance shares

     6,174,808        6,031,963        4,920,599   

Global free TOTAL share plan(a)

     2,523,233        1,504,071     

Exchange guarantee offered to the beneficiaries of Elf Aquitaine share subscription options

                   60,428   

Capital increase reserved for employees

     303,738        371,493          

Weighted-average number of diluted shares

     2,256,951,403        2,244,494,576        2,237,292,199   

 

(a) The Board of Directors approved on May 21, 2010 the implementation and conditions of a global free share plan intended for the Group employees.

 

Capital increase reserved for Group employees

At the shareholders’ meeting held on May 21, 2010, the shareholders delegated to the Board of Directors the authority to increase the share capital of the Company in one or more transactions and within a maximum period of 26 months from the date of the meeting, by an amount not exceeding 1.5% of the share capital outstanding on the date of the meeting of the Board of Directors at which a decision to proceed with an issuance is made reserving subscriptions for such issuance to the Group employees participating in a company savings plan. It is being specified that the amount of any such capital increase reserved for Group employees was counted against the

aggregate maximum nominal amount of share capital increases authorized by the shareholders’ meeting held on May 21, 2010 for issuing new ordinary shares or other securities granting immediate or future access to the Company’s share capital with preferential subscription rights (2.5 billion in nominal value).

Pursuant to this delegation of authorization, the Board of Directors, during its October 28, 2010 meeting, decided to proceed with a capital increase reserved for employees in 2011 within the limit of 12 million shares with dividend rights as of January 1, 2010 and delegated to the Chairman and Chief Executive Officer all powers to determine the opening and closing of the subscription period and the subscription price.

 

 

F-46


Table of Contents

On March 14, 2011, the Chairman and Chief Executive Officer decided that the subscription period would be set from March 16, 2011 to April 1, 2011 included, and acknowledged that the subscription price per ordinary share would be set at 34.80. With respect to this capital increase, 8,902,717 TOTAL shares were subscribed and created on April 28, 2011.

Share cancellation

Pursuant to the authorization granted by the shareholders’ meeting held on May 11, 2007 authorizing reduction of capital by cancellation of shares held by the Company within the limit of 10% of the outstanding capital every 24 months, the Board of Directors decided on July 30, 2009 to cancel 24,800,000 shares acquired in 2008 at an average price of 49.28 per share.

Treasury shares (TOTAL shares held by TOTAL S.A.)

As of December 31, 2011, TOTAL S.A. holds 9,222,905 of its own shares, representing 0.39% of its share capital, detailed as follows:

 

 

6,712,528 shares allocated to TOTAL share grant plans for Group employees;

 

 

2,510,377 shares intended to be allocated to new TOTAL share purchase option plans or to new share grant plans.

These shares are deducted from the consolidated shareholders’ equity.

As of December 31, 2010, TOTAL S.A. held 12,156,411 of its own shares, representing 0.52% of its share capital, detailed as follows:

 

 

6,012,460 shares allocated to TOTAL share grant plans for Group employees;

 

 

6,143,951 shares intended to be allocated to new TOTAL share purchase option plans or to new share grant plans.

These shares were deducted from the consolidated shareholders’ equity.

As of December 31, 2009, TOTAL S.A. held 15,075,922 of its own shares, representing 0.64% of its share capital, detailed as follows:

 

 

6,017,499 shares allocated to covering TOTAL share purchase option plans for Group employees and executive officers;

 

 

5,799,400 shares allocated to TOTAL share grant plans for Group employees; and

 

3,259,023 shares intended to be allocated to new TOTAL share purchase option plans or to new share grant plans.

These shares were deducted from the consolidated shareholders’ equity.

TOTAL shares held by Group subsidiaries

As of December 31, 2011, 2010 and 2009, TOTAL S.A. held indirectly through its subsidiaries 100,331,268 of its own shares, representing 4.24% of its share capital as of December 31, 2011, 4.27% of its share capital as of December 31, 2010 and 4.27% of its share capital as of December 31, 2009 detailed as follows:

 

 

2,023,672 shares held by a consolidated subsidiary, Total Nucléaire, 100% indirectly controlled by TOTAL S.A.; and

 

 

98,307,596 shares held by subsidiaries of Elf Aquitaine (Financière Valorgest, Sogapar and Fingestval), 100% indirectly controlled by TOTAL S.A.

These shares are deducted from the consolidated shareholders’ equity.

Dividend

TOTAL S.A. paid on May 26, 2011 the balance of the dividend of 1.14 per share for the 2010 fiscal year (the ex-dividend date was May 23, 2011). In addition, TOTAL S.A. paid two quarterly interim dividends for the fiscal year 2011:

 

 

The first quarterly interim dividend of 0.57 per share for the fiscal year 2011, decided by the Board of Directors on April 28, 2011, was paid on September 22, 2011 (the ex-dividend date was September 19, 2011);

 

 

The second quarterly interim dividend of 0.57 per share for the fiscal year 2011, decided by the Board of Directors on July 28, 2011, was paid on December 22, 2011 (the ex-dividend date was December 19, 2011).

The Board of Directors, during its October 27, 2011 meeting, decided to set the third quarterly interim dividend for the fiscal year 2011 at 0.57 per share. This interim dividend will be paid on March 22, 2012 (the ex-dividend date will be March 19, 2012).

A resolution will be submitted at the shareholders’ meeting on May 11, 2012 to pay a dividend of 2.28 per share for the 2011 fiscal year, i.e. a balance of 0.57 per share to be distributed after deducting the three quarterly interim dividends of 0.57 per share that will have already been paid.

 

 

F-47


Table of Contents

Paid-in surplus

In accordance with French law, the paid-in surplus corresponds to share premiums of the parent company which can be capitalized or used to offset losses if the legal reserve has reached its minimum required level. The amount of the paid-in surplus may also be distributed subject to taxation unless the unrestricted reserves of the parent company are distributed prior to this item.

As of December 31, 2011, paid-in surplus amounted to 27,655 million (27,208 million as of December 31, 2010 and 27,171 million as of December 31, 2009).

Reserves

Under French law, 5% of net income must be transferred to the legal reserve until the legal reserve reaches 10% of the nominal value of the share capital. This reserve cannot be distributed to the shareholders other than upon liquidation but can be used to offset losses.

If wholly distributed, the unrestricted reserves of the parent company would be taxed for an approximate amount of 539 million as of December 31, 2011 (514 million as of December 31, 2010 and as of December 31, 2009).

 

 

Other comprehensive income

Detail of other comprehensive income showing items reclassified from equity to net income is presented in the table below:

 

For the year ended December 31, (M)    2011     2010     2009  

Currency translation adjustment

       1,498          2,231          (244

— Unrealized gain/(loss) of the period

     1,435          2,234          (243  

— Less gain/(loss) included in net income

     (63             3                1           

Available for sale financial assets

       337          (100       38   

— Unrealized gain/(loss) of the period

     382          (50       38     

— Less gain/(loss) included in net income

     45                50                          

Cash flow hedge

       (84       (80       128   

— Unrealized gain/(loss) of the period

     (131       (195       349     

— Less gain/(loss) included in net income

     (47             (115             221           

Share of other comprehensive income of equity affiliates, net amount

             (15             302                234   

Other

       (2       (7       (5

— Unrealized gain/(loss) of the period

     (2       (7       (5  

— Less gain/(loss) included in net income

                                             

Tax effect

             (55             28                (38

Total other comprehensive income, net amount

             1,679                2,374                113   

Tax effects relating to each component of other comprehensive income are as follows:

 

      2011     2010     2009  

For the year ended
December 31, (M)

   Pre-tax
amount
    Tax
effect
    Net
amount
    Pre-tax
amount
    Tax
effect
     Net
amount
    Pre-tax
amount
    Tax
effect
    Net
amount
 

Currency translation adjustment

     1,498               1,498        2,231                2,231        (244            (244

Available for sale financial assets

     337        (93     244        (100     2         (98     38        4        42   

Cash flow hedge

     (84     38        (46     (80     26         (54     128        (42     86   

Share of other comprehensive income of equity affiliates, net amount

     (15            (15     302                302        234               234   

Other

     (2            (2     (7             (7     (5            (5

Total other comprehensive income

     1,734        (55     1,679        2,346        28         2,374        151        (38     113   

18) EMPLOYEE BENEFITS OBLIGATIONS

Liabilities for employee benefits obligations consist of the following:

 

As of December 31, (M)    2011      2010      2009  

Pension benefits liabilities

     1,268         1,268         1,236   

Other benefits liabilities

     620         605         592   

Restructuring reserves (early retirement plans)

     344         298         212   

Total

     2,232         2,171         2,040   

 

F-48


Table of Contents

The Group’s main defined benefit pension plans are located in France, in the United Kingdom, in the United States, in Belgium and in Germany. Their main characteristics are the following:

 

 

The benefits are usually based on the final salary and seniority;

 

 

They are usually funded (pension fund or insurer); and

 

They are closed to new employees who benefit from defined contribution pension plans.

The pension benefits include also termination indemnities and early retirement benefits.

The other benefits are the employer contribution to post-employment medical care.

 

 

The fair value of the defined benefit obligation and plan assets in the Consolidated Financial Statements is detailed as follows:

 

      Pension benefits     Other benefits  
As of December 31, (M)    2011     2010     2009     2011     2010     2009  

Change in benefit obligation

            

Benefit obligation at beginning of year

     8,740        8,169        7,405        623        547        544   

Service cost

     163        159        134        13        11        10   

Interest cost

     420        441        428        28        29        30   

Curtailments

     (24     (4     (5     (1     (3     (1

Settlements

     (111     (60     (3                     

Special termination benefits

                                 1          

Plan participants’ contributions

     9        11        10                        

Benefits paid

     (451     (471     (484     (34     (33     (33

Plan amendments

     33        28        118        4        1        (2

Actuarial losses (gains)

     435        330        446        (9     57          

Foreign currency translation and other

     108        137        120        4        13        (1

Benefit obligation at year-end

     9,322        8,740        8,169        628        623        547   

Change in fair value of plan assets

            

Fair value of plan assets at beginning of year

     (6,809     (6,286     (5,764                     

Expected return on plan assets

     (385     (396     (343                     

Actuarial losses (gains)

     155        (163     (317                     

Settlements

     80        56        2                        

Plan participants’ contributions

     (9     (11     (10                     

Employer contributions

     (347     (269     (126                     

Benefits paid

     386        394        396                        

Foreign currency translation and other

     (99     (134     (124                     

Fair value of plan assets at year-end

     (7,028     (6,809     (6,286                     

Unfunded status

     2,294        1,931        1,883        628        623        547   

Unrecognized prior service cost

     (78     (105     (153     9        10        15   

Unrecognized actuarial (losses) gains

     (1,713     (1,170     (1,045     (17     (28     30   

Asset ceiling

     10        9        9                        

Net recognized amount

     513        665        694        620        605        592   

Pension benefits and other benefits liabilities

     1,268        1,268        1,236        620        605        592   

Other non-current assets

     (755     (603     (542                     

As of December 31, 2011, the fair value of pension benefits and other pension benefits which are entirely or partially funded amounts to 8,277 million and the present value of the unfunded benefits amounts to 1,673 million (against 7,727 million and 1,636 million respectively as of December 31, 2010 and 7,206 million and 1,510 million respectively as of December 31, 2009).

 

F-49


Table of Contents

The experience actuarial (gains) losses related to the defined benefit obligation and the fair value of plan assets are as follows:

 

For the year ended December 31, (M)    2011     2010     2009     2008      2007  

Experience actuarial (gains) losses related to the defined benefit obligation

     (58     (54     (108     12         80   

Experience actuarial (gains) losses related to the fair value of plan assets

     155        (163     (317     1,099         140   

 

As of December 31, (M)    2011     2010     2009     2008     2007  

Pension benefits

          

Benefit obligation

     9,322        8,740        8,169        7,405        8,129   

Fair value of plan assets

     (7,028     (6,809     (6,286     (5,764     (6,604

Unfunded status

     2,294        1,931        1,883        1,641        1,525   

Other benefits

          

Benefits obligation

     628        623        547        544        583   

Fair value of plan assets

                                   

Unfunded status

     628        623        547        544        583   

The Group expects to contribute 182 million to its pension plans in 2012.

 

Estimated future payments (M)    Pension benefits      Other benefits  

2012

     479         35   

2013

     467         35   

2014

     505         35   

2015

     511         35   

2016

     512         37   

2017-2021

     2,767         191   

 

Asset allocation    Pension benefits  
As of December 31,    2011     2010     2009  

Equity securities

     29     34     31%   

Debt securities

     64     60     62%   

Monetary

     4     3     3%   

Real estate

     3     3     4%   

The Group’s assumptions of expected returns on assets are built up by asset class and by country based on long-term bond yields and risk premiums.

The discount rate retained corresponds to the rate of prime corporate bonds according to a benchmark per country of different market data on the closing date.

 

Assumptions used to determine benefits
obligations
         Pension benefits     Other benefits  
As of December 31,          2011     2010     2009     2011     2010     2009  

Discount rate (weighted average for all regions)

        4.61     5.01     5.41     4.70     5.00     5.60%   
   Of which Euro zone      4.21     4.58     5.12     4.25     4.55     5.18%   
   Of which United States      5.00     5.49     6.00     4.97     5.42     5.99%   
   Of which United Kingdom      4.75     5.50     5.50                     

Average expected rate of salary increase

        4.69     4.55     4.50                     

Expected rate of healthcare inflation

               

— initial rate

                             4.82     4.82     4.91%   

— ultimate rate

                               3.77     3.75     3.79%   
       
Assumptions used to determine the net periodic
benefit cost (income)
         Pension benefits     Other benefits  
For the year ended December 31,          2011     2010     2009     2011     2010     2009  

Discount rate (weighted average for all regions)

        5.01     5.41     5.93     5.00     5.60     6.00%   
   Of which Euro zone      4.58     5.12     5.72     4.55     5.18     5.74%   
   Of which United States      5.49     6.00     6.23     5.42     5.99     6.21%   
   Of which United Kingdom      5.50     5.50     6.00                   6.00%   

Average expected rate of salary increase

        4.55     4.50     4.56                     

Expected return on plan assets

        5.90     6.39     6.14                     

Expected rate of healthcare inflation

               

— initial rate

                             4.82     4.91     4.88%   

— ultimate rate

                               3.75     3.79     3.64%   

 

F-50


Table of Contents

A 0.5% increase or decrease in discount rates — all other things being equal — would have the following approximate impact:

 

(M)    0.5% increase     0.5% decrease  

Benefit obligation as of December 31, 2011

     (513     551   

2012 net periodic benefit cost (income)

     (41     56   

A 0.5% increase or decrease in expected return on plan assets rate — all other things being equal — would have an impact of 31 million on 2012 net periodic benefit cost (income).

The components of the net periodic benefit cost (income) in 2011, 2010 and 2009 are:

 

      Pension benefits     Other benefits  
For the year ended December 31, (M)    2011     2010     2009     2011     2010     2009  

Service cost

     163        159        134        13        11        10   

Interest cost

     420        441        428        28        29        30   

Expected return on plan assets

     (385     (396     (343                     

Amortization of prior service cost

     58        74        13        2        (5     (7

Amortization of actuarial losses (gains)

     46        66        50               (4     (6

Asset ceiling

     2        (3     4                        

Curtailments

     (22     (3     (4     (1     (3     (1

Settlements

     (9     7        (1                     

Special termination benefits

                                 1          

Net periodic benefit cost (income)

     273        345        281        42        29        26   

A positive or negative change of one-percentage-point in the healthcare inflation rate would have the following approximate impact:

 

(M)    1% point
increase
     1% point
decrease
 

Benefit obligation as of December 31, 2011

     53         (63

2011 net periodic benefit cost (income)

     5         (5

19) PROVISIONS AND OTHER NON-CURRENT LIABILITIES

 

As of December 31, (M)    2011      2010      2009  

Litigations and accrued penalty claims

     572         485         423   

Provisions for environmental contingencies

     600         644         623   

Asset retirement obligations

     6,884         5,917         5,469   

Other non-current provisions

     1,099         1,116         1,331   

Other non-current liabilities

     1,754         936         1,535   

Total

     10,909         9,098         9,381   

 

In 2011, litigation reserves mainly include a provision covering risks concerning antitrust investigations related to Arkema amounting to 17 million as of December 31, 2011. Other risks and commitments that give rise to contingent liabilities are described in Note 32 to the Consolidated Financial Statements.

In 2011, other non-current provisions mainly include:

 

 

The contingency reserve related to the Toulouse-AZF plant explosion (civil liability) for 21 million as of December 31, 2011;

 

 

Provisions related to restructuring activities in the Downstream and Chemicals segments for 211 million as of December 31, 2011; and

 

 

The contingency reserve related to the Buncefield depot explosion (civil liability) for 80 million as of December 31, 2011.

In 2011, other non-current liabilities mainly include debts (whose maturity is more than one year) related to fixed assets acquisitions. This heading is mainly composed of a 991 million debt related to the acquisition of an interest in the liquids-rich area of the Utica shale play (see Note 3 to the Consolidated Financial Statements).

In 2010, litigation reserves mainly included a provision covering risks concerning antitrust investigations related to Arkema amounting to 17 million as of December 31, 2010. Other risks and commitments that give rise to contingent liabilities are described in Note 32 to the Consolidated Financial Statements.

In 2010, other non-current provisions mainly included:

 

 

The contingency reserve related to the Toulouse-AZF plant explosion (civil liability) for 31 million as of December 31, 2010;

 

 

F-51


Table of Contents
 

Provisions related to restructuring activities in the Downstream and Chemicals segments for 261 million as of December 31, 2010; and

 

 

The contingency reserve related to the Buncefield depot explosion (civil liability) for 194 million as of December 31, 2010.

In 2010, other non-current liabilities mainly included debts (whose maturity is more than one year) related to fixed assets acquisitions.

In 2009, litigation reserves mainly included a provision covering risks concerning antitrust investigations related to Arkema amounting to 43 million as of December 31, 2009. Other risks and commitments that give rise to contingent liabilities are described in Note 32 to the Consolidated Financial Statements.

In 2009, other non-current provisions mainly included:

 

 

The contingency reserve related to the Toulouse-AZF plant explosion (civil liability) for 40 million as of December 31, 2009;

 

 

Provisions related to restructuring activities in the Downstream and Chemicals segments for 130 million as of December 31, 2009; and

 

 

The contingency reserve related to the Buncefield depot explosion (civil liability) for 295 million as of December 31, 2009.

In 2009, other non-current liabilities mainly included debts (whose maturity is more than one year) related to fixed assets acquisitions. This heading was mainly composed of a 818 million debt related to Chesapeake acquisition (see Note 3 to the Consolidated Financial Statements).

 

 

Changes in provisions and other non-current liabilities

Changes in provisions and other non-current liabilities are as follows:

 

(M)    As of
January 1,
     Allowances      Reversals     Currency
translation
adjustment
     Other     As of
December 31,
 

2011

     9,098         921         (798     227         1,461        10,909   

2010

     9,381         1,052         (971     497         (861     9,098   

2009

     7,858         1,254         (1,413     202         1,480        9,381   

 

Allowances

In 2011, allowances of the period (921 million) mainly include:

 

 

Asset retirement obligations for 344 million (accretion);

 

 

Environmental contingencies for 100 million in the Downstream and Chemicals segments ; and

 

 

Provisions related to restructuring of activities for 79 million.

In 2010, allowances of the period (1,052 million) mainly included:

 

 

Asset retirement obligations for 338 million (accretion);

 

 

Environmental contingencies for 88 million in the Downstream and Chemicals segments ;

 

 

The contingency reserve related to the Buncefield depot explosion (civil liability) for 79 million ; and

 

 

Provisions related to restructuring of activities for 226 million.

In 2009, allowances of the period (1,254 million) mainly included:

 

 

Asset retirement obligations for 283 million (accretion);

 

 

Environmental contingencies for 147 million in the Downstream and Chemicals segments;

 

 

The contingency reserve related to the Buncefield depot explosion (civil liability) for 223 million; and

 

 

Provisions related to restructuring of activities for 121 million.

Reversals

In 2011, reversals of the period (798 million) are mainly related to the following incurred expenses:

 

 

Provisions for asset retirement obligations for 189 million;

 

 

Environmental contingencies written back for 70 million;

 

 

The contingency reserve related to the Toulouse-AZF plant explosion (civil liability), written back for 10 million;

 

 

The contingency reserve related to the Buncefield depot explosion (civil liability), written back for 116 million; and

 

 

Provisions for restructuring and social plans written back for 164 million.

 

 

F-52


Table of Contents

In 2010, reversals of the period (971 million) were mainly related to the following incurred expenses:

 

 

Provisions for asset retirement obligations for 214 million;

 

 

26 million for litigation reserves in connection with antitrust investigations;

 

 

Environmental contingencies written back for 66 million;

 

 

The contingency reserve related to the Toulouse-AZF plant explosion (civil liability), written back for 9 million;

 

 

The contingency reserve related to the Buncefield depot explosion (civil liability), written back for 190 million; and

 

 

Provisions for restructuring and social plans written back for 60 million.

 

In 2009, reversals of the period (1,413 million) were mainly related to the following incurred expenses:

 

 

Provisions for asset retirement obligations for 191 million;

 

 

52 million for litigation reserves in connection with antitrust investigations;

 

 

Environmental contingencies written back for 86 million;

 

 

The contingency reserve related to the Toulouse-AZF plant explosion (civil liability), written back for 216 million;

 

 

The contingency reserve related to the Buncefield depot explosion (civil liability), written back for 375 million; and

 

 

Provisions for restructuring and social plans written back for 28 million.

 

 

Changes in the asset retirement obligation

Changes in the asset retirement obligation are as follows:

 

(M)    As of
January 1,
     Accretion      Revision in
estimates
     New
obligations
     Spending
on existing
obligations
    Currency
translation
adjustment
     Other     As of
December 31,
 

2011

     5,917         344         330         323         (189     150         9        6,884   

2010

     5,469         338         79         175         (214     316         (246     5,917   

2009

     4,500         283         447         179         (191     232         19        5,469   

20) FINANCIAL DEBT AND RELATED FINANCIAL INSTRUMENTS

 

A)   NON-CURRENT FINANCIAL DEBT AND RELATED FINANCIAL INSTRUMENTS

 

As of December 31, 2011 (M)
(Assets) / Liabilities
   Secured      Unsecured     Total  

Non-current financial debt

     349         22,208        22,557   

of which hedging instruments of non-current financial debt (liabilities)

             146        146   

Hedging instruments of non-current financial debt (assets)(a)

             (1,976     (1,976

Non-current financial debt — net of hedging instruments

     349         20,232        20,581   

Bonds after fair value hedge

             15,148        15,148   

Fixed rate bonds and bonds after cash flow hedge

             4,424        4,424   

Bank and other, floating rate

     129         446        575   

Bank and other, fixed rate

     76         206        282   

Financial lease obligations

     144         8        152   

Non-current financial debt — net of hedging instruments

     349         20,232        20,581   

 

(a) See the description of these hedging instruments in Notes 1 paragraph M(iii) “Long-term financing”, 28 and 29 to the Consolidated Financial Statements.

 

F-53


Table of Contents
As of December 31, 2010 (M)
(Assets) / Liabilities
   Secured      Unsecured     Total  

Non-current financial debt

     287         20,496        20,783   

of which hedging instruments of non-current financial debt (liabilities)

             178        178   

Hedging instruments of non-current financial debt (assets)(a)

             (1,870     (1,870

Non-current financial debt — net of hedging instruments

     287         18,626        18,913   

Bonds after fair value hedge

             15,491        15,491   

Fixed rate bonds and bonds after cash flow hedge

             2,836        2,836   

Bank and other, floating rate

     47         189        236   

Bank and other, fixed rate

     65         110        175   

Financial lease obligations

     175                175   

Non-current financial debt — net of hedging instruments

     287         18,626        18,913   

 

(a) See the description of these hedging instruments in Notes 1 paragraph M(iii) “Long-term financing”, 28 and 29 to the Consolidated Financial Statements.

 

As of December 31, 2009 (M)
(Assets) / Liabilities
   Secured      Unsecured     Total  

Non-current financial debt

     312         19,125        19,437   

of which hedging instruments of non-current financial debt (liabilities)

             241        241   

Hedging instruments of non-current financial debt (assets)(a)

             (1,025     (1,025

Non-current financial debt — net of hedging instruments

     312         18,100        18,412   

Bonds after fair value hedge

             15,884        15,884   

Fixed rate bonds and bonds after cash flow hedge

             1,700        1,700   

Bank and other, floating rate

     60         379        439   

Bank and other, fixed rate

     50         79        129   

Financial lease obligations

     202         58        260   

Non-current financial debt — net of hedging instruments

     312         18,100        18,412   

 

(a) See the description of these hedging instruments in Notes 1 paragraph M(iii) “Long-term financing”, 28 and 29 to the Consolidated Financial Statements.

Fair value of bonds, as of December 31, 2011, after taking into account currency and interest rates swaps, is detailed as follows:

 

Bonds after fair value
hedge (M)
   Year of
issue
     Fair value
after hedging
as of
December 31,
2011
     Fair value
after hedging
as of
December 31,
2010
     Fair value
after hedging
as of
December 31,
2009
    Currency      Maturity      Initial rate
before
hedging
instruments

Parent company

                   

Bond

     1998         129         125         116        FRF         2013       5.000%

Bond

     2000                         61        EUR         2010       5.650%

Current portion (less than one year)

                              (61                      

Total parent company

              129         125         116                         

 

Bonds after fair value
hedge (M)
   Year of
issue
     Fair value
after hedging
as of
December 31,
2011
     Fair value
after hedging
as of
December 31,
2010
     Fair value
after hedging
as of
December 31,
2009
     Currency      Maturity     

Initial rate

before

hedging

instruments

TOTAL CAPITAL(a)

                    

Bond

     2002         15         15         14         USD         2012       5.890%

Bond

     2003                         160         CHF         2010       2.385%

Bond

     2003         23         22         21         USD         2013       4.500%

Bond

     2004                         53         CAD         2010       4.000%

Bond

     2004                         113         CHF         2010       2.385%

Bond

     2004                         438         EUR         2010       3.750%

Bond

     2004                         322         GBP         2010       4.875%

Bond

     2004                         128         GBP         2010       4.875%

Bond

     2004                         185         GBP         2010       4.875%

Bond

     2004                 57         53         AUD         2011       5.750%

Bond

     2004                 116         107         CAD         2011       4.875%

 

F-54


Table of Contents
Bonds after fair value
hedge (M)
   Year of
issue
     Fair value
after hedging
as of
December 31,
2011
     Fair value
after hedging
as of
December 31,
2010
     Fair value
after hedging
as of
December 31,
2009
     Currency      Maturity     

Initial rate

before

hedging

instruments

Bond

     2004                 235         203         USD         2011       4.125%

Bond

     2004                 75         69         USD         2011       4.125%

Bond

     2004         129         125         116         CHF         2012       2.375%

Bond

     2004         52         51         47         NZD         2014       6.750%

Bond

     2005                 57         53         AUD         2011       5.750%

Bond

     2005                 60         56         CAD         2011       4.000%

Bond

     2005                 120         112         CHF         2011       1.625%

Bond

     2005                 226         226         CHF         2011       1.625%

Bond

     2005                 139         144         USD         2011       4.125%

Bond

     2005         63         63         63         AUD         2012       5.750%

Bond

     2005         200         194         180         CHF         2012       2.135%

Bond

     2005         65         65         65         CHF         2012       2.135%

Bond

     2005         97         97         97         CHF         2012       2.375%

Bond

     2005         404         391         363         EUR         2012       3.250%

Bond

     2005         57         57         57         NZD         2012       6.500%

Bond

     2006                         75         GBP         2010       4.875%

Bond

     2006                         50         EUR         2010       3.750%

Bond

     2006                         50         EUR         2010       3.750%

Bond

     2006                         100         EUR         2010       3.750%

Bond

     2006                 42         42         EUR         2011       EURIBOR

3 months

+0.040%

Bond

     2006                 300         300         EUR         2011       3.875%

Bond

     2006                 150         150         EUR         2011       3.875%

Bond

     2006                 300         300         EUR         2011       3.875%

Bond

     2006                 120         120         USD         2011       5.000%

Bond

     2006                 300         300         EUR         2011       3.875%

Bond

     2006                 472         472         USD         2011       5.000%

Bond

     2006         62         62         62         AUD         2012       5.625%

Bond

     2006         72         72         72         CAD         2012       4.125%

Bond

     2006         100         100         100         EUR         2012       3.250%

Bond

     2006         74         74         74         GBP         2012       4.625%

Bond

     2006         100         100         100         EUR         2012       3.250%

Bond

     2006         125         125         125         CHF         2013       2.510%

Bond

     2006         127         127         127         CHF         2014       2.635%

Bond

     2006         130         130         130         CHF         2016       2.385%

Bond

     2006         65         65         65         CHF         2016       2.385%

Bond

     2006         64         64         64         CHF         2016       2.385%

Bond

     2006         63         63         63         CHF         2016       2.385%

Bond

     2006         129         129         129         CHF         2018       3.135%

Bond

     2007                         60         CHF         2010       2.385%

Bond

     2007                         74         GBP         2010       4.875%

Bond

     2007                 77         77         USD         2011       5.000%

Bond

     2007         370         370         370         USD         2012       5.000%

Bond

     2007         222         222         222         USD         2012       5.000%

Bond

     2007         61         61         61         AUD         2012       6.500%

Bond

     2007         72         72         72         CAD         2012       4.125%

Bond

     2007         71         71         71         GBP         2012       4.625%

Bond

     2007         300         300         300         EUR         2013       4.125%

Bond

     2007         73         73         73         GBP         2013       5.500%

Bond

     2007         306         306         306         GBP         2013       5.500%

Bond

     2007         72         72         72         GBP         2013       5.500%

Bond

     2007         248         248         248         CHF         2014       2.635%

Bond

     2007         31         31         31         JPY         2014       1.505%

Bond

     2007         61         61         61         CHF         2014       2.635%

Bond

     2007         49         49         49         JPY         2014       1.723%

Bond

     2007         121         121         121         CHF         2015       3.125%

Bond

     2007         300         300         300         EUR         2017       4.700%

Bond

     2007         76         76         76         CHF         2018       3.135%

 

F-55


Table of Contents
December 31, December 31, December 31, December 31, December 31, December 31, December 31,
Bonds after fair value
hedge (M)
   Year of
issue
     Fair value
after hedging
as of
December 31,
2011
     Fair value
after hedging
as of
December 31,
2010
     Fair value
after hedging
as of
December 31,
2009
     Currency      Maturity     

Initial rate

before

hedging

instruments

Bond

     2007         60         60         60         CHF         2018       3.135%

Bond

     2008                         63         GBP         2010       4.875%

Bond

     2008                         66         GBP         2010       4.875%

Bond

     2008                 92         92         AUD         2011       7.500%

Bond

     2008                 100         100         EUR         2011       3.875%

Bond

     2008                 150         150         EUR         2011       3.875%

Bond

     2008                 50         50         EUR         2011       3.875%

Bond

     2008                 50         50         EUR         2011       3.875%

Bond

     2008                 60         60         JPY         2011       EURIBOR
6 months
+ 0.018%

Bond

     2008                 102         102         USD         2011       3.750%

Bond

     2008         62         62         62         CHF         2012       2.135%

Bond

     2008         124         124         124         CHF         2012       3.635%

Bond

     2008         46         46         46         CHF         2012       2.385%

Bond

     2008         92         92         92         CHF         2012       2.385%

Bond

     2008         64         64         64         CHF         2012       2.385%

Bond

     2008         50         50         50         EUR         2012       3.250%

Bond

     2008         63         63         63         GBP         2012       4.625%

Bond

     2008         63         63         63         GBP         2012       4.625%

Bond

     2008         63         63         63         GBP         2012       4.625%

Bond

     2008         62         62         62         NOK         2012       6.000%

Bond

     2008         69         69         69         USD         2012       5.000%

Bond

     2008         60         60         60         AUD         2013       7.500%

Bond

     2008         61         61         61         AUD         2013       7.500%

Bond

     2008         128         127         127         CHF         2013       3.135%

Bond

     2008         62         62         62         CHF         2013       3.135%

Bond

     2008         200         200         200         EUR         2013       4.125%

Bond

     2008         100         100         100         EUR         2013       4.125%

Bond

     2008         1,000         1,000         1,000         EUR         2013       4.750%

Bond

     2008         63         63         63         GBP         2013       5.500%

Bond

     2008         149         149         149         JPY         2013       EURIBOR
6 months
+ 0.008%

Bond

     2008         191         191         191         USD         2013       4.000%

Bond

     2008         61         61         61         CHF         2015       3.135%

Bond

     2008         62         62         62         CHF         2015       3.135%

Bond

     2008         61         61         61         CHF         2015       3.135%

Bond

     2008         62         62         62         CHF         2018       3.135%

Bond

     2009         56         56         56         AUD         2013       5.500%

Bond

     2009         54         54         54         AUD         2013       5.500%

Bond

     2009         236         236         236         CHF         2013       2.500%

Bond

     2009         77         77         77         USD         2013       4.000%

Bond

     2009         131         131         131         CHF         2014       2.625%

Bond

     2009         998         997         998         EUR         2014       3.500%

Bond

     2009         150         150         150         EUR         2014       3.500%

Bond

     2009         40         40         40         HKD         2014       3.240%

Bond

     2009         107         103         96         AUD         2015       6.000%

Bond

     2009         550         550         550         EUR         2015       3.625%

Bond

     2009         684         684         684         USD         2015       3.125%

Bond

     2009         232         224         208         USD         2015       3.125%

Bond

     2009         99         99         99         CHF         2016       2.385%

Bond

     2009         115         115         115         GBP         2017       4.250%

Bond

     2009         225         225         225         GBP         2017       4.250%

Bond

     2009         448         448         448         EUR         2019       4.875%

Bond

     2009         69         69         69         HKD         2019       4.180%

Bond

     2009                 374         347         USD         2021       4.250%

Bond

     2010         105         102                 AUD         2014       5.750%

 

F-56


Table of Contents
December 31, December 31, December 31, December 31, December 31, December 31, December 31,
Bonds after fair value
hedge (M)
   Year of
issue
     Fair value
after hedging
as of
December 31,
2011
    Fair value
after hedging
as of
December 31,
2010
    Fair value
after hedging
as of
December 31,
2009
    Currency      Maturity     

Initial rate

before

hedging

instruments

Bond

     2010         111        108               CAD         2014       2.500%

Bond

     2010         54        53               NZD         2014       4.750%

Bond

     2010         193        187               USD         2015       2.875%

Bond

     2010         966        935               USD         2015       3.000%

Bond

     2010         70        68               AUD         2015       6.000%

Bond

     2010         71        69               AUD         2015       6.000%

Bond

     2010         64        64               AUD         2015       6.000%

Bond

     2010         773        748               USD         2016       2.300%

Bond

     2010         491        476               EUR         2022       3.125%

Bond

     2011         116                      USD         2016       6.500%

Bond

     2011         597                      USD         2018       3.875%

Current portion (less than one year)

              (2 992     (3 450     (1,937                      

Total TOTAL CAPITAL

              12,617        15,143        15,615                         

TOTAL CAPITAL CANADA Ltd. (b)

                 

Bond

     2011         565                      CAD         2014       1.625%

Bond

     2011         565                      CAD         2014       USLIBOR
3 months
+ 0.38 %

Bond

     2011         75                      CAD         2014       5.750%

Bond

     2011         738                      CAD         2013       USLIBOR
3 months
+ 0.09 %

Bond

     2011         82                      CAD         2016       4.000%

Bond

     2011         69                      CAD         2016       3.625%

Current portion (less than one year)

                                

Total TOTAL CAPITAL CANADA Ltd

              2,094                                         

TOTAL CAPITAL INTERNATIONAL(c)

                                

Other consolidated subsidiaries

        308        223        153           

Total bonds after fair value hedge

              15,148        15,491        15,884                         

 

December 31, December 31, December 31, December 31, December 31, December 31, December 31,
Bonds after cash flow
hedge and fix rate
bonds
( million)
   Year of
issue
    

Amount after
hedging

as of
December 31,
2011

   

Amount after
hedging

as of
December 31,
2010

    

Amount after
hedging

as of
December 31,
2009

     Currency      Maturity     

Initial rate
before

hedging
instruments

 

TOTAL CAPITAL(a)

                   

Bond

     2005         294        293         292         GBP         2012         4.625

Bond

     2009         744        691         602         EUR         2019         4.875

Bond

     2009         386                        USD         2021         4.250

Bond

     2009         1,016        917         806         EUR         2024         5.125

Bond

     2010         966        935                 USD         2020         4.450

Bond

     2011         386                        USD         2021         4.125

Current portion (less than one year)

        (294                        

Total TOTAL CAPITAL

              3,498        2,836         1,700                              

Other consolidated subsidiaries(d)

        926                           

Total Bonds after cash flow hedge

              4,424        2,836         1,700                              

 

F-57


Table of Contents

 

(a) TOTAL CAPITAL is a wholly-owned indirect subsidiary of TOTAL S.A. (with the exception of one share held by each member of its Board of Directors). It acts as a financing vehicle for the Group. Its debt securities are fully and unconditionally guaranteed by TOTAL S.A. as to payment of principal, premium, if any, interest and any other amounts due.
(b) TOTAL CAPITAL CANADA Ltd. is a wholly-owned direct subsidiary of TOTAL S.A. It acts as a financing vehicle for the activities of the Group in Canada. Its debt securities are fully and unconditionally guaranteed by TOTAL S.A. as to payment of principal, premium, if any, interest and any other amounts due.
(c) TOTAL CAPITAL INTERNATIONAL is a wholly-owned direct subsidiary of TOTAL S.A. It acts as a financing vehicle for the Group. Its debt securities are fully and unconditionally guaranteed by TOTAL S.A. as to payment of principal, premium, if any, interest and any other amounts due.
(d) This amount includes SunPower’s convertible bonds for an amount of 355 million.

Loan repayment schedule (excluding current portion)

 

As of December 31,  2011
(M)
  Non-current financial
debt
    of which hedging
instruments of
non-current financial
debt (liabilities)
    Hedging instruments
of non-current
financial debt (assets)
    Non-current financial
debt - net of hedging
instruments
    %  

2013

    5,021        80        (529     4,492        22%   

2014

    4,020        3        (390     3,630        18%   

2015

    4,070        6        (456     3,614        18%   

2016

    1,712        9        (193     1,519        7%   

2017 and beyond

    7,734        48        (408     7,326        35%   

Total

    22,557        146        (1,976     20,581        100%   
           
As of  December 31, 2010
(M)
  Non-current financial
debt
    of which hedging
instruments of
non-current financial
debt (liabilities)
    Hedging instruments
of non-current
financial debt (assets)
    Non-current financial
debt - net of hedging
instruments
    %  

2012

    3,756        34        (401     3,355        18%   

2013

    4,017        76        (473     3,544        19%   

2014

    2,508        1        (290     2,218        12%   

2015

    3,706        2        (302     3,404        18%   

2016 and beyond

    6,796        65        (404     6,392        33%   

Total

    20,783        178        (1,870     18,913        100%   
           
As of  December 31, 2009
(M)
  Non-current financial
debt
    of which hedging
instruments of
non-current financial
debt (liabilities)
    Hedging instruments
of non-current
financial debt (assets)
    Non-current financial
debt - net of hedging
instruments
    %  

2011

    3,857        42        (199     3,658        20%   

2012

    3,468        48        (191     3,277        18%   

2013

    3,781        95        (236     3,545        19%   

2014

    2,199        6        (90     2,109        11%   

2015 and beyond

    6,132        50        (309     5,823        32%   

Total

    19,437        241        (1,025     18,412        100%   

Analysis by currency and interest rate

These analyses take into account interest rate and foreign currency swaps to hedge non-current financial debt.

 

As of December 31, (M)    2011      %      2010      %      2009      %  

U.S. Dollar

     8,645         42%         7,248         39%         3,962         21%   

Euro

     9,582         47%         11,417         60%         14,110         77%   

Other currencies

     2,354         11%         248         1%         340         2%   

Total

     20,581         100%         18,913         100%         18,412         100%   

 

As of December 31, (M)    2011      %      2010      %      2009      %  

Fixed rate

     4,854         24%         3,177         17%         2,064         11%   

Floating rate

     15,727         76%         15,736         83%         16,348         89%   

Total

     20,581         100%         18,913         100%         18,412         100%   

 

F-58


Table of Contents
B)   CURRENT FINANCIAL ASSETS AND LIABILITIES

Current borrowings consist mainly of commercial papers or treasury bills or draws on bank loans. These instruments bear interest at rates that are close to market rates.

 

As of December 31, (M)    2011     2010     2009  

(Assets) / Liabilities

      

Current financial debt(a)

     5,819        5,867        4,761   

Current portion of non-current financial debt

     3,856        3,786        2,233   

Current borrowings (note 28)

     9,675        9,653        6,994   

Current portion of hedging instruments of debt (liabilities)

     40        12        97   

Other current financial instruments (liabilities)

     127        147        26   

Other current financial liabilities (note 28)

     167        159        123   

Current deposits beyond three months

     (101     (869     (55

Current portion of hedging instruments of debt (assets)

     (383     (292     (197

Other current financial instruments (assets)

     (216     (44     (59

Current financial assets (note 28)

     (700     (1,205     (311

Current borrowings and related financial assets and liabilities, net

     9,142        8,607        6,806   

 

(a) As of December 31, 2011 and as of December 31, 2010, the current financial debt includes a commercial paper program in Total Capital Canada Ltd. Total Capital Canada Ltd. is a wholly-owned direct subsidiary of TOTAL S.A. It acts as a financing vehicle for the activities of the Group in Canada. Its debt securities are fully and unconditionally guaranteed by TOTAL S.A. as to payment of principal, premium, if any, interest and any other amounts due.

 

C)   NET-DEBT-TO-EQUITY RATIO

For its internal and external communication needs, the Group calculates a debt ratio by dividing its net financial debt by equity. Adjusted shareholders’ equity for the year ended December 31, 2011 is calculated after payment of a dividend of 2.28 per share, subject to approval by the shareholders’ meeting on May 11, 2012.

The net-debt-to-equity ratio is calculated as follows:

 

As of December 31, (M)    2011     2010     2009  

(Assets) / Liabilities

      

Current borrowings

     9,675        9,653        6,994   

Other current financial liabilities

     167        159        123   

Current financial assets

     (700     (1,205     (311

Non-current financial debt

     22,557        20,783        19,437   

Hedging instruments on non-current financial debt

     (1,976     (1,870     (1,025

Cash and cash equivalents

     (14,025     (14,489     (11,662

Net financial debt

     15,698        13,031        13,556   

Shareholders’ equity — Group share

     68,037        60,414        52,552   

Distribution of the income based on existing shares at the closing date

     (1,255     (2,553     (2,546

Non-controlling interests

     1,352        857        987   

Adjusted shareholders’ equity

     68,134        58,718        50,993   

Net-debt-to-equity ratio

     23.0%        22.2%        26.6%   

21) OTHER CREDITORS AND ACCRUED LIABILITIES

 

As of December 31, (M)    2011      2010      2009  

Accruals and deferred income

     231         184         223   

Payable to States (including taxes and duties)

     8,040         7,235         6,024   

Payroll

     1,062         996         955   

Other operating liabilities

     5,441         3,574         4,706   

Total

     14,774         11,989         11,908   

As of December 31, 2011, the heading “Other operating liabilities” mainly includes the third quarterly interim dividend for the fiscal year 2011 for 1,317 million. This interim dividend will be paid on March 2012.

As of December 31, 2009, the heading “Other operating liabilities” mainly included 744 million related to Chesapeake acquisition (see Note 3 to the Consolidated Financial Statements).

 

F-59


Table of Contents

22) LEASE CONTRACTS

The Group leases real estate, retail stations, ships, and other equipments (see Note 11 to the Consolidated Financial Statements).

The future minimum lease payments on operating and finance leases to which the Group is committed are shown as follows:

 

For the year ended December 31,
2011 (M)
   Operating
leases
     Finance
leases
 

2012

     762         41   

2013

     552         40   

2014

     416         37   

2015

     335         36   

2016

     316         34   

2017 and beyond

     940         20   

Total minimum payments

     3,321         208   

Less financial expenses

             (31

Nominal value of contracts

             177   

Less current portion of finance lease contracts

             (25

Outstanding liability of finance lease contracts

             152   

 

For the year ended December 31,
2010 (M)
   Operating
leases
     Finance
leases
 

2011

     582         39   

2012

     422         39   

2013

     335         39   
For the year ended December 31,
2010 (M)
   Operating
leases
     Finance
leases
 

2014

     274         35   

2015

     230         35   

2016 and beyond

     1,105         54   

Total minimum payments

     2,948         241   

Less financial expenses

             (43

Nominal value of contracts

             198   

Less current portion of finance lease contracts

             (23

Outstanding liability of finance lease contracts

             175   

 

For the year ended December 31,
2009 (M)
   Operating
leases
     Finance
leases
 

2010

     523         42   

2011

     377         43   

2012

     299         42   

2013

     243         41   

2014

     203         39   

2015 and beyond

     894         128   

Total minimum payments

     2,539         335   

Less financial expenses

             (53

Nominal value of contracts

             282   

Less current portion of finance lease contracts

             (22

Outstanding liability of finance lease contracts

             260   

Net rental expense incurred under operating leases for the year ended December 31, 2011 is 645 million (against 605 million in 2010 and 613 million in 2009).

 

 

23) COMMITMENTS AND CONTINGENCIES

 

      Maturity and installments  

As of December 31, 2011

(M)

   Total      Less than
1 year
     Between 1
and 5 years
     More than
5 years
 

Non-current debt obligations net of hedging instruments (Note 20)

     20,429                 13,121         7,308   

Current portion of non-current debt obligations net of hedging instruments (Note 20)

     3,488         3,488                   

Finance lease obligations (Note 22)

     177         25         134         18   

Asset retirement obligations (Note 19)

     6,884         272         804         5,808   

Contractual obligations recorded in the balance sheet

     30,978         3,785         14,059         13,134   

Operating lease obligations (Note 22)

     3,321         762         1,619         940   

Purchase obligations

     77,353         11,049         20,534         45,770   

Contractual obligations not recorded in the balance sheet

     80,674         11,811         22,153         46,710   

Total of contractual obligations

     111,652         15,596         36,212         59,844   

Guarantees given for excise taxes

     1,765         1,594         73         98   

Guarantees given against borrowings

     4,778         3,501         323         954   

Indemnities related to sales of businesses

     39                 34         5   

Guarantees of current liabilities

     376         262         35         79   

Guarantees to customers / suppliers

     3,265         1,634         57         1,574   

Letters of credit

     2,408         1,898         301         209   

Other operating commitments

     2,477         433         697         1,347   

Total of other commitments given

     15,108         9,322         1,520         4,266   

Mortgages and liens received

     408         7         119         282   

Goods and services sale obligations(a)

     62,216         4,221         17,161         40,834   

Other commitments received

     6,740         4,415         757         1,568   

Total of commitments received

     69,364         8,643         18,037         42,684   

 

(a) As from December 31, 2011, the Group discloses its goods and services sale obligations.

 

F-60


Table of Contents
      Maturity and installments  
As of December 31, 2010 (M)    Total      Less than
1 year
     Between 1
and 5 years
     More than
5 years
 

Non-current debt obligations net of hedging instruments (Note 20)

     18,738                 12,392         6,346   

Current portion of non-current debt obligations net of hedging instruments (Note 20)

     3,483         3,483                   

Finance lease obligations (Note 22)

     198         23         129         46   

Asset retirement obligations (Note 19)

     5,917         177         872         4,868   

Contractual obligations recorded in the balance sheet

     28,336         3,683         13,393         11,260   

Operating lease obligations (Note 22)

     2,948         582         1,261         1,105   

Purchase obligations

     61,293         6,347         14,427         40,519   

Contractual obligations not recorded in the balance sheet

     64,241         6,929         15,688         41,624   

Total of contractual obligations

     92,577         10,612         29,081         52,884   

Guarantees given for excise taxes

     1,753         1,594         71         88   

Guarantees given against borrowings

     5,005         1,333         493         3,179   

Indemnities related to sales of businesses

     37                 31         6   

Guarantees of current liabilities

     171         147         19         5   

Guarantees to customers / suppliers

     3,020         1,621         96         1,303   

Letters of credit

     1,250         1,247                 3   

Other operating commitments

     2,057         467         220         1,370   

Total of other commitments given

     13,293         6,409         930         5,954   

Mortgages and liens received

     429         2         114         313   

Other commitments received

     6,387         3,878         679         1,830   

Total of commitments received

     6,816         3,880         793         2,143   

 

      Maturity and installments  
As of December 31, 2009 (M)    Total      Less than
1 year
     Between 1
and 5 years
     More than
5 years
 

Non-current debt obligations net of hedging instruments (Note 20)

     18,152                 12,443         5,709   

Current portion of non-current debt obligations net of hedging instruments (Note 20)

     2,111         2,111                   

Finance lease obligations (Note 22)

     282         22         146         114   

Asset retirement obligations (Note 19)

     5,469         235         972         4,262   

Contractual obligations recorded in the balance sheet

     26,014         2,368         13,561         10,085   

Operating lease obligations (Note 22)

     2,539         523         1,122         894   

Purchase obligations

     49,808         4,542         9,919         35,347   

Contractual obligations not recorded in the balance sheet

     52,347         5,065         11,041         36,241   

Total of contractual obligations

     78,361         7,433         24,602         46,326   

Guarantees given for excise taxes

     1,765         1,617         69         79   

Guarantees given against borrowings

     2,882         1,383         709         790   

Indemnities related to sales of businesses

     36                 1         35   

Guarantees of current liabilities

     203         160         38         5   

Guarantees to customers / suppliers

     2,770         1,917         70         783   

Letters of credit

     1,499         1,485         2         12   

Other operating commitments

     765         582         103         80   

Total of other commitments given

     9,920         7,144         992         1,784   

Mortgages and liens received

     330         5         106         219   

Other commitments received

     5,637         3,187         481         1,969   

Total of commitments received

     5,967         3,192         587         2,188   

 

F-61


Table of Contents
A.   CONTRACTUAL OBLIGATIONS

Debt obligations

“Non-current debt obligations” are included in the items “Non-current financial debt” and “Hedging instruments of non-current financial debt” of the Consolidated Balance Sheet. It includes the non-current portion of swaps hedging bonds, and excludes non-current finance lease obligations of 152 million.

The current portion of non-current debt is included in the items “Current borrowings”, “Current financial assets” and “Other current financial liabilities” of the Consolidated Balance Sheet. It includes the current portion of swaps hedging bonds, and excludes the current portion of finance lease obligations of 25 million.

The information regarding contractual obligations linked to indebtedness is presented in Note 20 to the Consolidated Financial Statements.

Lease contracts

The information regarding operating and finance leases is presented in Note 22 to the Consolidated Financial Statements.

Asset retirement obligations

This item represents the discounted present value of Upstream asset retirement obligations, primarily asset removal costs at the completion date. The information regarding contractual obligations linked to asset retirement obligations is presented in Notes 1Q and 19 to the Consolidated Financial Statements.

Purchase obligations

Purchase obligations are obligations under contractual agreements to purchase goods or services, including capital projects. These obligations are enforceable and legally binding on the company and specify all significant terms, including the amount and the timing of the payments.

These obligations mainly include: hydrocarbon unconditional purchase contracts (except where an active, highly-liquid market exists and when the hydrocarbons are expected to be re-sold shortly after purchase), reservation of transport capacities in pipelines, unconditional exploration works and development works in the Upstream segment, and contracts for capital investment projects in the Downstream segment.

B.   OTHER COMMITMENTS GIVEN

Guarantees given for excise taxes

They consist of guarantees given to other oil and gas companies in order to comply with French tax authorities’ requirements for oil and gas imports in France. A payment would be triggered by a failure of the guaranteed party with respect to the French tax authorities. The default of the guaranteed parties is however considered to be highly remote by the Group.

Guarantees given against borrowings

The Group guarantees bank debt and finance lease obligations of certain non-consolidated subsidiaries and equity affiliates. Maturity dates vary, and guarantees will terminate on payment and/or cancellation of the obligation. A payment would be triggered by failure of the guaranteed party to fulfill its obligation covered by the guarantee, and no assets are held as collateral for these guarantees. As of December 31, 2011, the maturities of these guarantees are up to 2023.

Guarantees given against borrowings include the guarantee given in 2008 by TOTAL S.A. in connection with the financing of the Yemen LNG project for an amount of 1,208 million. In turn, certain partners involved in this project have given commitments that could, in the case of Total S.A.’s guarantees being called for the maximum amount, reduce the Group’s exposure by up to 404 million, recorded under “Other commitments received”.

In 2010, TOTAL S.A. provided guarantees in connection with the financing of the Jubail project (operated by SAUDI ARAMCO TOTAL Refining and Petrochemical Company (SATORP)) of up to 2,463 million, proportional to TOTAL’s share in the project (37.5%). In addition, TOTAL S.A. provided in 2010 a guarantee in favor of its partner in the Jubail project (Saudi Arabian Oil Company) with respect to Total Refining Saudi Arabia SAS’s obligations under the shareholders agreement with respect to SATORP. As of December 31, 2011, this guarantee is of up to 1,095 million and has been recorded under “Other operating commitments”.

Indemnities related to sales of businesses

In the ordinary course of business, the Group executes contracts involving standard indemnities in oil industry and indemnities specific to transactions such as sales of businesses. These indemnities might include claims against any of the following: environmental, tax and shareholder matters, intellectual property rights, governmental regulations and employment-related matters,

 

 

F-62


Table of Contents

dealer, supplier, and other commercial contractual relationships. Performance under these indemnities would generally be triggered by a breach of terms of the contract or by a third party claim. The Group regularly evaluates the probability of having to incur costs associated with these indemnities.

The guarantees related to antitrust investigations granted as part of the agreement relating to the spin-off of Arkema are described in Note 32 to the Consolidated Financial Statements.

Other guarantees given

Non-consolidated subsidiaries

The Group also guarantees the current liabilities of certain non-consolidated subsidiaries. Performance under these guarantees would be triggered by a financial default of the entity.

Operating agreements

As part of normal ongoing business operations and consistent with generally and accepted recognized industry practices, the Group enters into numerous agreements with other parties. These commitments are often entered into for commercial purposes, for regulatory purposes or for other operating agreements.

 

C.   COMMITMENTS RECEIVED

Goods and services sale obligations

These amounts represent binding obligations under contractual agreements to sell goods or services, including in particular hydrocarbon unconditional sale contracts (except when an active, highly-liquid market exists and volumes are re-sold shortly after purchase).

 

 

24) RELATED PARTIES

The main transactions and balances with related parties (principally non-consolidated subsidiaries and equity affiliates) are detailed as follows:

 

As of December 31, (M)    2011      2010      2009  

Balance sheet

        

Receivables

        

Debtors and other debtors

     585         432         293   

Loans (excl. loans to equity affiliates)

     331         315         438   

Payables

        

Creditors and other creditors

     724         497         386   

Debts

     31         28         42   
       
For the year ended December 31, (M)    2011      2010      2009  

Statement of income

        

Sales

     4,400         3,194         2,183   

Purchases

     5,508         5,576         2,958   

Financial expense

             69         1   

Financial income

     79         74         68   

Compensation for the administration and management bodies

The aggregate amount of direct and indirect compensation accounted for by the French and foreign affiliates of the Company for the executive officers of TOTAL (the members of the Management Committee and the Treasurer) and for the members of the Board of Directors who are employees of the Group, is detailed as follows:

 

For the year ended December 31, (M)    2011      2010      2009  

Number of people

     30         26         27   

Direct or indirect compensation received

     20.4         20.8         19.4   

Pension expenses(a)

     9.4         12.2         10.6   

Other long-term benefits expenses

                       

Termination benefits expenses

     4.8                   

Share-based payments expense (IFRS 2)(b)

     10.2         10.0         11.2   

 

(a) The benefits provided for executive officers and certain members of the Board of Directors, employees and former employees of the Group, include severance to be paid on retirement, supplementary pension schemes and insurance plans, which represent 139.7 million provisioned as of December 31, 2011 (against 113.8 million as of December 31, 2010 and 96.6 million as of December 31, 2009).
(b) Share-based payments expense computed for the executive officers and the members of the Board of Directors who are employees of the Group as described in Note 25 paragraph E to the Consolidated Financial Statements and based on the principles of IFRS 2 “Share-based payments” described in Note 1 paragraph E to the Consolidated Financial Statements.

The compensation allocated to members of the Board of Directors for directors’ fees totaled 1.07 million in 2011 (0.96 million in 2010 and 0.97 million in 2009).

 

F-63


Table of Contents

25) SHARE-BASED PAYMENTS

 

A.   TOTAL SHARE SUBSCRIPTION OPTION PLANS

 

     2003 Plan     2004 Plan     2005 Plan     2006 Plan     2007 Plan     2008 Plan     2009 Plan     2010 Plan     2011 Plan     Total     Weighted
average
exercise
price
 

Date of the shareholders’ meeting

    05/17/2001        05/14/2004        05/14/2004        05/14/2004        05/11/2007        05/11/2007        05/11/2007        05/21/2010        05/21/2010       

Date of the award(a)

    07/16/2003        07/20/2004        07/19/2005        07/18/2006        07/17/2007        10/09/2008        09/15/2009        09/14/2010        09/14/2011       

Exercise price until May 23, 2006 included(b)

    33.30        39.85        49.73                                                 

Exercise price since May 24, 2006(b)

    32.84        39.30        49.04        50.60        60.10        42.90        39.90        38.20        33.00       

Expiry date

    07/16/2011        07/20/2012        07/19/2013        07/18/2014        07/17/2015        10/09/2016        09/15/2017        09/14/2018        09/14/2019                   

Number of options(c)

                     

Existing options as of January 1, 2008

    8,368,378        13,197,236        6,243,438        5,711,060        5,920,105                                    39,440,217        44.23   

Granted

                                       4,449,810                             4,449,810        42.90   

Cancelled

    (25,184     (118,140     (34,032     (53,304     (34,660     (6,000                          (271,320 )      44.88   

Exercised

    (841,846     (311,919     (17,702     (6,700                                        (1,178,167 )      34.89   

Existing options as of January 1, 2009

    7,501,348        12,767,177        6,191,704        5,651,056        5,885,445        4,443,810                             42,440,540        44.35   

Granted

                                              4,387,620                      4,387,620        39.90   

Cancelled

    (8,020     (18,387     (6,264     (5,370     (13,780     (2,180     (10,610                   (64,611 )      45.04   

Exercised

    (681,699     (253,081                                                      (934,780 )      34.59   

Existing options as of January 1, 2010

    6,811,629        12,495,709        6,185,440        5,645,686        5,871,665        4,441,630        4,377,010                      45,828,769        44.12   

Granted

                                                     4,788,420               4,788,420        38.20   

Cancelled(d)

    (1,420     (15,660     (6,584     (4,800     (5,220     (92,472     (4,040     (1,120            (131,316 )      43.50   

Exercised

    (1,075,765     (141,202                                 (1,080                   (1,218,047 )      33.60   

Existing options as of January 1, 2011

    5,734,444        12,338,847        6,178,856        5,640,886        5,866,445        4,349,158        4,371,890        4,787,300               49,267,826        43.80   

Granted

                                                            1,518,840        1,518,840        33.00   

Cancelled(e)

    (738,534     (28,208     (16,320     (17,380     (16,080     (13,260     (14,090     (85,217     (1,000     (930,089 )      34.86   

Exercised

    (4,995,910     (216,115                          (200            (2,040     (9,400     (5,223,665 )      33.11   

Existing options as of December 31, 2011

           12,094,524        6,162,536        5,623,506        5,850,365        4,335,698        4,357,800        4,700,043        1,508,440        44,632,912        44.87   

 

(a) The grant date is the date of the Board meeting awarding the share subscription options, except for the grant of October 9, 2008, decided by the Board on September 9, 2008.
(b) Exercise price in euro. The exercise prices of TOTAL subscription shares of the plans in force at that date were multiplied by 0.25 to take into account the four-for-one stock split on May 18, 2006. Moreover, following the spin-off of Arkema, the exercise prices of TOTAL subscription shares of these plans were multiplied by an adjustment factor equal to 0.986147 effective as of May 24, 2006.
(c) The number of options awarded, outstanding, canceled or exercised before May 23, 2006 included, was multiplied by four to take into account the four-for-one stock split approved by the shareholders’ meeting on May 12, 2006.
(d) Out of 92,472 options awarded under the 2008 Plan that were canceled, 88,532 options were canceled due to the performance condition. The acquisition rate applicable to the subscription options that were subject to the performance condition of the 2008 Plan was 60%.
(e) Out of the 930,089 options canceled in 2011, 738,534 options that were not exercised expired due to the expiry of the 2003 subscription option Plan on July 16, 2011.

 

F-64


Table of Contents

Options are exercisable, subject to a continuous employment condition, after a 2-year period from the date of the Board meeting awarding the options and expire eight years after this date. The underlying shares may not be transferred during four years from the date of grant. For the 2007 to 2011 Plans, the 4-year transfer restriction period does not apply to employees of non-French subsidiaries as of the date of the grant, who may transfer the underlying shares after a 2-year period from the date of the grant.

2011 Plan

For the 2011 Plan, the Board of Directors decided that for each grantee other than the Chairman and Chief Executive Officer, the options will be finally granted to their beneficiary provided that the performance condition is fulfilled.

The performance condition states that the number of options finally granted is based on the average of the Return On Equity (ROE) of the Group. The average ROE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012.

The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

 

varies on straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

 

is equal to 100% if the average ROE is more than or equal to 18%.

In addition, as part of the 2011 Plan, the Board of Directors decided that the number of share subscription options finally awarded to the Chairman and Chief Executive Officer will be subject to two performance conditions:

 

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROE of the Group. The average ROE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate is equal to zero if the average ROE is less than or equal to 7%; varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and is equal to 100% if the average ROE is more than or equal to 18%.

 

 

For 50% of the share subscription options granted, the performance condition states that the number of

   

options finally granted is based on the average of the Return On Average Capital Employed (ROACE) of the Group. The average ROACE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate is equal to zero if the average ROACE is less than or equal to 6%; varies on a straight-line basis between 0% and 100% if the average ROACE is more than 6% and less than 15%; and is equal to 100% if the average ROACE is more than or equal to 15%.

2010 Plan

For the 2010 Plan, the Board of Directors decided that:

 

 

For each grantee of up to 3,000 options, other than the Chairman and Chief Executive Officer, the options will be finally granted to their beneficiary.

 

 

For each grantee of more than 3,000 options and less or equal to 50,000 options (other than the Chairman and Chief Executive Officer):

 

   

The first 3,000 options and two-thirds above the first 3,000 options will be finally granted to their beneficiary;

 

   

The outstanding options, that is one-third of the options above the first 3,000 options, will be finally granted provided that the performance condition described below is fulfilled.

 

   

For each grantee of more than 50,000 options (other than the Chairman and Chief Executive Officer):

 

   

The first 3,000 options, two-thirds of the options above the first 3,000 options and below the first 50,000 options, and one-third of the options above the first 50,000 options, will be finally granted to their beneficiary;

 

   

The outstanding options, that is one-third of the options above the first 3,000 options and below the first 50,000 options and two-thirds of the options above the first 50,000 options, will be finally granted provided that the performance condition is fulfilled.

The performance condition states that the number of options finally granted is based on the average ROE of the Group. The average ROE is calculated by the Group based on TOTAL’s consolidated balance sheet and statement of income for fiscal years 2010 and 2011. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

 

F-65


Table of Contents
 

varies on straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

 

is equal to 100% if the average ROE is more than or equal to 18%.

In addition, as part of the 2010 Plan, the Board of Directors decided that the number of share subscription options finally awarded to the Chairman and Chief Executive Officer will be subject to two performance conditions:

 

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROE of the Group. The average ROE is calculated by the Group based on TOTAL’s consolidated balance sheet and statement of income for fiscal years 2010 and 2011. The acquisition rate is equal to zero if the average ROE is less than or equal to 7%; varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and is equal to 100% if the average ROE is more than or equal to 18%.

 

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROACE of the Group. The average ROACE is calculated by the Group based on TOTAL’s consolidated balance sheet and statement of income for fiscal years 2010 and 2011. The acquisition rate is equal to zero if the average ROACE is less than or equal to 6%; varies on a straight-line basis between 0% and 100% if the average ROACE is more than 6% and less than 15%; and is equal to 100% if the average ROACE is more than or equal to 15%.

2009 Plan

For the 2009 Plan, the Board of Directors decided that for each beneficiary, other than the Chief Executive Officer, of more than 25,000 options, one third of the options granted in excess of this number will be finally granted subject to a performance condition. This condition states that the final number of options finally granted is based on the average

ROE of the Group as published by TOTAL. The average ROE is calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2009 and 2010. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

 

varies on straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and

 

 

is equal to 100% if the average ROE is more than or equal to 18%.

In addition, the Board of Directors decided that, for the Chief Executive Officer, the number of share subscription options finally granted will be subject to two performance conditions:

 

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROE of the Group as published by TOTAL. The average ROE is calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2009 and 2010. The acquisition rate is equal to zero if the average ROE is less than or equal to 7%; varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and is equal to 100% if the average ROE is more than or equal to 18%.

 

 

For 50% of the share subscription options granted, the performance condition states that the number of options finally granted is based on the average ROACE of the Group as published by TOTAL. The average ROACE is calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2009 and 2010. The acquisition rate is equal to zero if the average ROACE is less than or equal to 6%; varies on a straight-line basis between 0% and 100% if the average ROACE is more than 6% and less than 15%; and is equal to 100% if the average ROACE is more than or equal to 15%.

Due to the application of the performance condition, the acquisition rates were 100% for the 2009 Plan.

 

 

F-66


Table of Contents
B.   TOTAL SHARE PURCHASE OPTION PLANS

 

      2001 Plan(a)     2002 Plan(b)     Total     Weighted
average exercise
price
 

Date of the shareholders’ meeting

     05/17/2001        05/17/2001       

Grant date(c)

     07/10/2001        07/09/2002       

Exercise price until May 23, 2006 included(d)

     42.05        39.58       

Exercise price since May 24, 2006(d)

     41.47        39.03       

Expiry date

     07/10/2009        07/09/2010                   

Number of options(e)

        

Outstanding as of January 1, 2009

     4,691,426        6,450,857        11,142,283        40.06   

Awarded

                            

Cancelled

     (4,650,446     (7,920     (4,658,366 )      41.47   

Exercised

     (40,980     (507,676     (548,656 )      39.21   

Outstanding as of January 1, 2010

            5,935,261        5,935,261        39.03   

Awarded

                            

Cancelled(f)

            (4,671,989     (4,671,989 )      39.03   

Exercised

            (1,263,272     (1,263,272 )      39.03   

Outstanding as of January 1, 2011

                            

Awarded

                            

Cancelled

                            

Exercised

                            

Outstanding as of December 31, 2011

                            

 

(a) Options were exercisable, subject to a continued employment condition, after a 3.5-year vesting period from the date of the Board meeting awarding the options and expired 8 years after this date. The underlying shares may not be transferred during the 4-year period from the date of the grant. This plan expired on July 10, 2009.
(b) Options were exercisable, subject to a continued employment condition, after a 2-year vesting period from the date of the Board meeting awarding the options and expired 8 years after this date. The underlying shares may not be transferred during the 4-year period from the date of the grant. This plan expired on July 9, 2010.
(c) The grant date is the date of the Board meeting awarding the options.
(d) Exercise price in euro. The exercise prices of TOTAL share purchase options of the plans at that date were multiplied by 0.25 to take into account the four-for-one stock split on May 18, 2006. Moreover, following the spin-off of Arkema, the exercise prices of TOTAL share purchase options of these plans were multiplied by an adjustment factor equal to 0.986147 effective as of May 24, 2006.
(e) The number of options awarded, outstanding, canceled or exercised before May 23, 2006 included, was multiplied by four to take into account the four-for-one stock split approved by the shareholders’ meeting on May 12, 2006.
(f) Out of the 4,671,989 options canceled in 2010, 4,671,145 options that were not exercised expired due to the expiry of the 2002 purchase option Plan on July 9, 2010.

 

C.   EXCHANGE GUARANTEE GRANTED TO THE HOLDERS OF ELF AQUITAINE SHARE SUBSCRIPTION OPTIONS

Pursuant to the public exchange offer for Elf Aquitaine shares which was made in 1999, the Group made a commitment to guarantee the holders of Elf Aquitaine share subscription options, at the end of the period referred to in Article 163 bis C of the French Tax Code (CGI), and until the end of the period for the exercise of the options, the possibility to exchange their future Elf Aquitaine shares for TOTAL shares, on the basis of the exchange ratio of the offer (nineteen TOTAL shares for thirteen Elf Aquitaine shares).

In order to take into account the spin-off of S.D.A. (Société de Développement Arkema) by Elf Aquitaine, the spin-off of Arkema by TOTAL S.A. and the four-for-one TOTAL stock split, the Board of Directors of TOTAL S.A., in accordance

with the terms of the share exchange undertaking, approved on March 14, 2006 to adjust the exchange ratio described above (see pages 24 and 25 of the “Prospectus for the purpose of listing Arkema shares on Euronext Paris in connection with the allocation of Arkema shares to TOTAL S.A. shareholders”). Following the approval by Elf Aquitaine shareholders’ meeting on May 10, 2006 of the spin-off of S.D.A. by Elf Aquitaine, the approval by TOTAL S.A. shareholders’ meeting on May 12, 2006 of the spin-off of Arkema by TOTAL S.A. and the four-for-one TOTAL stock split, the exchange ratio was adjusted to six TOTAL shares for one Elf Aquitaine share on May 22, 2006.

This exchange guarantee expired on September 12, 2009, due to the expiry of the Elf Aquitaine share subscription option plan No. 2 of 1999. Subsequently, no Elf Aquitaine shares are covered by the exchange guarantee.

 

 

F-67


Table of Contents
D.   TOTAL PERFORMANCE SHARE GRANTS

 

     2005 Plan     2006 Plan     2007 Plan     2008 Plan     2009 Plan     2010 Plan     2011 Plan     Total  

Date of the shareholders’ meeting

    05/17/2005        05/17/2005        05/17/2005        05/16/2008        05/16/2008        05/16/2008        05/13/2011     

Grant date(a)

    07/19/2005        07/18/2006        07/17/2007        10/09/2008        09/15/2009        09/14/2010        09/14/2011     

Final grant date (end of the vesting period)

    07/20/2007        07/19/2008        07/18/2009        10/10/2010        09/16/2011        09/15/2012        09/15/2013     

Transfer possible from

    07/20/2009        07/19/2010        07/18/2011        10/10/2012        09/16/2013        09/15/2014        09/15/2015           

Number of performance shares

               

Outstanding as of January 1, 2009

                  2,333,217        2,772,748              5,105,965   

Awarded

                                2,972,018            2,972,018   

Canceled

    1,928        2,922        (12,418     (9,672     (5,982         (23,222 ) 

Finally granted(b)(c)

    (1,928     (2,922     (2,320,799     (600                (2,326,249 ) 

Outstanding as of January 1, 2010

                         2,762,476        2,966,036            5,728,512   

Awarded

                                       3,010,011          3,010,011   

Canceled(d)

    1,024        3,034        552        (1,113,462     (9,796     (8,738       (1,127,386 ) 

Finally granted(b)(c)

    (1,024     (3,034     (552     (1,649,014     (1,904     (636       (1,656,164 ) 

Outstanding as of January 1, 2011

                                2,954,336        3,000,637          5,954,973   

Awarded

                                              3,649,770        3,649,770   

Canceled

    800        700        792        356        (26,214     (10,750     (19,579     (53,895 ) 

Finally granted(b)(c)(e)

    (800     (700     (792     (356     (2,928,122     (1,836            (2,932,606 ) 

Outstanding as of December 31, 2011

                                       2,988,051        3,630,191        6,618,242   

 

(a) The grant date is the date of the Board of Directors meeting that awarded the shares, except for the shares awarded by the Board of Directors at their meeting of September 9, 2008, and granted on October 9, 2008.
(b) Performance shares finally granted following the death of their beneficiaries.
(c) Including performance shares finally granted for which the entitlement right had been canceled erroneously.
(d) Out of the 1,113,462 canceled rights to the grant share under the 2008 Plan, 1,094,914 entitlement rights were canceled due to the performance condition. The acquisition rate for the 2008 Plan was 60%.
(e) The acquisition rate for the 2009 Plan was 100%.

 

The performance shares, which are bought back by the Company on the market, are finally granted to their beneficiaries after a 2-year vesting period from the date of the grant. The final grant is subject to a continued employment condition and a performance condition. Moreover, the transfer of the performance shares finally granted will not be permitted until the end of a 2-year mandatory holding period from the date of the final grant.

2011 Plan

For the 2011 Plan, the Board of Directors decided that, for each senior executive (other than the Chairman and Chief Executive Officer), the shares will be finally granted subject to a performance condition. This condition is based on the average ROE as published by the Group and calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2011 and 2012. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

 

varies on a straight-line basis between 0% and 100% if the average ROE is greater than 7% and less than 18%; and

 

is equal to 100% if the average ROE is greater than or equal to 18%.

The Board of Directors decided also that, for each for each beneficiary (other than the Chairman and Chief Executive Officer and the senior executives) of more than 100 shares, the shares in excess of this number will be finally granted subject to the performance condition mentioned before.

In addition, as part of the 2011 plan, the Board of Directors decided that the number of performance share finally granted to the Chairman and Chief Executive Officer will be subject to two performance conditions:

 

 

For 50% of the share granted, the performance condition states that the number of shares finally granted is based on the average ROE of the Group. The average ROE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate is equal to zero if the average ROE is less than or equal to 7%; varies on a straight-line basis between 0% and 100% if the average ROE is more than 7% and less than 18%; and is equal to 100% if the average ROE is more than or equal to 18%.

 

 

For 50% of the share granted, the performance condition states that the number of shares finally

 

 

F-68


Table of Contents
   

granted is based on the average ROACE of the Group. The average ROACE is calculated by the Group from the consolidated balance sheet and statement of income of the Group for fiscal years 2011 and 2012. The acquisition rate is equal to zero if the average ROACE is less than or equal to 6%; varies on a straight-line basis between 0% and 100% if the average ROACE is more than 6% and less than 15%; and is equal to 100% if the average ROACE is more than or equal to 15%.

2010 Plan

For the 2010 Plan, the Board of Directors decided that, for each beneficiary of more than 100 shares, half of the shares in excess of this number will be finally granted subject to a performance condition. This condition is based on the average ROE calculated by the Group based on TOTAL’s consolidated balance sheet and statement of income for fiscal years 2010 and 2011. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

 

varies on a straight-line basis between 0% and 100% if the average ROE is greater than 7% and less than 18%; and

 

is equal to 100% if the average ROE is greater than or equal to 18%.

2009 Plan

For the 2009 Plan, the Board of Directors decided that, for each beneficiary of more than 100 shares, half of the shares in excess of this number will be finally granted subject to a performance condition. This condition states that the number of shares finally granted is based on the average ROE as published by the Group and calculated based on the Group’s consolidated balance sheet and statement of income for fiscal years 2009 and 2010. The acquisition rate:

 

 

is equal to zero if the average ROE is less than or equal to 7%;

 

 

varies on a straight-line basis between 0% and 100% if the average ROE is greater than 7% and less than 18%; and

 

 

is equal to 100% if the average ROE is greater than or equal to 18%.

Due to the application of the performance condition, the acquisition rate was 100% for the 2009 Plan.

 

 

E.   GLOBAL FREE TOTAL SHARE PLAN

The Board of Directors approved at its meeting on May 21, 2010 the implementation and conditions of a global free share plan intended for the Group employees. On June 30, 2010, entitlement rights to 25 free shares were granted to every employee. The final grant is subject to a continued employment condition during the plan’s vesting period. The shares are not subject to any performance condition. Following the vesting period, the shares awarded will be new shares.

 

      2010 Plan
(2+2)
    2010 Plan
(4+0)
    Total  

Date of the shareholders’ meeting

     05/16/2008        05/16/2008     

Date of the award(a)

     06/30/2010        06/30/2010     

Date of the final award

     07/01/2012        07/01/2014     

Transfer authorized as from

     07/01/2014        07/01/2014           

Number of free shares

      

Outstanding as of January 1, 2010

      

Notified

     1,508,850        1,070,650        2,579,500   

Cancelled

     (125     (75     (200 ) 

Finally granted(b)

     (75            (75 ) 

Outstanding as of January 1, 2011

     1,508,650        1,070,575        2,579,225   

Notified

                     

Cancelled

     (29,175     (54,625     (83,800 ) 

Finally granted(b)

     (475     (425     (900 ) 

Outstanding as of December 31, 2011

     1,479,000        1,015,525        2,494,525   

 

(a) The June 30, 2010, grant was decided by the Board of Directors on May 21, 2010.
(b) Final grant following the death or disability of the beneficiary of the shares.

 

F-69


Table of Contents
F.   SUNPOWER PLANS

SunPower has three stock incentive plans: the 1996 Stock Plan (“1996 Plan”), the Second Amended and Restated 2005 SunPower Corporation Stock Incentive Plan (“2005 Plan”) and the PowerLight Corporation Common Stock Option and Common Stock Purchase Plan (“PowerLight Plan”). The PowerLight Plan was assumed by SunPower by way of the acquisition of PowerLight in fiscal 2007. Under the terms of all three plans, SunPower may issue incentive or non-statutory stock options or stock purchase rights to directors, employees and consultants to purchase common stock. The 2005 Plan was adopted by SunPower’s Board of Directors in August 2005, and was approved by shareholders in November 2005. The 2005 Plan replaced the 1996 Plan and allows not only for the grant of options, but also for the grant of stock appreciation rights, restricted stock grants, restricted stock units and other equity rights. The 2005 Plan also allows for tax withholding obligations related to stock option exercises or restricted stock awards to be satisfied through the retention of shares otherwise released upon vesting. The PowerLight Plan was adopted by PowerLight’s Board of Directors in October 2000.

In May 2008, SunPower’s stockholders approved an automatic annual increase available for grant under the 2005 Plan, beginning in fiscal 2009. The automatic annual increase is equal to the lower of three percent of the outstanding shares of all classes of SunPower’s common stock measured on the last day of the immediately preceding fiscal quarter, 6.0 million shares, or such other

number of shares as determined by SunPower’s Board of Directors. As of January 1, 2012, approximately 3.3 million shares were available for grant under the 2005 Plan. No new awards are being granted under the 1996 Plan or the PowerLight Plan.

Incentive stock options may be granted at no less than the fair value of the common stock on the date of grant. Non-statutory stock options and stock purchase rights may be granted at no less than 85% of the fair value of the common stock at the date of grant. The options and rights become exercisable when and as determined by SunPower’s Board of Directors, although these terms generally do not exceed ten years for stock options. Under the 1996 and 2005 Plans, the options typically vest over five years with a one-year cliff and monthly vesting thereafter. Under the PowerLight Plan, the options typically vest over five years with yearly cliff vesting. Under the 2005 Plan, the restricted stock grants and restricted stock units typically vest in three equal installments annually over three years.

The majority of shares issued are net of the minimum statutory withholding requirements that SunPower pays on behalf of its employees. During the six months ended January 1, 2012 SunPower withheld 221,262 shares to satisfy the employees’ tax obligations. SunPower pays such withholding requirements in cash to the appropriate taxing authorities. Shares withheld are treated as common stock repurchases for accounting and disclosure purposes and reduce the number of shares outstanding upon vesting.

 

 

The following table summarizes SunPower’s stock option activities:

 

      Outstanding Stock Options  

  

   Shares
(in thousands)
    Weighted-Average
Exercise Price
Per Share
(in dollars)
     Weighted-Average
Remaining
Contractual Term
(in years)
     Aggregate
Intrinsic Value
(in thousands
dollars)
 

Outstanding as of July 3, 2011

     519        25.39         

Exercised

     (29     3.93         

Forfeited

     (6     31.29         
  

 

 

       

Outstanding as of January 1, 2012

     484        26.62         4.71         480   
  

 

 

       

Exercisable as of January 1, 2012

     441        24.52         4.53         480   

Expected to vest after January 1, 2012

     40        48.08         6.64           

 

The intrinsic value of options exercised in the six months ended January 1, 2012 was $0.3 million. There were no stock options granted in the six months ended January 1, 2012.

The aggregate intrinsic value in the preceding table represents the total pre-tax intrinsic value, based on

SunPower’s closing stock price of $6.23 at December 30, 2011, which would have been received by the option holders had all option holders exercised their options as of that date. The total number of in-the-money options exercisable was 0.1 million shares as of January 1, 2012.

 

 

F-70


Table of Contents

The following table summarizes SunPower’s non-vested stock options and restricted stock activities thereafter:

 

      Stock Options      Restricted Stock Awards and Units  

  

   Shares
(in thousands)
    Weighted-Average
Exercise Price
Per Share
(in dollars)
     Shares
(in thousands)
    Weighted-Average
Grant Date Fair
Value Per Share
(in dollars)
(1)
 

Outstanding as of July 3, 2011

     67        41.34         7,198        16.03   

Granted

                    2,336        6.91   

Vested(2)

     (19     28.73         (691     18.96   

Forfeited

     (5     31.29         (1,473     14.10   

Outstanding as of December 31, 2011

     43        48.33         7,370        13.25   

 

(1) The Company estimates the fair value of the restricted stock unit awards as the stock price on the grant date.
(2) Restricted stock awards and units vested include shares withheld on behalf of employees to satisfy the minimum statutory tax withholding requirements.

 

G.   SHARE-BASED PAYMENT EXPENSE

Share-based payment expense before tax for the year 2011 amounts to 178 million and is broken down as follows:

 

 

27 million for TOTAL share subscription plans;

 

 

134 million for TOTAL restricted shares plans; and

 

 

17 million for SunPower plans.

Share-based payment expense before tax for the year 2010 amounted to 140 million and was broken down as follows:

 

 

31 million for TOTAL share subscription plans; and

 

 

109 million for TOTAL restricted shares plans.

Share-based payment expense before tax for the year 2009 amounted to 106 million and was broken down as follows:

 

 

38 million for TOTAL share subscription plans; and

 

 

68 million for TOTAL restricted shares plans.

The fair value of the options granted in 2011, 2010 and 2009 has been measured according to the Black-Scholes method and based on the following assumptions:

 

For the year ended December 31,    2011      2010      2009  

Risk free interest rate (%)(a)

     2.0         2.1         2.9   

Expected dividends (%)(b)

     5.6         5.9         4.8   

Expected volatility (%)(c)

     27.5         25.0         31.0   

Vesting period (years)

     2         2         2   

Exercice period (years)

     8         8         8   

Fair value of the granted options
( per option)

     4.4         5.8         8.4   

 

(a) Zero coupon Euro swap rate at 6 years.
(b) The expected dividends are based on the price of TOTAL share derivatives traded on the markets.
(c) The expected volatility is based on the implied volatility of TOTAL share options and of share indices options traded on the markets.

At the shareholders’ meeting held on May 21, 2010, the shareholders delegated to the Board of Directors the authority to increase the share capital of the Company in

one or more transactions and within a maximum period of 26 months from the date of the meeting, by an amount not exceeding 1.5% of the share capital outstanding on the date of the meeting of the Board of Directors at which a decision to proceed with an issuance is made reserving subscriptions for such issuance to the Group employees participating in a company savings plan. It is being specified that the amount of any such capital increase reserved for Group employees was counted against the aggregate maximum nominal amount of share capital increases authorized by the shareholders’ meeting held on May 21, 2010 for issuing new ordinary shares or other securities granting immediate or future access to the Company’s share capital with preferential subscription rights (2.5 billion in nominal value).

Pursuant to this delegation of authorization, the Board of Directors, during its October 28, 2010 meeting, implemented a capital increase reserved for employees within the limit of 12 million shares, with dividend rights as of the January 1, 2010 and delegated all power to the Chairman and Chief Executive Officer to determine the opening and closing of subscription period and the subscription price.

On March 14, 2011, the Chairman and Chief Executive Officer decided that the subscription period would be set from March 16, 2011 to April 1, 2011 and acknowledged that the subscription price per ordinary share would be set at 34.80. During this capital increase, 8,902,717 TOTAL shares were subscribed and created on April 28, 2011.

The cost of capital increases reserved for employees is reduced to take into account the non-transferability of the shares that could be subscribed by the employees over a period of five years. The valuation method of non-transferability of the shares is based on a strategy cost in two steps consisting, first, in a five years forward sale of the non-transferable shares, and second, in purchasing the same number of shares in cash with a loan financing reimbursable “in fine”. During the year 2011, the main

 

 

F-71


Table of Contents

assumptions used for the valuation of the cost of capital increase reserved for employees were the following:

 

For the year ended December 31,    2011  

Date of the Board of Directors meeting that decided the issue

     October 28, 2010   

Subscription price ()

     34.80   

Share price at the reference date ()(a)

     41.60   

Number of shares (in millions)

     8.90   

Risk free interest rate (%)(b)

     2.82   

Employees loan financing rate (%)(c)

     7.23   

Non transferability cost (% of the reference’s share price)

     17.6   

 

(a) Share price at the date which the Chairman and Chief Executive Officer decided the subscription period.
(b) Zero coupon Euro swap rate at 5 years.
(c) The employees loan financing rate is based on a 5-year consumer’s credit rate.

Due to the fact that the non-transferability cost is higher than the discount, no cost has been accounted to the fiscal year 2011.

26) PAYROLL AND STAFF

 

For the year ended
December 31,
   2011      2010      2009  

Personnel expenses (M)

        

Wages and salaries (including social charges)

     6,579         6,246         6,177   

Group employees

        

France

        

• Management

     11,123         10,852         10,906   

• Other

     23,914         24,317         25,501   

International

        

• Management

     15,713         15,146         15,243   

• Other

     45,354         42,540         44,737   

Total

     96,104         92,855         96,387   

The number of employees includes only employees of fully consolidated subsidiaries.

The increase in the number of employees between December 31, 2011 and December 31, 2010 is mainly explained by the acquisition of SunPower, partially compensated by the sale of the photocure and coatings resins businesses (see Note 3 to the Consolidated Financial Statements).

27) STATEMENT OF CASH FLOWS

 

A)   CASH FLOW FROM OPERATING ACTIVITIES

The following table gives additional information on cash paid or received in the cash flow from operating activities:

 

For the year ended
December 31, (M)
   2011     2010     2009  

Interests paid

     (679     (470     (678

Interests received

     277        132        148   

Income tax paid(a)

     (12,061     (8,848     (7,027

Dividends received

     2,133        1,722        1,456   

 

(a) These amounts include taxes paid in kind under production-sharing contracts in the exploration-production.

Changes in working capital are detailed as follows:

 

For the year ended
December 31, (M)
   2011     2010     2009  

Inventories

     (1,845     (1,896     (4,217

Accounts receivable

     (1,287     (2,712     (344

Other current assets

     (2,409     911        1,505   

Accounts payable

     2,646        2,482        571   

Other creditors and accrued liabilities

     1,156        719        (831

Net amount

     (1,739     (496     (3,316

 

B)   Cash flow used in financing activities

Changes in non-current financial debt are detailed in the following table under a net value due to the high number of multiple drawings:

 

For the year ended
December 31, (M)
   2011     2010     2009  

Issuance of non-current debt

     4,234        3,995        6,309   

Repayment of non-current debt

     (165     (206     (787

Net amount

     4,069        3,789        5,522   

 

C)   Cash and cash equivalents

Cash and cash equivalents are detailed as follows:

 

For the year ended
December 31, (M)
   2011      2010      2009  

Cash

     4,715         4,679         2,448   

Cash equivalents

     9,310         9,810         9,214   

Total

     14,025         14,489         11,662   

Cash equivalents are mainly composed of deposits less than three months deposited in government institutions or deposit banks selected in accordance with strict criteria.

 

 

F-72


Table of Contents

28) FINANCIAL ASSETS AND LIABILITIES ANALYSIS PER INSTRUMENTS CLASS AND STRATEGY

The financial assets and liabilities disclosed in the balance sheet are detailed as follows:

 

     Financial instruments related to financing and trading activities     Other financial
instruments
    Total     Fair
value
 
    Amortized
cost
    Fair value                       
As of  December 31, 2011 (M) Assets / (Liabilities)          Available
for sale
(a)
    Held for
trading
    Financial
debt
(b)
    Hedging of
financial debt
    Cash flow
hedge
    Net investment
hedge and other
                      

Equity affiliates: loans

    2,246                      2,246        2,246   

Other investments

      3,674                    3,674        3,674   

Hedging instruments of non-current financial debt

            1,971        5            1,976        1,976   

Other non-current assets

    2,055                      2,055        2,055   

Accounts receivable, net

                  20,049        20,049        20,049   

Other operating receivables

        1,074                6,393        7,467        7,467   

Current financial assets

    146          159          383        12                 700        700   

Cash and cash equivalents

                                                            14,025        14,025        14,025   

Total financial assets

    4,447        3,674        1,233               2,354        17               40,467        52,192        52,192   

Total non-financial assets

                                                                    111,857           

Total assets

                                                                    164,049           

Non-current financial debt

    (4,858         (17,551     (97     (49       (2     (22,557 )      (23,247 ) 

Accounts payable

                  (22,086     (22,086 )      (22,086 ) 

Other operating liabilities

        (606             (4,835     (5,441 )      (5,441 ) 

Current borrowings

    (6,158         (3,517             (9,675 )      (9,675 ) 

Other current financial liabilities

                    (87             (40     (14     (26             (167 )      (167 ) 

Total financial liabilities

    (11,016            (693     (21,068     (137     (63     (26     (26,923     (59,926     (60,616

Total non-financial liabilities

                                                                    (104,123        

Total liabilities

                                                                    (164,049        

 

(a) Financial assets available for sale are measured at their fair value except for unlisted securities (see Note 1 paragraph M(ii) and Note 13 to the Consolidated Financial Statements).
(b) The financial debt is adjusted to the hedged risks value (currency and interest rate) as part of hedge accounting (see Note 1 paragraph M(iii) to the Consolidated Financial Statements).

 

F-73


Table of Contents
     Financial instruments related to financing and trading activities     Other financial
instruments
    Total     Fair
value
 
    Amortized
cost
           Fair value                                     
As of December 31, 2010 (M) Assets / (Liabilities)          Available
for sale(a)
    Held for
trading
    Financial
debt(b)
    Hedging of
financial debt
    Cash flow
hedge
    Net investment
hedge and other
                      

Equity affiliates: loans

    2,383                      2,383        2,383   

Other investments

      4,590                    4,590        4,590   

Hedging instruments of non-current financial debt

            1,814        56            1,870        1,870   

Other non-current assets

    1,596                      1,596        1,596   

Accounts receivable, net

                  18,159        18,159        18,159   

Other operating receivables

        499                3,908        4,407        4,407   

Current financial assets

    869          38          292          6          1,205        1,205   

Cash and cash equivalents

                                                            14,489        14,489        14,489   

Total financial assets

    4,848        4,590        537               2,106        56        6        36,556        48,699        48,699   

Total non-financial assets

                                                                    95,019           

Total assets

                                                                    143,718           

Non-current financial debt

    (3,186         (17,419     (178           (20,783     (21,172

Accounts payable

                  (18,450     (18,450     (18,450

Other operating liabilities

        (559             (3,015     (3,574     (3,574

Current borrowings

    (5,916         (3,737             (9,653     (9,653

Other current financial liabilities

                    (147             (12                            (159     (159

Total financial liabilities

    (9,102             (706     (21,156     (190                   (21,465     (52,619     (53,008

Total non-financial liabilities

                                                                    (91,099        

Total liabilities

                                                                    (143,718        

 

(a) Financial assets available for sale are measured at their fair value except for unlisted securities (see Note 1 paragraph M(ii) and Note 13 to the Consolidated Financial Statements).
(b) The financial debt is adjusted to the hedged risks value (currency and interest rate) as part of hedge accounting (see Note 1 paragraph M(iii) to the Consolidated Financial Statements).

 

F-74


Table of Contents
     Financial instruments related to financing and trading activities     Other financial
instruments
    Total     Fair
value
 
    Amortized
cost
           Fair value                                     
As of December 31, 2009 (M) Assets / (Liabilities)          Available
for sale(a)
    Held for
trading
    Financial
debt(b)
    Hedging of
financial debt
    Cash flow
hedge
    Net investment
hedge and other
                      

Equity affiliates: loans

    2,367                      2,367        2,367   

Other investments

      1,162                    1,162        1,162   

Hedging instruments of non-current financial debt

            889        136            1,025        1,025   

Other non-current assets

    1,284                      1,284        1,284   

Accounts receivable, net

                  15,719        15,719        15,719   

Other operating receivables

        1,029                4,116        5,145        5,145   

Current financial assets

    55          53          197          6          311        311   

Cash and cash equivalents

                                                            11,662        11,662        11,662   

Total financial assets

    3,706        1,162        1,082               1,086        136        6        31,497        38,675        38,675   

Total non-financial assets

                                                                    89,078           

Total assets

                                                                    127,753           

Non-current financial debt

    (2,089         (17,107     (241           (19,437     (19,905

Accounts payable

                  (15,383     (15,383     (15,383

Other operating liabilities

        (923             (3,783     (4,706     (4,706

Current borrowings

    (4,849         (2,145             (6,994     (6,994

Other current financial liabilities

                    (25             (97             (1             (123     (123

Total financial liabilities

    (6,938             (948     (19,252     (338            (1     (19,166     (46,643     (47,111

Total non-financial liabilities

                                                                    (81,110        

Total liabilities

                                                                    (127,753        

 

(a) Financial assets available for sale are measured at their fair value except for unlisted securities (see Note 1 paragraph M(ii) and Note 13 to the Consolidated Financial Statements).
(b) The financial debt is adjusted to the hedged risks value (currency and interest rate) as part of hedge accounting (see Note 1 paragraph M(iii) to the Consolidated Financial Statements).

 

F-75


Table of Contents

29) FAIR VALUE OF FINANCIAL INSTRUMENTS (EXCLUDING COMMODITY CONTRACTS)

 

A)   IMPACT ON THE STATEMENT OF INCOME PER NATURE OF FINANCIAL INSTRUMENTS

Operating assets and liabilities

The impact on the statement of income is detailed as follows:

 

For the year ended December 31,
(M)
   2011     2010     2009  

Assets available for sale (investments):

      

— dividend income on non-consolidated subsidiaries

     330        255        210   

— gains (losses) on disposal of assets

     103        60        6   

— other

     (29     (17     (18

Loans and receivables

     (34     90        41   

Impact on net operating income

     370        388        239   

The impact in the statement of income mainly includes:

 

 

Dividends and gains or losses on disposal of other investments classified as “Other investments”;

 

 

Financial gains and depreciation on loans related to equity affiliates, non-consolidated companies and on receivables reported in “Loans and receivables”.

Assets and liabilities from financing activities

The impact on the statement of income of financing assets and liabilities is detailed as follows:

 

For the year ended December 31,
(M)
   2011     2010     2009  

Loans and receivables

     271        133        158   

Financing liabilities and associated hedging instruments

     (730     (469     (563

Fair value hedge (ineffective portion)

     17        4        33   

Assets and liabilities held for trading

     2        (2     (26

Impact on the cost of net debt

     (440     (334     (398

The impact on the statement of income mainly includes:

 

 

Financial income on cash, cash equivalents, and current financial assets (notably current deposits

   

beyond three months) classified as “Loans and receivables”;

 

 

Financial expense of long term subsidiaries financing, associated hedging instruments (excluding ineffective portion of the hedge detailed below) and financial expense of short term financing classified as “Financing liabilities and associated hedging instruments”;

 

 

Ineffective portion of bond hedging; and

 

 

Financial income, financial expense and fair value of derivative instruments used for cash management purposes classified as “Assets and liabilities held for trading”.

Financial derivative instruments used for cash management purposes (interest rate and foreign exchange) are considered to be held for trading. Based on practical documentation issues, the Group did not elect to set up hedge accounting for such instruments. The impact on income of the derivatives is offset by the impact of loans and current liabilities they are related to. Therefore these transactions taken as a whole do not have a significant impact on the Consolidated Financial Statements.

 

B)   IMPACT OF THE HEDGING STRATEGIES

Fair value hedge

The impact on the statement of income of the bond hedging instruments which is recorded in the item “Financial interest on debt” in the Consolidated Statement of Income is detailed as follows:

 

For the year ended December 31,
(M)
   2011     2010     2009  

Revaluation at market value of bonds

     (301     (1,164     (183

Swap hedging of bonds

     318        1,168        216   

Ineffective portion of the fair value hedge

     17        4        33   

The ineffective portion is not representative of the Group’s performance considering the Group’s objective to hold swaps to maturity. The current portion of the swaps valuation is not subject to active management.

 

 

F-76


Table of Contents

Net investment hedge

These instruments are recorded directly in shareholders’ equity under “Currency translation adjustments”. The variations of the period are detailed in the table below:

 

For the year ended December 31, (M)    As of January 1,     Variations     Disposals      As of December 31,  

2011

     (243     139                (104

2010

     25        (268             (243

2009

     124        (99             25   

As of December 31, 2011, the fair value of the open instruments amounts to (26) million compared to 6 million in 2010 and 5 million in 2009.

Cash flow hedge

The impact on the statement of income and on equity of the hedging instruments qualified as cash flow hedges is detailed as follows:

 

For the year ended December 31, (M)    2011     2010     2009  

Profit (Loss) recorded in equity during the period

     (84     (80     128   

Recycled amount from equity to the income statement during the period

     (47     (115     221   

As of December 31, 2011, 2010 and 2009, the ineffective portion of these financial instruments is equal to zero.

 

F-77


Table of Contents
C)   MATURITY OF DERIVATIVE INSTRUMENTS

The maturity of the notional amounts of derivative instruments, excluding the commodity contracts, is detailed in the following table:

 

As of December 31, 2011 (M)

Assets / (Liabilities)

   Fair
value
    Notional value(a)  
     Total      2012      2013      2014      2015      2016      2017
and
after
 

Fair value hedge

                      

Swaps hedging fixed-rates bonds (liabilities)

     (97     1,478                     

Swaps hedging fixed-rates bonds (assets)

     1,971        15,653                                                         

Total swaps hedging fixed-rates bonds (assets and liabilities)

     1,874        17,131            4,204         4,215         3,380         1,661         3,671   

Swaps hedging fixed-rates bonds (current portion) (liabilities)

     (40     642                     

Swaps hedging fixed-rates bonds (current portion) (assets)

     383        2,349                                                         

Total swaps hedging fixed-rates bonds (current portion) (assets and liabilities)

     343        2,991         2,991                  

Cash flow hedge

                      

Swaps hedging fixed-rates bonds (liabilities)

     (49     967                     

Swaps hedging fixed-rates bonds (assets)

     5        749                                                         

Total swaps hedging fixed-rates bonds (assets and liabilities)

     (44     1,716                                            1,716   

Swaps hedging fixed-rates bonds (current portion) (liabilities)

     (14     582                     

Swaps hedging fixed-rates bonds (current portion) (assets)

     12        908                                                         

Total swaps hedging fixed-rates bonds (current portion) (assets and liabilities)

     (2     1,490         1,490                  

Net investment hedge

                      

Currency swaps and forward exchange contracts (assets)

                                

Currency swaps and forward exchange contracts (liabilities)

     (26     881                                                         

Total swaps hedging net investments

     (26     881         881                  

Held for trading

                      

Other interest rate swaps (assets)

     1        3,605                     

Other interest rate swaps (liabilities)

     (2     14,679                                                         

Total other interest rate swaps (assets and liabilities)

     (1     18,284         18,284                                           

Currency swaps and forward exchange contracts (assets)

     158        6,984                     

Currency swaps and forward exchange contracts (liabilities)

     (85     4,453                                                         

Total currency swaps and forward exchange contracts (assets and liabilities)

     73        11,437         11,176         80         58         36         31         56   

 

(a) These amounts set the levels of notional commitment and are not indicative of a contingent gain or loss.

 

F-78


Table of Contents

As of December 31, 2010 (M)

Assets / (Liabilities)

          Notional value(a)  
   Fair
value
    Total      2011      2012      2013      2014      2015      2016
and
after
 

Fair value hedge

                      

Swaps hedging fixed-rates bonds (liabilities)

     (178     2,244                     

Swaps hedging fixed-rates bonds (assets)

     1,814        13,939                                                         

Total swaps hedging fixed-rates bonds (assets and liabilities)

     1,636        16,183            2,967         3,461         2,421         3,328         4,006   

Swaps hedging fixed-rates bonds (current portion) (liabilities)

     (12     592                     

Swaps hedging fixed-rates bonds (current portion) (assets)

     292        2,815                                                         

Total swaps hedging fixed-rates bonds (current portion) (assets and liabilities)

     280        3,407         3,407                  

Cash flow hedge

                      

Swaps hedging fixed-rates bonds (liabilities)

                                

Swaps hedging fixed-rates bonds (assets)

     56        1,957                                                         

Total swaps hedging fixed-rates bonds (assets and liabilities)

     56        1,957            295                  1,662   

Swaps hedging fixed-rates bonds (current portion) (liabilities)

                      

Swaps hedging fixed-rates bonds (current portion) (assets)

                                                                      

Total swaps hedging fixed-rates bonds (current portion) (assets and liabilities)

                                     

Net investment hedge

                      

Currency swaps and forward exchange contracts (assets)

     6        381                     

Currency swaps and forward exchange contracts (liabilities)

                                                                    

Total swaps hedging net investments

     6        381         381                  

Held for trading

                      

Other interest rate swaps (assets)

     1        6,463                     

Other interest rate swaps (liabilities)

     (3     11,395                                                         

Total other interest rate swaps (assets and liabilities)

     (2     17,858         17,667         189                         2           

Currency swaps and forward exchange contracts (assets)

     37        1,532                     

Currency swaps and forward exchange contracts (liabilities)

     (144     6,757                                                         

Total currency swaps and forward exchange contracts (assets and liabilities)

     (107     8,289         8,102                 25         49         31         82   

 

(a) These amounts set the levels of notional commitment and are not indicative of a contingent gain or loss.

 

F-79


Table of Contents

As of December 31, 2009 (M)

Assets / (Liabilities)

          Notional value(a)  
   Fair
value
    Total      2010      2011      2012      2013      2014      2015
and
after
 

Fair value hedge

                      

Swaps hedging fixed-rates bonds (liabilities)

     (241     4,615                     

Swaps hedging fixed-rates bonds (assets)

     889        11,076                                                         

Total swaps hedging fixed-rates bonds (assets and liabilities)

     648        15,691                 3,345         2,914         3,450         1,884         4,098   

Swaps hedging fixed-rates bonds (current portion) (liabilities)

     (97     912                     

Swaps hedging fixed-rates bonds (current portion) (assets)

     197        1,084                                                         

Total swaps hedging fixed-rates bonds (current portion) (assets and liabilities)

     100        1,996         1,996                  

Cash flow hedge

                      

Swaps hedging fixed-rates bonds (liabilities)

                      

Swaps hedging fixed-rates bonds (assets)

     136        1,837                           295                           1,542   

Total swaps hedging fixed-rates bonds (assets and liabilities)

     136        1,837               295               1,542   

Swaps hedging fixed-rates bonds (current portion) (liabilities)

                      

Swaps hedging fixed-rates bonds (current portion) (assets)

                                                                      

Total swaps hedging fixed-rates bonds (current portion) (assets and liabilities)

                      

Net investment hedge

                      

Currency swaps and forward exchange contracts (assets)

     6        701                     

Currency swaps and forward exchange contracts (liabilities)

     (1     224                                                         

Total swaps hedging net investments

     5        925         925                  

Held for trading

                      

Other interest rate swaps (assets)

       1,459                     

Other interest rate swaps (liabilities)

     (1     10,865                                                         

Total other interest rate swaps (assets and liabilities)

     (1     12,324         12,208         114                  2   

Currency swaps and forward exchange contracts (assets)

     53        4,017                     

Currency swaps and forward exchange contracts (liabilities)

     (24     3,456                                                         

Total currency swaps and forward exchange contracts (assets and liabilities)

     29        7,473         7,224                  52         50         47         100   

 

(a) These amounts set the levels of notional commitment and are not indicative of a contingent gain or loss.

 

D)   FAIR VALUE HIERARCHY

The fair value hierarchy for financial instruments excluding commodity contracts is as follows:

 

As of December 31, 2011 (M)    Quoted prices in
active markets
for identical
assets
(level 1)
     Prices based on
observable data
(level 2)
    Prices based on non-
observable data
(level 3)
     Total  

Fair value hedge instruments

             2,217                2,217   

Cash flow hedge instruments

             (46             (46

Net investment hedge instruments

             (26             (26

Assets and liabilities held for trading

             72                72   

Assets available for sale

     2,575                        2,575   

Total

     2,575         2,217                4,792   

 

F-80


Table of Contents
As of December 31, 2010 (M)    Quoted prices in
active markets
for identical
assets
(level 1)
     Prices based on
observable data
(level 2)
    Prices based on
non-observable
data
(level 3)
     Total  

Fair value hedge instruments

             1,916                1,916   

Cash flow hedge instruments

             56                56   

Net investment hedge instruments

             6                6   

Assets and liabilities held for trading

             (109             (109

Assets available for sale

     3,631                        3,631   

Total

     3,631         1,869                5,500   

 

As of December 31, 2009 (M)    Quoted prices in
active markets
for identical
assets
(level 1)
     Prices based on
observable data
(level 2)
     Prices based on
non-observable
data
(level 3)
     Total  

Fair value hedge instruments

             748                 748   

Cash flow hedge instruments

             136                 136   

Net investment hedge instruments

             5                 5   

Assets and liabilities held for trading

             28                 28   

Assets available for sale

     232                         232   

Total

     232         917                 1,149   

The description of each fair value level is presented in Note 1 paragraph M(v) to the Consolidated Financial Statements.

30) FINANCIAL INSTRUMENTS RELATED TO COMMODITY CONTRACTS

Financial instruments related to oil, gas and power activities as well as related currency derivatives are recorded at fair value under “Other current assets” or “Other creditors and accrued liabilities” depending on whether they are assets or liabilities.

 

As of December 31, 2011 (M)               

Assets / (Liabilities)

   Carrying amount     Fair value(b)  

Crude oil, petroleum products and freight rates activities

    

Petroleum products and crude oil swaps

     3        3   

Freight rate swaps

              

Forwards(a)

     (16     (16

Options

     (4     (4

Futures

     (14     (14

Options on futures

     (6     (6

Total crude oil, petroleum products and freight rates

     (37     (37

Gas & Power activities

    

Swaps

     57        57   

Forwards(a)

     452        452   

Options

     (3     (3

Futures

              

Total Gas & Power

     506        506   

Total

     469        469   

Total of fair value non-recognized in the balance sheet

         

 

(a) Forwards: contracts resulting in physical delivery are accounted for as derivative commodity contracts and included in the amounts shown.
(b) When the fair value of derivatives listed on an organized exchange market (futures, options on futures and swaps) is offset with the margin call received or paid in the balance sheet, this fair value is set to zero.

 

F-81


Table of Contents

As of December 31, 2010 (M)

Assets / (Liabilities)

   Carrying amount     Fair value(b)  

Crude oil, petroleum products and freight rates activities

    

Petroleum products and crude oil swaps

     (2     (2

Freight rate swaps

              

Forwards(a)

     5        5   

Options

     51        51   

Futures

     (12     (12

Options on futures

     (4     (4

Total crude oil, petroleum products and freight rates

     38        38   

Gas & Power activities

    

Swaps

     (1     (1

Forwards(a)

     (102     (102

Options

     5        5   

Futures

              

Total Gas & Power

     (98     (98

Total

     (60     (60

Total of fair value non-recognized in the balance sheet

         

 

(a) Forwards: contracts resulting in physical delivery are accounted for as derivative commodity contracts and included in the amounts shown.
(b) When the fair value of derivatives listed on an organized exchange market (futures, options on futures and swaps) is offset with the margin call received or paid in the balance sheet, this fair value is set to zero.

 

As of December 31, 2009 (M)

Assets / (Liabilities)

   Carrying amount     Fair value(b)  

Crude oil, petroleum products and freight rates activities

    

Petroleum products and crude oil swaps

     (29     (29

Freight rate swaps

              

Forwards(a)

     (9     (9

Options

     21        21   

Futures

     (17     (17

Options on futures

     6        6   

Total crude oil, petroleum products and freight rates

     (28     (28

Gas & Power activities

    

Swaps

     52        52   

Forwards(a)

     78        78   

Options

     4        4   

Futures

              

Total Gas & Power

     134        134   

Total

     106        106   

Total of fair value non-recognized in the balance sheet

         

 

(a) Forwards: contracts resulting in physical delivery are accounted for as derivative commodity contracts and included in the amounts shown.
(b) When the fair value of derivatives listed on an organized exchange market (futures, options on futures and swaps) is offset with the margin call received or paid in the balance sheet, this fair value is set to zero.

Most commitments on crude oil and refined products have a short term maturity (less than one year). The maturity of most Gas & Power energy derivatives is less than three years forward.

The changes in fair value of financial instruments related to commodity contracts are detailed as follows:

 

For the year ended December 31, (M)   

Fair value

as of  January 1,

   

Impact on

income

    

Settled

contracts

    Other    

Fair value

as of  December 31,

 

Crude oil, petroleum products and freight rates activities

                                         

2011

     38        1,572         (1,648     1        (37

2010

     (28     1,556         (1,488     (2     38   

2009

     39        1,713         (1,779     (1     (28

Gas & Power activities

                                         

2011

     (98     899         (295     0        506   

2010

     134        410         (648     6        (98

2009

     592        327         (824     39        134   

 

F-82


Table of Contents

The fair value hierarchy for financial instruments related to commodity contracts is as follows:

 

As of December 31, 2011 (M)   

Quoted prices

in active  markets for

identical

assets (level 1)

   

Prices based on

observable data

(level 2)

    

Prices based on

non-observable

data (level 3)

     Total  

Crude oil, petroleum products and freight rates activities

     (38     1                 (37

Gas & Power activities

     (44     550                 506   

Total

     (82     551                 469   

 

As of December 31, 2010 (M)   

Quoted prices

in active  markets for
identical

assets (level 1)

   

Prices based on

observable data

(level 2)

   

Prices based on

non-observable
data (level 3)

     Total  

Crude oil, petroleum products and freight rates activities

     (10     48                38   

Gas & Power activities

     50        (148             (98

Total

     40        (100             (60

 

As of December 31, 2009 (M)   

Quoted prices

in active  markets for

identical

assets (level 1)

   

Prices based on

observable data

(level 2)

   

Prices based on

non-observable

data (level 3)

     Total  

Crude oil, petroleum products and freight rates activities

     (45     17                (28

Gas & Power activities

     140        (6             134   

Total

     95        11                106   

The description of each fair value level is presented in Note 1 paragraph M(v) to the Consolidated Financial Statements.

 

31) FINANCIAL RISKS MANAGEMENT

Oil and gas market related risks

Due to the nature of its business, the Group has significant oil and gas trading activities as part of its day-to-day operations in order to optimize revenues from its oil and gas production and to obtain favorable pricing to supply its refineries.

In its international oil trading business, the Group follows a policy of not selling its future production. However, in connection with this trading business, the Group, like most other oil companies, uses energy derivative instruments to adjust its exposure to price fluctuations of crude oil, refined products, natural gas, power and coal. The Group also uses freight rate derivative contracts in its shipping business to adjust its exposure to freight-rate fluctuations. To hedge against this risk, the Group uses various instruments such as futures, forwards, swaps and options on organised markets or over-the-counter markets. The list of the different derivatives held by the Group in these markets is detailed in Note 30 to the Consolidated Financial Statements.

The Trading & Shipping division measures its market risk exposure, i.e. potential loss in fair values, on its crude oil, refined products and freight rates trading activities using a value-at-risk technique. This technique is based on an historical model and makes an assessment of the market risk arising from possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair values takes into account a

snapshot of the end-of-day exposures and the set of historical price movements for the last 400 business days for all instruments and maturities in the global trading activities. Options are systematically reevaluated using appropriate models.

The potential movement in fair values corresponds to a 97.5% value-at-risk type confidence level. This means that the Group’s portfolio result is likely to exceed the value-at-risk loss measure once over 40 business days if the portfolio exposures were left unchanged.

Trading & Shipping : value-at-risk with a 97.5% probability

 

As of December 31,
(M)
   High      Low      Average      Year end  

2011

     10.6         3.7         6.1         6.3   

2010

     23.1         3.4         8.9         3.8   

2009

     18.8         5.8         10.2         7.6   

As part of its gas, power and coal trading activity, the Group also uses derivative instruments such as futures, forwards, swaps and options in both organised and over-the-counter markets. In general, the transactions are settled at maturity date through physical delivery. The Gas & Power division measures its market risk exposure, i.e. potential loss in fair values, on its trading business using a value-at-risk technique. This technique is based on an historical model and makes an assessment of the market risk arising from possible future changes in market values over a one-day period. The calculation of the range of potential changes in fair values takes into account a

 

 

F-83


Table of Contents

snapshot of the end-of-day exposures and the set of historical price movements for the past two years for all instruments and maturities in the global trading business.

Gas & Power trading : value-at-risk with a 97.5% probability

 

As of December 31,
(M)
   High      Low      Average      Year end  

2011

     21.0         12.7         16.0         17.6   

2010

     13.9         2.7         6.8         10.0   

2009

     9.8         1.9         5.0         4.8   

The Group has implemented strict policies and procedures to manage and monitor these market risks. These are based on the separation of control and front-office functions and on an integrated information system that enables real-time monitoring of trading activities.

Limits on trading positions are approved by the Group’s Executive Committee and are monitored daily. To increase flexibility and encourage liquidity, hedging operations are performed with numerous independent operators, including other oil companies, major energy producers or consumers and financial institutions. The Group has established counterparty limits and monitors outstanding amounts with each counterparty on an ongoing basis.

Financial markets related risks

As part of its financing and cash management activities, the Group uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Group may also use, on a less frequent basis, futures and options contracts. These operations and their accounting treatment are detailed in Notes 1 paragraph M, 20, 28 and 29 to the Consolidated Financial Statements.

Risks relative to cash management operations and to interest rate and foreign exchange financial instruments are managed according to rules set by the Group’s senior management, which provide for regular pooling of available cash balances, open positions and management of the financial instruments by the Treasury Department. Excess cash of the Group is deposited mainly in government institutions, deposit banks, or major companies through deposits, reverse repurchase agreements and purchase of commercial paper. Liquidity positions and the management of financial instruments are centralized by the Treasury Department, where they are managed by a team specialized in foreign exchange and interest rate market transactions.

The Cash Monitoring-Management Unit within the Treasury Department monitors limits and positions per bank on a daily basis and results of the Front Office. This unit also prepares marked-to-market valuations of used financial instruments and, when necessary, performs sensitivity analysis.

Counterparty risk

The Group has established standards for market transactions under which bank counterparties must be approved in advance, based on an assessment of the counterparty’s financial soundness (multi-criteria analysis including a review of market prices and of the Credit Default Swap (CDS), its ratings with Standard & Poor’s and Moody’s, which must be of high quality, and its overall financial condition).

An overall authorized credit limit is set for each bank and is allotted among the subsidiaries and the Group’s central treasury entities according to their needs.

To reduce the market values risk on its commitments, in particular for swaps set as part of bonds issuance, the Treasury Department also developed a system of margin call that is gradually implemented with significant counterparties.

Currency exposure

The Group seeks to minimize the currency exposure of each entity to its functional currency (primarily the euro, the dollar, the Canadian dollar, the pound sterling and the Norwegian krone).

For currency exposure generated by commercial activity, the hedging of revenues and costs in foreign currencies is typically performed using currency operations on the spot market and, in some cases, on the forward market. The Group rarely hedges future cash flows, although it may use options to do so.

With respect to currency exposure linked to non-current assets booked in a currency other than the euro, the Group has a policy of reducing the related currency exposure by financing these assets in the same currency.

Net short-term currency exposure is periodically monitored against limits set by the Group’s senior management.

The non-current debt described in Note 20 to the Consolidated Financial Statements is generally raised by the corporate treasury entities either directly in dollars, in euros or in Canadian dollars, or in other currencies which are then exchanged for dollars or euros through swaps issues to appropriately match general corporate needs. The proceeds from these debt issuances are loaned to

 

 

F-84


Table of Contents

affiliates whose accounts are kept in dollars, in Canadian dollars or in euros. Thus, the net sensitivity of these positions to currency exposure is not significant.

The Group’s short-term currency swaps, the notional value of which appears in Note 29 to the Consolidated Financial Statements, are used to attempt to optimize the centralized cash management of the Group. Thus, the sensitivity to currency fluctuations which may be induced is likewise considered negligible.

Short-term interest rate exposure and cash

Cash balances, which are primarily composed of euros and dollars, are managed according to the guidelines established by the Group’s senior management (maintain an adequate level of liquidity, optimize revenue from investments considering existing interest rate yield curves,

and minimize the cost of borrowing) over a less than twelve-month horizon and on the basis of a daily interest rate benchmark, primarily through short-term interest rate swaps and short-term currency swaps, without modifying currency exposure.

Interest rate risk on non-current debt

The Group’s policy consists of incurring non-current debt primarily at a floating rate, or, if the opportunity arises at the time of an issuance, at a fixed rate. Debt is incurred in dollars, in euros or in Canadian dollars according to general corporate needs. Long-term interest rate and currency swaps may be used to hedge bonds at their issuance in order to create a variable or fixed rate synthetic debt. In order to partially modify the interest rate structure of the long-term debt, TOTAL may also enter into long-term interest rate swaps.

 

 

Sensitivity analysis on interest rate and foreign exchange risk

The tables below present the potential impact of an increase or decrease of 10 basis points on the interest rate yield curves for each of the currencies on the fair value of the current financial instruments as of December 31, 2011, 2010 and 2009.

 

                    Change in fair
value due to a change
in interest rate by
 

Assets / (Liabilities) (M)

    
 
Carrying
amount
  
  
   
 
Estimated
fair value
  
  
   
 
+ 10 basis
points
  
  
   
 
- 10 basis
points
  
  

As of December 31, 2011

                                

Bonds (non-current portion, before swaps)

     (21,402     (22,092     83        (83

    Swaps hedging fixed-rates bonds (liabilities)

     (146     (146    

    Swaps hedging fixed-rates bonds (assets)

     1,976        1,976       

Total swaps hedging fixed-rates bonds (assets and liabilities)

     1,830        1,830        (49     49   

Current portion of non-current debt after swap (excluding capital lease obligations)

     3,488        3,488        3        (3

Other interest rates swaps

     (1     (1     3        (3

Currency swaps and forward exchange contracts

     47        47                 

As of December 31, 2010

                                

Bonds (non-current portion, before swaps)

     (20,019     (20,408     86        (84

    Swaps hedging fixed-rates bonds (liabilities)

     (178     (178    

    Swaps hedging fixed-rates bonds (assets)

     1,870        1,870       

Total swaps hedging fixed-rates bonds (assets and liabilities)

     1,692        1,692        (59     59   

Current portion of non-current debt after swap (excluding capital lease obligations)

     3,483        3,483        4        (4

Other interest rates swaps

     (2     (2     3        (3

Currency swaps and forward exchange contracts

     (101     (101              

As of December 31, 2009

                                

Bonds (non-current portion, before swaps)

     (18,368     (18,836     75        (75

    Swaps hedging fixed-rates bonds (liabilities)

     (241     (241    

    Swaps hedging fixed-rates bonds (assets)

     1,025        1,025       

Total swaps hedging fixed-rates bonds (assets and liabilities)

     784        784        (57     57   

Current portion of non-current debt after swap (excluding capital lease obligations)

     (2,111     (2,111     3        (3

Other interest rates swaps

     (1     (1     1        (1

Currency swaps and forward exchange contracts

     34        34                 

 

F-85


Table of Contents

The impact of changes in interest rates on the cost of net debt before tax is as follows:

 

For the year ended December 31, (M)    2011     2010     2009  

Cost of net debt

     (440     (334     (398

Interest rate translation of :

      

+ 10 basis points

     (10     (11     (11

- 10 basis points

     10        11        11   

+ 100 basis points

     (103     (107     (108

- 100 basis points

     103        107        108   

As a result of the policy for the management of currency exposure previously described, the Group’s sensitivity to currency exposure is primarily influenced by the net equity of the subsidiaries whose functional currency is the dollar and, to a lesser extent, the pound sterling, the Norwegian krone and the Canadian dollar.

This sensitivity is reflected in the historical evolution of the currency translation adjustment recorded in the statement of changes in shareholders’ equity which, in the course of the last three fiscal years, is essentially related to the fluctuation of dollar and pound sterling and is set forth in the table below:

 

      Euro / Dollar
exchange rates
     Euro / Pound sterling
exchange rates
 

As of December 31, 2011

     1.29         0.84   

As of December 31, 2010

     1.34         0.86   

As of December 31, 2009

     1.44         0.89   

 

As of December 31, 2011 (M)    Total     Euro      Dollar     Pound
sterling
    Other currencies and
equity affiliates
(a)
 

Shareholders’ equity at historical exchange rate

     69,025        41,396         21,728        4,713        1,188   

Currency translation adjustment before net investment hedge

     (962        127        (923     (166

Net investment hedge — open instruments

     (26        (25     (1       

Shareholders’ equity at exchange rate as of December 31, 2011

     68,037        41,396         21,830        3,789        1,022   
           
As of December 31, 2010 (M)    Total     Euro      Dollar     Pound
sterling
    Other currencies and
equity affiliates
(a)
 

Shareholders’ equity at historical exchange rate

     62,909        32,894         22,242        4,997        2,776   

Currency translation adjustment before net investment hedge

     (2,501             (1,237     (1,274     10   

Net investment hedge — open instruments

     6                6                 

Shareholders’ equity at exchange rate as of December 31, 2010

     60,414        32,894         21,011        3,723        2,786   
As of December 31, 2009 (M)    Total     Euro      Dollar     Pound
sterling
    Other currencies and
equity affiliates
 

Shareholders’ equity at historical exchange rate

     57,621        27,717         18,671        5,201        6,032   

Currency translation adjustment before net investment hedge

     (5,074             (3,027     (1,465     (582

Net investment hedge — open instruments

     5                6        (1       

Shareholders’ equity at exchange rate as of December 31, 2009

     52,552        27,717         15,650        3,735        5,450   

 

(a) The decrease in the heading “Other currencies and equity affiliates” is mainly explained by the change in the consolidation method of Sanofi (see Note 3 to the Consolidated Financial Statements). The contribution to the shareholders’ equity of this investment is now reclassified into the heading for the Eurozone.

As a result of this policy, the impact of currency exchange rate fluctuations on consolidated income, as illustrated in Note 7 to the Consolidated Financial Statements, has not been significant over the last three years despite the considerable fluctuation of the dollar (gain of 118 million in 2011, nil result in 2010, loss of 32 million in 2009).

Stock market risk

The Group holds interests in a number of publicly-traded companies (see Notes 12 and 13 to the Consolidated Financial Statements). The market value of these holdings fluctuates due to various factors, including stock market trends, valuations of the sectors in which the companies operate, and the economic and financial condition of each individual company.

Liquidity risk

TOTAL S.A. has confirmed lines of credit granted by international banks, which are calculated to allow it to manage its short-term liquidity needs as required.

 

F-86


Table of Contents

As of December 31, 2011, these lines of credit amounted to $10,139 million, of which $10,096 million was unused. The agreements for the lines of credit granted to TOTAL S.A. do not contain conditions related to the Company’s financial ratios, to its financial ratings from specialized agencies, or to the occurrence of events that could have a material adverse effect on its financial position. As of December 31, 2011, the aggregate amount of the principal confirmed lines of credit granted by international banks to Group companies, including TOTAL S.A., was $11,447 million, of which $11,154 million was unused. The lines of credit granted to Group companies other than TOTAL S.A. are not intended to finance the Group’s general needs; they are intended to finance either the general needs of the borrowing subsidiary or a specific project.

The following tables show the maturity of the financial assets and liabilities of the Group as of December 31, 2011, 2010 and 2009 (see Note 20 to the Consolidated Financial Statements).

 

As of December 31, 2011 (M)
Assets/(Liabilities)
   Less than
one year
    1-2 years     2-3 years     3-4 years     4-5 years     More than
5 years
    Total  

Non-current financial debt (notional value excluding interests)

       (4,492     (3,630     (3,614     (1,519     (7,326     (20,581

Current borrowings

     (9,675               (9,675

Other current financial liabilities

     (167               (167

Current financial assets

     700                  700   

Cash and cash equivalents

     14,025                                                14,025   

Net amount before financial expense

     4,883        (4,492     (3,630     (3,614     (1,519     (7,326     (15,698

Financial expense on non-current financial debt

     (785     (691     (521     (417     (302     (1,075     (3,791

Interest differential on swaps

     320        331        221        120        55        44        1,091   

Net amount

     4,418        (4,852     (3,930     (3,911     (1,766     (8,357     (18,398
                                                          
As of December 31, 2010
(M) Assets/(Liabilities)
   Less than
one year
    1-2 years     2-3 years     3-4 years     4-5 years     More than
5 years
    Total  

Non-current financial debt (notional value excluding interests)

       (3,355     (3,544     (2,218     (3,404     (6,392     (18,913

Current borrowings

     (9,653               (9,653

Other current financial liabilities

     (159               (159

Current financial assets

     1,205                  1,205   

Cash and cash equivalents

     14,489                                                14,489   

Net amount before financial expense

     5,882        (3,355     (3,544     (2,218     (3,404     (6,392     (13,031

Financial expense on non-current financial debt

     (843     (729     (605     (450     (358     (1,195     (4,180

Interest differential on swaps

     461        334        153        33        2        (78     905   

Net amount

     5,500        (3,750     (3,996     (2,635     (3,760     (7,665     (16,306
                                                          
As of December 31, 2009
(M) Assets/(Liabilities)
   Less than
one year
    1-2 years     2-3 years     3-4 years     4-5 years     More than
5 years
    Total  

Non-current financial debt (notional value excluding interests)

       (3,658     (3,277     (3,545     (2,109     (5,823     (18,412

Current borrowings

     (6,994               (6,994

Other current financial liabilities

     (123               (123

Current financial assets

     311                  311   

Cash and cash equivalents

     11,662                                                11,662   

Net amount before financial expense

     4,856        (3,658     (3,277     (3,545     (2,109     (5,823     (13,556

Financial expense on non-current financial debt

     (768     (697     (561     (448     (301     (1,112     (3,887

Interest differential on swaps

     447        233        100        25        (16     (55     734   

Net amount

     4,535        (4,122     (3,738     (3,968     (2,426     (6,990     (16,709

In addition, the Group guarantees bank debt and finance lease obligations of certain non-consolidated companies and equity affiliates. A payment would be triggered by failure of the guaranteed party to fulfill its obligation covered by the guarantee, and no assets are held as collateral for these guarantees. Maturity dates and amounts are set forth in Note 23 to the Consolidated Financial Statements (“Guarantees given against borrowings”).

The Group also guarantees the current liabilities of certain non-consolidated companies. Performance under these guarantees would be triggered by a financial default of these entities. Maturity dates and amounts are set forth in Note 23 to the Consolidated Financial Statements (“Guarantees of current liabilities”).

 

F-87


Table of Contents

The following table sets forth financial assets and liabilities related to operating activities as of December 31, 2011, 2010 and 2009 (see Note 28 to the Consolidated Financial Statements).

 

As of December 31 (M)
Assets/(Liabilities)
   2011     2010     2009  

Accounts payable

     (22,086     (18,450     (15,383

Other operating liabilities

     (5,441     (3,574     (4,706

    including financial instruments related to commodity contracts

     (606     (559     (923

Accounts receivable, net

     20,049        18,159        15,719   

Other operating receivables

     7,467        4,407        5,145   

    including financial instruments related to commodity contracts

     1,074        499        1,029   

Total

     (11     542        775   

These financial assets and liabilities mainly have a maturity date below one year.

Credit risk

Credit risk is defined as the risk of the counterparty to a contract failing to perform or pay the amounts due.

The Group is exposed to credit risks in its operating and financing activities. The Group’s maximum exposure to credit risk is partially related to financial assets recorded on its balance sheet, including energy derivative instruments that have a positive market value.

The following table presents the Group’s maximum credit risk exposure:

 

As of December 31, (M) Assets/
(Liabilities)
  2011     2010     2009  

Loans to equity affiliates (Note 12)

    2,246        2,383        2,367   

Loans and advances (Note 14)

    2,055        1,596        1,284   

Hedging instruments of non-current financial debt (Note 20)

    1,976        1,870        1,025   

Accounts receivable (Note 16)

    20,049        18,159        15,719   

Other operating receivables (Note 16)

    7,467        4,407        5,145   

Current financial assets (Note 20)

    700        1,205        311   

Cash and cash equivalents (Note 27)

    14,025        14,489        11,662   

Total

    48,518        44,109        37,513   

The valuation allowance on loans and advances and on accounts receivable and other operating receivables is detailed respectively in Notes 14 and 16 to the Consolidated Financial Statements.

As part of its credit risk management related to operating and financing activities, the Group has developed margin call contracts with certain counterparties. As of

December 31, 2011, the net amount received as part of these margin calls was 1,682 million (against 1,560 million as of December 31, 2010 and 693 million as of December 31, 2009).

Credit risk is managed by the Group’s business segments as follows:

 

 

Upstream Segment

 

   

Exploration & Production

Risks arising under contracts with government authorities or other oil companies or under long-term supply contracts necessary for the development of projects are evaluated during the project approval process. The long-term aspect of these contracts and the high-quality of the other parties lead to a low level of credit risk.

Risks related to commercial operations, other than those described above (which are, in practice, directly monitored by subsidiaries), are subject to procedures for establishing and reviewing credit.

Customer receivables are subject to provisions on a case-by-case basis, based on prior history and management’s assessment of the facts and circumstances.

 

   

Gas & Power

The Gas & Power division deals with counterparties in the energy, industrial and financial sectors throughout the world. Financial institutions providing credit risk coverage are highly rated international bank and insurance groups.

Potential counterparties are subject to credit assessment and approval before concluding transactions and are thereafter subject to regular review, including re-appraisal and approval of the limits previously granted.

The creditworthiness of counterparties is assessed based on an analysis of quantitative and qualitative data regarding financial standing and business risks, together with the review of any relevant third party and market information, such as data published by rating agencies. On this basis, credit limits are defined for each potential counterparty and, where appropriate, transactions are subject to specific authorisations.

Credit exposure, which is essentially an economic exposure or an expected future physical exposure, is permanently monitored and subject to sensitivity measures.

Credit risk is mitigated by the systematic use of industry standard contractual frameworks that permit netting, enable requiring added security in case of adverse change in the counterparty risk, and allow for termination of the contract upon occurrence of certain events of default.

 

 

F-88


Table of Contents
 

Downstream Segment

 

   

Refining & Marketing

Internal procedures for the Refining & Marketing division include rules on credit risk that describe the basis of internal control in this domain, including the separation of authority between commercial and financial operations. Credit policies are defined at the local level, complemented by the implementation of procedures to monitor customer risk (credit committees at the subsidiary level, the creation of credit limits for corporate customers, portfolio guarantees, etc.).

Each entity also implements monitoring of its outstanding receivables. Risks related to credit may be mitigated or limited by subscription of credit insurance and/or requiring security or guarantees.

Bad debts are provisioned on a case-by-case basis at a rate determined by management based on an assessment of the risk of credit loss.

 

   

Trading & Shipping

Trading & Shipping deals with commercial counterparties and financial institutions located throughout the world. Counterparties to physical and derivative transactions are primarily entities involved in the oil and gas industry or in the trading of energy commodities, or financial institutions. Credit risk coverage is concluded with financial institutions, international banks and insurance groups selected in accordance with strict criteria.

The Trading & Shipping division has a strict policy of internal delegation of authority governing establishment of country and counterparty credit limits and approval of specific transactions. Credit exposures contracted under these limits and approvals are monitored on a daily basis.

Potential counterparties are subject to credit assessment and approval prior to any transaction being concluded and all active counterparties are subject to regular reviews, including re-appraisal and approval of granted limits. The creditworthiness of counterparties is assessed based on an analysis of quantitative and qualitative data regarding financial standing and business risks, together with the review of any relevant third party and market information, such as ratings published by Standard & Poor’s, Moody’s Investors Service and other agencies.

Contractual arrangements are structured so as to maximize the risk mitigation benefits of netting between transactions wherever possible and additional protective

terms providing for the provision of security in the event of financial deterioration and the termination of transactions on the occurrence of defined default events are used to the greatest permitted extent.

Credit risks in excess of approved levels are secured by means of letters of credit and other guarantees, cash deposits and insurance arrangements. In respect of derivative transactions, risks are secured by margin call contracts wherever possible.

 

 

Chemicals Segment

Credit risk in the Chemicals segment is primarily related to commercial receivables. Each division implements procedures for managing and provisioning credit risk that differ based on the size of the subsidiary and the market in which it operates. The principal elements of these procedures are:

 

   

implementation of credit limits with different authorization procedures for possible credit overruns;

 

   

use of insurance policies or specific guarantees (letters of credit);

 

   

regular monitoring and assessment of overdue accounts (aging balance), including collection procedures; and

 

   

provisioning of bad debts on a customer-by-customer basis, according to payment delays and local payment practices (provisions may also be calculated based on statistics).

 

32)   OTHER RISKS AND CONTINGENT LIABILITIES

TOTAL is not currently aware of any exceptional event, dispute, risks or contingent liabilities that could have a material impact on the assets and liabilities, results, financial position or operations of the Group.

The contingent commitments and contractual obligations are detailed in note 23 to the consolidated financial statement.

ANTITRUST INVESTIGATIONS

The principal antitrust proceedings in which the Group’s companies are involved are described hereafter.

 

 

F-89


Table of Contents

Chemicals

 

 

As part of the spin-off of Arkema(1) in 2006, TOTAL S.A. or certain other Group companies agreed to grant Arkema a guarantee for potential monetary consequences related to antitrust proceedings arising from events prior to the spin-off.

This guarantee covers, for a period of ten years from the date of the spin-off, 90% of amounts paid by Arkema related to (i) fines imposed by European authorities or European member-states for competition law violations, (ii) fines imposed by U.S. courts or antitrust authorities for federal antitrust violations or violations of the competition laws of U.S. states, (iii) damages awarded in civil proceedings related to the government proceedings mentioned above, and (iv) certain costs related to these proceedings. The guarantee related to anti-competition violations in Europe applies to amounts above a 176.5 million threshold. On the other hand, the agreements provide that Arkema will indemnify TOTAL S.A. or any Group company for 10% of any amount that TOTAL S.A. or any Group company are required to pay under any of the proceedings covered by this guarantee, in Europe.

If one or more individuals or legal entities, acting alone or together, directly or indirectly holds more than one-third of the voting rights of Arkema, or if Arkema transfers more than 50% of its assets (as calculated under the enterprise valuation method, as of the date of the transfer) to a third party or parties acting together, irrespective of the type or number of transfers, this guarantee will become void.

 

 

In the United States, civil liability lawsuits, for which TOTAL S.A. has been named as the parent company, are closed without significant impact on the Group’s financial position.

 

 

In Europe, since 2006, the European Commission has fined companies of the Group in its configuration prior to the spin-off an overall amount of 385.47 million, of which Elf Aquitaine and/or TOTAL S.A. were held jointly liable for 280.17 million, Elf Aquitaine being personally fined 23.6 million for deterrence. These fines are entirely settled as of today.

As a result, since the spin-off, the Group has paid the overall amount of 188.07 million(2), corresponding to 90% of the fines overall amount once the threshold

provided for by the guarantee is deducted to which an amount of 31.31 million of interest has been added as explained hereinafter.

The European Commission imposed these fines following investigations between 2000 and 2004 into commercial practices involving eight products sold by Arkema. Five of these investigations resulted in prosecutions from the European Commission for which Elf Aquitaine has been named as the parent company, and two of these investigations named TOTAL S.A. as the ultimate parent company of the Group.

TOTAL S.A. and Elf Aquitaine are contesting their liability based solely on their status as parent companies and appealed for cancellation and reformation of the rulings that are still pending before the relevant EU court of appeals or supreme court of appeals.

During the year 2011, four of the proceedings have evolved and are closed as far as Arkema is concerned:

 

   

In one of these proceedings, the Court of Justice of the European Union (CJEU) has rejected the action of Arkema while the decisions of the European Commission and of the General Court of the European Union against the parent companies have been squashed. Consequently, this proceeding is definitively closed regarding Arkema as well as the parent companies.

 

   

In two other proceedings, previous decisions against Arkema and the parent companies have been upheld by the General Court of the European Union. While the parent companies have introduced an appeal before the CJEU, Arkema did not appeal to the CJEU.

 

   

Finally, in a last proceeding, the General Court has decided to reduce the amount of the fine initially ordered against Arkema while, in parallel, it has rejected the actions of the parent companies that have remained obliged to pay the whole amount of the fine initially ordered by the European Commission. Arkema has accepted this decision while the parent companies have introduced an appeal before the CJEU.

 

 

F-90

 

(1) Arkema is used in this section to designate those companies of the Arkema group whose ultimate parent company is Arkema S.A. Arkema became an independent company after being spun-off from TOTAL S.A. in May 2006.
(2) This amount does not take into account a case that led to Arkema, prior to Arkema’s spin-off from TOTAL, and Elf Aquitaine being fined jointly 45 million and Arkema being fined 13.5 million.


Table of Contents

With the exception of the 31.31 million of interest charged by the European Commission to the parent companies, which has been required to pay in accordance with the decision concerning the last proceeding referred hereinabove, the evolution of the proceedings during the year 2011 did not modify the global amount assumed by the Group in execution of the guarantee.

In addition, civil proceedings against Arkema and other groups of companies were initiated in 2009 and 2011, respectively, before German and Dutch courts by third parties for alleged damages pursuant to two of the above mentioned legal proceedings. TOTAL S.A. was summoned to serve notice of the dispute before the German court. At this point, the probability to have a favorable verdict and the financial impacts of these proceedings are uncertain due to the number of legal difficulties they give rise to, the lack of documented claims and evaluations of the alleged damages.

Arkema began implementing compliance procedures in 2001 that are designed to prevent its employees from violating antitrust provisions. However, it is not possible to exclude the possibility that the relevant authorities could commence additional proceedings involving Arkema regarding events prior to the spin-off, as well as Elf Aquitaine and/or TOTAL S.A. based on their status as parent company.

Within the framework of all of the legal proceedings described above, a 17 million reserve remains booked in the Group’s consolidated financial statements as of December 31, 2011.

Downstream

 

 

Pursuant to a statement of objections received by Total Nederland N.V. and TOTAL S.A. (based on its status as parent company) from the European Commission, Total Nederland N.V. was fined 20.25 million in 2006, for which TOTAL S.A. was held jointly liable for 13.5 million. TOTAL S.A. appealed this decision before the relevant court and this appeal is still pending.

 

 

In addition, pursuant to a statement of objections received by Total Raffinage Marketing (formerly Total France) and TOTAL S.A. from the European Commission regarding another product line of the Refining & Marketing division, Total Raffinage Marketing was fined 128.2 million in 2008, which has been paid, and for which TOTAL S.A. was held jointly liable based on its status as parent company. TOTAL S.A. also appealed this decision before the relevant court and this appeal is still pending.

 

In addition, civil proceedings against TOTAL S.A and Total Raffinage Marketing and other companies were initiated before U.K and Dutch courts by third parties for alleged damages in connection with the prosecutions brought by the European Commission in this case. At this point, the probability to have a favorable verdict and the financial impacts of these procedures are uncertain due to the number of legal difficulties they gave rise to, the lack of documented claims and evaluations of the alleged damages.

Within the framework of the legal proceedings described above, a 30 million reserve is booked in the Group’s consolidated financial statements as of December 31, 2011.

Whatever the evolution of the proceedings described above, the Group believes that their outcome should not have a material adverse effect on the Group’s financial situation or consolidated results.

GRANDE PAROISSE

An explosion occurred at the Grande Paroisse industrial site in the city of Toulouse in France on September 21, 2001. Grande Paroisse, a former subsidiary of Atofina which became a subsidiary of Elf Aquitaine Fertilisants on December 31, 2004, as part of the reorganization of the Chemicals segment, was principally engaged in the production and sale of agricultural fertilizers. The explosion, which involved a stockpile of ammonium nitrate pellets, destroyed a portion of the site and caused the death of thirty-one people, including twenty-one workers at the site, and injured many others. The explosion also caused significant damage to certain property in part of the city of Toulouse.

This plant has been closed and individual assistance packages have been provided for employees. The site has been rehabilitated.

On December 14, 2006, Grande Paroisse signed, under the supervision of the city of Toulouse, the deed whereby it donated the former site of the AZF plant to the greater agglomeration of Toulouse (CAGT) and the Caisse des dépôts et consignations and its subsidiary ICADE. Under this deed, TOTAL S.A. guaranteed the site restoration obligations of Grande Paroisse and granted a 10 million endowment to the InNaBioSanté research foundation as part of the setting up of a cancer research center at the site by the city of Toulouse.

Regarding the cause of the explosion, the hypothesis that the explosion was caused by Grande Paroisse through the accidental mixing of hundreds of kilos of a chlorine compound at a storage site for ammonium nitrate was

 

 

F-91


Table of Contents

discredited over the course of the investigation. As a result, proceedings against ten of the eleven Grande Paroisse employees charged during the criminal investigation conducted by the Toulouse Regional Court (Tribunal de grande instance) were dismissed and this dismissal was upheld on appeal. Nevertheless, the final experts’ report filed on May 11, 2006 continued to focus on the hypothesis of a chemical accident, although this hypothesis was not confirmed during the attempt to reconstruct the accident at the site. After having articulated several hypotheses, the experts no longer maintain that the accident was caused by pouring a large quantity of a chlorine compound over ammonium nitrate. Instead, the experts have retained a scenario where a container of chlorine compound sweepings was poured between a layer of wet ammonium nitrate covering the floor and a quantity of dry agricultural nitrate at a location not far from the principal storage site. This is claimed to have caused an explosion which then spread into the main storage site. Grande Paroisse was investigated based on this new hypothesis in 2006; Grande Paroisse is contesting this explanation, which it believes to be based on elements that are not factually accurate.

All the requests for additional investigations that were submitted by Grande Paroisse, the former site manager and various plaintiffs were denied on appeal after the end of the criminal investigation procedure. On July 9, 2007, the investigating judge brought charges against Grande Paroisse and the former plant manager before the criminal chamber of the Court of Appeal of Toulouse. In late 2008, TOTAL S.A. and Mr. Thierry Desmarest were summoned to appear in Court pursuant to a request by a victims association. The trial for this case began on February 23, 2009, and lasted approximately four months.

On November 19, 2009, the Toulouse Criminal Court acquitted both the former Plant Manager, and Grande Paroisse due to the lack of reliable evidence for the explosion. The Court also ruled that the summonses against TOTAL S.A. and Mr. Thierry Desmarest, Chairman and CEO at the time of the disaster, were inadmissible.

Due to the presumption of civil liability that applied to Grande Paroisse, the Court declared Grande Paroisse civilly liable for the damages caused by the explosion to the victims in its capacity as custodian and operator of the plant.

The Prosecutor’s office, together with certain third parties, has appealed the Toulouse Criminal Court verdict. In order to preserve its rights, Grande Paroisse lodged a cross-appeal with respect to civil charges.

The appeal proceedings before the Court of Appeal of Toulouse started on November 3, 2011.

A compensation mechanism for victims was set up immediately following the explosion. 2.3 billion was paid for the compensation of claims and related expenses amounts. As of December 31, 2011, a 21 million reserve was recorded in the Group’s consolidated balance sheet.

BUNCEFIELD

On December 11, 2005, several explosions, followed by a major fire, occurred at an oil storage depot at Buncefield, north of London. This depot was operated by Hertfordshire Oil Storage Limited (HOSL), a company in which TOTAL’s UK subsidiary holds 60% and another oil group holds 40%.

The explosion caused injuries, most of which were minor injuries, to a number of people and caused property damage to the depot and the buildings and homes located nearby. The official Independent Investigation Board has indicated that the explosion was caused by the overflow of a tank at the depot. The Board’s final report was released on December 11, 2008. The civil procedure for claims, which had not yet been settled, took place between October and December 2008. The Court’s decision of March 20, 2009, declared TOTAL’s UK subsidiary liable for the accident and solely liable for indemnifying the victims. The subsidiary appealed the decision. The appeal trial took place in January 2010. The Court of Appeals, by a decision handed down on March 4, 2010, confirmed the prior judgment. The Supreme Court of United Kingdom has partially authorized TOTAL’s UK subsidiary to contest the decision. TOTAL’s UK subsidiary finally decided to withdraw from this recourse due to settlement agreements reached in mid-February 2011.

The Group carries insurance for damage to its interests in these facilities, business interruption and civil liability claims from third parties. The provision for the civil liability that appears in the Group’s consolidated financial statements as of December 31, 2011, stands at 80 million after taking into account the payments previously made.

The Group believes that, based on the information currently available, on a reasonable estimate of its liability and on provisions recognized, this accident should not have a significant impact on the Group’s financial situation or consolidated results.

In addition, on December 1, 2008, the Health and Safety Executive (HSE) and the Environment Agency (EA) issued a Notice of prosecution against five companies, including TOTAL’s UK subsidiary. By a judgment on July 16, 2010, the subsidiary was fined £3.6 million and paid it. The decision takes into account a number of elements that have mitigated the impact of the charges brought against it.

 

 

F-92


Table of Contents

ERIKA

Following the sinking in December 1999 of the Erika, a tanker that was transporting products belonging to one of the Group companies, the Tribunal de grande instance of Paris convicted TOTAL S.A. of marine pollution pursuant to a judgment issued on January 16, 2008, finding that TOTAL S.A. was negligent in its vetting procedure for vessel selection, and ordering TOTAL S.A. to pay a fine of 375,000. The Court also ordered compensation to be paid to those affected by the pollution from the Erika up to an aggregate amount of 192 million, declaring TOTAL S.A. jointly and severally liable for such payments together with the Erika’s inspection and classification firm, the Erika’s owner and the Erika’s manager.

TOTAL has appealed the verdict of January 16, 2008. In the meantime, it nevertheless proposed to pay third parties who so requested definitive compensation as determined by the Court. Forty-two third parties have been compensated for an aggregate amount of 171.5 million.

By a decision dated March 30, 2010, the Court of Appeal of Paris upheld the lower Court verdict pursuant to which TOTAL S.A. was convicted of marine pollution and fined 375,000. TOTAL appealed this decision to the French Supreme Court (Cour de cassation).

However, the Court of Appeal ruled that TOTAL S.A. bears no civil liability according to the applicable international conventions and consequently ruled that TOTAL S.A. be not convicted.

To facilitate the payment of damages awarded by the Court of Appeal in Paris to third parties against Erika’s controlling and classification firm, the ship-owner and the ship-manager, a global settlement agreement was signed late 2011 between these parties and TOTAL S.A. under the auspices of the IOPC Fund. Under this global settlement agreement, each party agreed to the withdrawal of all civil proceedings initiated against all other parties to the agreement.

TOTAL S.A. believes that, based on the information currently available, the case should not have a significant impact on the Group’s financial situation or consolidated results.

BLUE RAPID AND THE RUSSIAN OLYMPIC COMMITTEE — RUSSIAN REGIONS AND INTERNEFT

Blue Rapid, a Panamanian company, and the Russian Olympic Committee filed a claim for damages with the Paris Commercial Court against Elf Aquitaine, alleging a so-called non-completion by a former subsidiary of Elf Aquitaine of a contract related to an exploration and

production project in Russia negotiated in the early 1990s. Elf Aquitaine believed this claim to be unfounded and opposed it. On January 12, 2009, the Commercial Court of Paris rejected Blue Rapid’s claim against Elf Aquitaine and found that the Russian Olympic Committee did not have standing in the matter. Blue Rapid and the Russian Olympic Committee appealed this decision. On June 30, 2011, the Court of Appeal of Paris dismissed as inadmissible the claim of Blue Rapid and the Russian Olympic Committee against Elf Aquitaine, notably on the grounds of the contract’s termination. Blue Rapid and the Russian Olympic Committee appealed this decision to the French Supreme Court.

In connection with the same facts, and fifteen years after the termination of the exploration and production contract, a Russian company, which was held not to be the contracting party to the contract, and two regions of the Russian Federation which were not even parties to the contract, have launched an arbitration procedure against the aforementioned former subsidiary of Elf Aquitaine that was liquidated in 2005, claiming alleged damages of U.S.$ 22.4 billion. For the same reasons as those successfully adjudicated by Elf Aquitaine against Blue Rapid and the Russian Olympic Committee, the Group considers this claim to be unfounded as to a matter of law or fact. The Group has lodged a criminal complaint to denounce the fraudulent claim which the Group believes it is a victim of and, has taken and reserved its rights to take other actions and measures to defend its interests.

IRAN

In 2003, the United States Securities and Exchange Commission (SEC) followed by the Department of Justice (DoJ) issued a formal order directing an investigation in connection with the pursuit of business in Iran, by certain oil companies including, among others, TOTAL.

The inquiry concerns an agreement concluded by the Company with a consultant concerning a gas field in Iran and aims to verify whether certain payments made under this agreement would have benefited Iranian officials in violation of the Foreign Corrupt Practices Act (FCPA) and the Company’s accounting obligations.

Investigations are still pending and the Company is cooperating with the SEC and the DoJ. In 2010, the Company opened talks with U.S. authorities, without any acknowledgement of facts, to consider an out-of-court settlement as it is often the case in this kind of proceeding.

Late in 2011, the SEC and the DoJ proposed to TOTAL out-of-court settlements that would close their inquiries, in exchange for TOTAL’s committing to a number of

 

 

F-93


Table of Contents

obligations and paying fines. As TOTAL was unable to agree to several substantial elements of the proposal, the Company is continuing discussions with the U.S. authorities. The Company is free not to accept an out-of-court settlement solution, in which case it would be exposed to the risk of prosecution in the United States.

In this same affair, a parallel judicial inquiry related to TOTAL was initiated in France in 2006. In 2007, the Company’s Chief Executive Officer was placed under formal investigation in relation to this inquiry, as the former President of the Middle East department of the Group’s Exploration & Production division. The Company has not been notified of any significant developments in the proceedings since the formal investigation was launched.

At this point, the Company cannot determine when these investigations will terminate, and cannot predict their results, or the outcome of the talks that have been initiated. Resolving these cases is not expected to have a significant impact on the Group’s financial situation or consequences on its future planned operations.

OIL-FOR-FOOD PROGRAM

Several countries have launched investigations concerning possible violations related to the United Nations (UN) Oil-for-Food program in Iraq.

Pursuant to a French criminal investigation, certain current or former Group employees were placed under formal criminal investigation for possible charges as accessories to the misappropriation of corporate assets and as accessories to the corruption of foreign public agents. The Chairman and Chief Executive Officer of the Company, formerly President of the Group’s Exploration & Production division, was also placed under formal investigation in October 2006. In 2007, the criminal investigation was closed and the case was transferred to the Prosecutor’s office. In 2009, the Prosecutor’s office recommended to the investigating judge that the case against the Group’s current and former employees and TOTAL’s Chairman and Chief Executive Officer not be pursued.

In early 2010, despite the recommendation of the Prosecutor’s office, a new investigating judge, having taken over the case, decided to indict TOTAL S.A. on bribery charges as well as complicity and influence peddling. The indictment was brought eight years after the beginning of the investigation without any new evidence being introduced.

In October 2010, the Prosecutor’s office recommended to the investigating judge that the case against TOTAL S.A., the Group’s current and former employees and TOTAL’s Chairman and Chief Executive Officer not be pursued.

However, by ordinance notified in early August 2011, the investigating judge on the matter decided to send the case to trial.

The Company believes that its activities related to the Oil-for-Food program have been in compliance with this program, as organized by the UN in 1996.

The Volcker report released by the independent investigating committee set up by the UN had discarded any bribery grievance within the framework of the Oil-For-Food program with respect to TOTAL.

ITALY

As part of an investigation led by the Prosecutor of the Republic of the Potenza Court, Total Italia and certain Group’s employees are the subject of an investigation related to certain calls for tenders that Total Italia made for the preparation and development of an oil field. On February 16, 2009, as a preliminary measure before the proceedings go before the Court, the preliminary investigation judge of Potenza served notice to Total Italia of a decision that would suspend the concession for this field for one year. Total Italia has appealed the decision by the preliminary investigation judge before the Court of Appeal of Potenza. In a decision dated April 8, 2009, the Court reversed the suspension of the concession and appointed for one year, i.e. until February 16, 2010, a judicial administrator to supervise the operations related to the development of the concession, allowing the Tempa Rossa project to continue.

The criminal investigation was closed in the first half of 2010. The preliminary hearing judge, who will decide whether the case shall be returned to the Criminal Court to be judged on the merits, held the first hearing on December 6, 2010. The proceedings before the Judge of the preliminary hearing are still pending.

In 2010, Total Italia’s exploration and production operations were transferred to Total E&P Italia and refining and marketing operations were merged with those of Erg Petroli.

LIBYA

During the financial year 2011, the Group’s activities were affected by the security context in Libya, and the Group’s production was gradually shut down as from the end of February. The Group’s production started up again at the end of September 2011 on the offshore Al Jurf field located in zones 15, 16 & 32 (ex C137) at the level existing before the events, and has gradually restarted since October 2011 in onshore zones 129, 130 and 131. The restart of the Group’s production on the other onshore zones is expected to occur progressively in 2012.

 

 

F-94


Table of Contents

In June 2011, the United States Securities and Exchange Commission (SEC) issued to certain oil companies — including, among others, TOTAL — a formal request for information related to their operations in Libya. TOTAL is cooperating with this non public investigation.

YEMEN

During the financial year 2011, the Group’s activities were not significantly impacted by the security context in Yemen, but the Group nevertheless reorganized locally to minimize the risks to its personnel. In addition, on October 15, 2011, the gas pipeline supplying Yemen LNG was sabotaged, and then repaired with no delay, enabling LNG production to resume as from October 26, 2011.

SYRIA

In May 2011, the European Union adopted measures with criminal and financial penalties that prohibit the supply of certain equipment to Syria, as well as certain financial and asset transactions with respect to a list of named individuals and entities. These measures apply to European persons and to entities constituted under the laws of a EU Member State. In September 2011, the EU adopted further measures, including, notably, a prohibition on the purchase, import or transportation from Syria of crude oil and petroleum products. Since early September 2011, the Group ceased to purchase hydrocarbons from Syria. On December 1, 2011, the EU extended sanctions against, among others, three state-owned Syrian oil firms, including General Petroleum Corporation, the Group’s co-contracting partner in PSA 1988 (Deir Es Zor license) and the Tabiyeh contract. Since early December 2011, TOTAL has ceased its activities that contribute to oil and gas production in Syria.

33) OTHER INFORMATION

Research and development costs incurred by the Group in 2011 amounted to 776 million (715 million in 2010 and 650 million in 2009), corresponding to 0.4% of the sales.

The staff dedicated in 2011 to these research and development activities are estimated at 3,946 people (4,087 in 2010 and 4,016 in 2009).

 

34)   CHANGES IN PROGRESS IN THE GROUP STRUCTURE

 

 

TOTAL signed in March 2011 agreements for the acquisition in Uganda of a one-third interest in Blocks 1, 2 and 3A held by Tullow Oil plc for $1,467 million (amount as of January 1, 2010, to which will add costs of interim period). Following this acquisition, TOTAL would become an equal partner with Tullow and CNOOC in the blocks, each with a one-third interest and each being an operator of one of the blocks. Subject to the decision of the Authorities, TOTAL would be the operator of Block 1.

 

 

TOTAL announced in February 2012 the signature of an agreement with Sinochem to sell its interests in the Cusiana field and in OAM and ODC pipelines. This transaction is subject to approval by the relevant authorities.

 

 

As of December 31, 2010, the sections “Assets classified as held for sale” and “Liabilities directly associated with the assets classified as held for sale” included the assets and liabilities of Total E&P Cameroun, of Joslyn and of photocure and coatings resins businesses.

35) CONSOLIDATION SCOPE

As of December 31, 2011, 870 entities are consolidated of which 783 are fully consolidated, and 87 are accounted for under the equity method (identified with the letter E).

This simplified organizational chart shows the main consolidated entities. For each of them, the Group interest is mentioned between brackets. This chart of legal detentions is not exhaustive and does not reflect neither the operational structure nor the relative economic size of the Group entities and the business segments.

 

 

F-95


Table of Contents

 

LOGO

 

F-96


Table of Contents

TOTAL

SUPPLEMENTAL OIL AND GAS INFORMATION (Unaudited)

 

As from 2009, the amendments to the Securities and Exchange Commission (SEC) Rule 4-10 of Regulation S-X set forth in the “Modernization of Oil and Gas Reporting” release (SEC Release n° 33-8995) and the Financial Accounting Standard Board (FASB) Accounting Standards Update regarding Extractive Activities-Oil and Gas (ASC 932) change a number of reserves estimation and disclosure requirements. As a reminder, in terms of reserves estimation, the main changes are: the use of an average price instead of a single year-end price; the use of new reliable technologies to assess proved reserves; and the inclusion, under certain conditions, of non-traditional sources as oil and gas producing activities. The revised rules form the basis of the 2011, 2010 and 2009 year-end estimation of proved reserves.

Preparation of reserves estimates

The estimation of reserves is an ongoing process which is done within affiliates by experienced geoscientists, engineers and economists under the supervision of each affiliate’s General Management. Persons involved in reserves evaluation are trained to follow SEC-compliant internal guidelines and policies regarding criteria that must be met before reserves can be considered as proved.

The technical validation process relies on a Technical Reserves Committee that is responsible for approving proved reserves changes above a certain threshold and technical evaluations of reserves associated with any investment decision that requires approval from the Exploration & Production Executive Committee. The Chairman of the Technical Reserves Committee is appointed by the Senior Management of Exploration & Production and its members represent expertise in reservoir engineering, production geology, production geophysics, drilling, and development studies.

An internal control process related to reserves estimation is well established within TOTAL and involves the following elements:

 

   

A central Reserve Entity whose responsibility is to consolidate, document and archive the Group’s reserves; to ensure coherence of evaluations worldwide; to maintain the Corporate Reserves Guidelines Standards in line with SEC guidelines and policies; to deliver training on reserves

   

evaluation and classification; and to conduct periodically in-depth technical review of reserves for each affiliate.

 

   

An annual review of affiliates reserves conducted by an internal group of specialists selected for their expertise in geosciences and engineering or their knowledge of the affiliate. All members of this group chaired by the Reserves Vice-president and composed of at least three Technical Reserves Committee members are knowledgeable in the SEC guidelines for proved reserves evaluation. Their responsibility is to provide an independent review of reserves changes proposed by affiliates and ensure that reserves are estimated using appropriate standards and procedures.

 

   

At the end of the annual review carried out by the Development Division, an SEC Reserves Committee chaired by the Exploration & Production Finance Senior Vice President and comprised of the Development, Exploration, Strategy and Legal Senior Vice Presidents, or their representatives, as well as the Chairman of the Technical Reserves Committee and the Reserves Vice-President, approves the SEC reserve booking proposals regarding criteria that are not dependent upon reservoir and geosciences techniques. The results of the annual review and the proposals for including revisions or additions of SEC Proved Reserves are presented to the Exploration & Production Executive Committee for approval before final validation by the Group Executive Management.

The reserves evaluation and control process is audited periodically by the Group’s internal auditors who verify the effectiveness of the reserves evaluation process and control procedures.

The Reserves Vice-President (RVP) is the technical person responsible for preparing the reserves estimates for the Group. Appointed by the President of Exploration & Production, the RVP supervises the Reserve Entity, chairs the annual review of reserves, and is a member of the Technical Reserves Committee and the SEC Reserves Committee. The RVP has over thirty years of experience in the oil & gas industry. He previously held several

 

 

S-1


Table of Contents

management positions in the Group in reservoir engineering and geosciences, and has more than fifteen years of experience in the field of reserves evaluation and control process. He holds an engineering degree from Institut National des Sciences Appliquées, Lyon, France, and a petroleum engineering degree from Ecole Nationale Supérieure du Pétrole et des Moteurs (IFP School), France. He is a past member and past chairman of the Society of Petroleum Engineering Oil and Gas Reserves Committee and a member of the UNECE (United Nations Economic Commission for Europe) Expert Group on Resource Classification.

Proved developed reserves

At the end of 2011, proved developed reserves of oil and gas were 6,046 Mboe and represented 53% of the proved reserves. At the end of 2010, proved developed reserves of oil and gas were 5,708 Mboe and represented 53% of the proved reserves. At the end of 2009, proved developed reserves of oil and gas were 5,835 Mboe and represented 56% of the proved reserves. Over the past three years, the level of proved developed reserves has remained above 5.7 Bboe and over 53% of proved reserves, illustrating TOTAL’s ability to consistently transfer proved undeveloped reserves into developed status.

Proved undeveloped reserves

As of December 31, 2011, TOTAL’s combined proved undeveloped reserves of oil and gas were 5,377 Mboe as compared to 4,987 Mboe at the end of 2010. The net increase of 390 Mboe of proved undeveloped reserves is due to the addition of +639 Mboe of undeveloped reserves related to extensions and discoveries, a net increase of +401 Mboe due to acquisitions/divestitures, the revision of -168 Mboe of previous estimates (partly resulting from negative price effects), and the transfer of 482 Mboe from proved undeveloped reserves to proved developed reserves. In 2011, the costs incurred to develop proved undeveloped reserves (PUDs) was 10.2 billion, which represents 84% of 2011 development costs incurred, and was related to projects located for the most part in Angola, Australia, Canada, Kazakhstan, Nigeria, Norway, United Kingdom and Russia.

Approximately 57% of the Group’s proved undeveloped reserves are associated with producing projects and are

located for the most part in Angola, Canada, Nigeria, Norway, and Venezuela. These reserves are expected to be developed over time as part of initial field development plans or additional development phases. The timing to bring these proved reserves into production will depend upon several factors including reservoir performance, surface facilities or plant capacity constraints and contractual limitations on production level. The remaining proved undeveloped reserves correspond to undeveloped fields or assets for which a development has been sanctioned or is in progress.

The Group’s portfolio of projects includes a few large scale and complex developments for which it anticipates that it may take more than five years from the time of recording proved reserves to the start of production. These specific projects represent approximately 26% of the Group’s proved undeveloped reserves and include the development of a giant field in Kazakhstan, deep offshore developments in Angola, Nigeria and the United Kingdom and development of oil sands in Canada. These projects are highly complex to develop due to a combination of factors that include, among others, the nature of the reservoir rock and fluid properties, challenging operating environments and the size of the projects. In addition, some of these projects are generally designed and optimized for a given production capacity that controls the pace at which the field is developed and the wells are drilled. At production start-up, only a portion of the proved reserves are developed in order to deliver sufficient production potential to meet capacity constraints and contractual obligations. The remaining PUD’s associated with the complete development plan will therefore remain undeveloped for more than five years following project approval and booking. Under these specific circumstances, the Group believes that it is justified to report as proved reserves the level of reserves used in connection with the approved project, despite the fact that some of these PUDs may remain undeveloped for more than five years. In addition, TOTAL has demonstrated in recent years the Group’s ability to successfully develop and bring into production similar large scale and complex projects, including the development of deep-offshore fields in Angola, Nigeria, the Republic of Congo, HP/HT fields in the United Kingdom, heavy oil projects in Venezuela and LNG projects in Qatar, Yemen, Nigeria and Indonesia.

 

 

Information shown in the following tables is presented in accordance with the FASB’s ASC 932 and the requirements of the SEC Regulation S-K (Items 1200 to 1208).

The tables provided below are presented by the following geographic areas: Europe, Africa, the Americas, Middle East and Asia (including CIS).

 

S-2


Table of Contents

ESTIMATED PROVED RESERVES OF OIL, BITUMEN AND GAS RESERVES

The following tables present, for oil, bitumen and gas reserves, an estimate of the Group’s oil, bitumen and gas quantities by geographic areas as of December 31, 2011, 2010 and 2009. Quantities shown concern proved developed and undeveloped reserves together with changes in quantities for 2011, 2010 and 2009.

The definitions used for proved, proved developed and proved undeveloped oil and gas reserves are in accordance with the revised Rule 4-10 of SEC Regulation S-X.

All references in the following tables to reserves or production are to the Group’s entire share of such reserves or production. TOTAL’s worldwide proved reserves include the proved reserves of its consolidated subsidiaries as well as its proportionate share of the proved reserves of equity affiliates.

 

S-3


Table of Contents

Changes in oil, bitumen and gas reserves

 

Proved developed and undeveloped reserves    Consolidated subsidiaries  

(in million barrels of oil equivalent)

   Europe     Africa     Americas     Middle
East
    Asia     Total  

Balance as of December 31, 2008

     1,815        3,646        732        530        1,242        7,965   

Revisions of previous estimates

     46        76        14        (7     25        154   

Extensions, discoveries and other

     18        53        284        76               431   

Acquisitions of reserves in place

     12               130                      142   

Sales of reserves in place

     (2     (43     (14                   (59

Production for the year

     (224     (266     (56     (55     (101     (702

Balance as of December 31, 2009

     1,665        3,466        1,090        544        1,166        7,931   

Revisions of previous estimates

     92        200        82        (10     1        365   

Extensions, discoveries and other

     182               18        96        30        326   

Acquisitions of reserves in place

     23               425               9        457   

Sales of reserves in place

     (45     (26     (5            (8     (84

Production for the year

     (211     (269     (70     (56     (99     (705

Balance as of December 31, 2010

     1,706        3,371        1,540        574        1,099        8,290   

Revisions of previous estimates

     117        (61     (36     (68     (19     (67

Extensions, discoveries and other

     57        6                      588        651   

Acquisitions of reserves in place

     44               309               2        355   

Sales of reserves in place

            (65                          (65

Production for the year

     (187     (237     (75     (56     (93     (648

Balance as of December 31, 2011

     1,737        3,014        1,738        450        1,577        8,516   

Minority interest in proved developed and undeveloped reserves as of

  

       

December 31, 2009

     26        98                             124   

December 31, 2010

     26        100                             126   

December 31, 2011

            98                             98   
Proved developed and undeveloped reserves    Equity affiliates  

(in million barrels of oil equivalent)

   Europe     Africa     Americas     Middle
East
    Asia     Total  

Balance as of December 31, 2008

            98        527        1,868               2,493   

Revisions of previous estimates

            10        (7     51               54   

Extensions, discoveries and other

                          136               136   

Acquisitions of reserves in place

                                          

Sales of reserves in place

                                          

Production for the year

            (8     (18     (105            (131

Balance as of December 31, 2009

            100        502        1,950               2,552   

Revisions of previous estimates

            14        4        (2            16   

Extensions, discoveries and other

                                          

Acquisitions of reserves in place

                                          

Sales of reserves in place

                                          

Production for the year

            (7     (20     (136            (163

Balance as of December 31, 2010

            107        486        1,812               2,405   

Revisions of previous estimates

            (1     (8     (20            (29

Extensions, discoveries and other

                                          

Acquisitions of reserves in place

                                 779        779   

Sales of reserves in place

            (24     (4     (11            (39

Production for the year

            (4     (18     (152     (35     (209

Balance as of December 31, 2011

            78        456        1,629        744        2,907   

 

S-4


Table of Contents
     Consolidated subsidiaries and equity affiliates  

(in million barrels of oil equivalent)

   Europe      Africa      Americas      Middle
East
     Asia      Total  

As of December 31, 2009

                 

Proved developed and undeveloped reserves

     1,665         3,566         1,592         2,494         1,166         10,483   

Consolidated subsidiaries

     1,665         3,466         1,090         544         1,166         7,931   

Equity affiliates

             100         502         1,950                 2,552   

Proved developed reserves

     1,096         1,775         631         1,918         415         5,835   

Consolidated subsidiaries

     1,096         1,745         503         482         415         4,241   

Equity affiliates

             30         128         1,436                 1,594   

Proved undeveloped reserves

     569         1,791         961         576         751         4,648   

Consolidated subsidiaries

     569         1,721         587         62         751         3,690   

Equity affiliates

             70         374         514                 958   

As of December 31, 2010

                 

Proved developed and undeveloped reserves

     1,706         3,478         2,026         2,386         1,099         10,695   

Consolidated subsidiaries

     1,706         3,371         1,540         574         1,099         8,290   

Equity affiliates

             107         486         1,812                 2,405   

Proved developed reserves

     962         1,692         638         2,055         361         5,708   

Consolidated subsidiaries

     962         1,666         505         427         361         3,921   

Equity affiliates

             26         133         1,628                 1,787   

Proved undeveloped reserves

     744         1,786         1,388         331         738         4,987   

Consolidated subsidiaries

     744         1,705         1,035         147         738         4,369   

Equity affiliates

             81         353         184                 618   

As of December 31, 2011

                 

Proved developed and undeveloped reserves

     1,737         3,092         2,194         2,079         2,321         11,423   

Consolidated subsidiaries

     1,737         3,014         1,738         450         1,577         8,516   

Equity affiliates

             78         456         1,629         744         2,907   

Proved developed reserves

     894         1,660         647         1,869         976         6,046   

Consolidated subsidiaries

     894         1,639         524         371         321         3,749   

Equity affiliates

             21         123         1,498         655         2,297   

Proved undeveloped reserves

     843         1,432         1,547         210         1,345         5,377   

Consolidated subsidiaries

     843         1,375         1,214         79         1,256         4,767   

Equity affiliates

             57         333         131         89         610   

 

S-5


Table of Contents

Changes in oil reserves

The oil reserves for the years prior to 2009 include crude oil, natural gas liquids (condensates, LPG) and bitumen reserves. Bitumen reserves as from 2009 are shown separately.

 

Proved developed and undeveloped reserves    Consolidated subsidiaries  
     Europe     Africa     Americas     Middle
East
    Asia     Total  

(in million barrels)

            

Balance as of December 31, 2008

     798        2,597        252        225        538        4,410   

Revisions of previous estimates

     34        92        (170     (4     51        3   

Extensions, discoveries and other

     8        38        22        1               69   

Acquisitions of reserves in place

     1                                    1   

Sales of reserves in place

            (44     (1                   (45

Production for the year

     (108     (223     (15     (34     (17     (397

Balance as of December 31, 2009

     733        2,460        88        188        572        4,041   

Revisions of previous estimates

     46        131        7        (2            182   

Extensions, discoveries and other

     146               2        82        4        234   

Acquisitions of reserves in place

     2                                    2   

Sales of reserves in place

     (37     (23     (2            (7     (69

Production for the year

     (98     (218     (16     (29     (15     (376

Balance as of December 31, 2010

     792        2,350        79        239        554        4,014   

Revisions of previous estimates

     49        (19     9        (33     (24     (18

Extensions, discoveries and other

     17        6                      58        81   

Acquisitions of reserves in place

     42                                    42   

Sales of reserves in place

            (57                          (57

Production for the year

     (88     (185     (15     (25     (15     (328

Balance as of December 31, 2011

     812        2,095        73        181        573        3,734   

Minority interest in proved developed and undeveloped reserves as of

            

December 31, 2009

     12        88                             100   

December 31, 2010

     11        89                             100   

December 31, 2011

            88                             88   
Proved developed and undeveloped reserves    Equity affiliates  
     Europe     Africa     Americas     Middle
East
    Asia     Total  

(in million barrels)

            

Balance as of December 31, 2008

            58        508        719               1,285   

Revisions of previous estimates

            (14     (5     (15            (34

Extensions, discoveries and other

                          136               136   

Acquisitions of reserves in place

                                          

Sales of reserves in place

                                          

Production for the year

            (7     (18     (79            (104

Balance as of December 31, 2009

            37        485        761               1,283   

Revisions of previous estimates

            4        4        3               11   

Extensions, discoveries and other

                                          

Acquisitions of reserves in place

                                          

Sales of reserves in place

                                          

Production for the year

            (7     (19     (84            (110

Balance as of December 31, 2010

            34        470        680               1,184   

Revisions of previous estimates

            2        (6     (12            (16

Extensions, discoveries and other

                                          

Acquisitions of reserves in place

                                 51        51   

Sales of reserves in place

            (22     (4     (12            (38

Production for the year

            (4     (17     (91     (3     (115

Balance as of December 31, 2011

            10        443        565        48        1,066   

 

S-6


Table of Contents
     Consolidated subsidiaries and equity affiliates  
     Europe      Africa      Americas      Middle
East
     Asia      Total  

(in million barrels)

                 

As of December 31, 2009

                 

Proved developed and undeveloped reserves

     733         2,497         573         949         572         5,324   

Consolidated subsidiaries

     733         2,460         88         188         572         4,041   

Equity affiliates

             37         485         761                 1,283   

Proved developed reserves

     457         1,331         187         728         65         2,768   

Consolidated subsidiaries

     457         1,303         66         174         65         2,065   

Equity affiliates

             28         121         554                 703   

Proved undeveloped reserves

     276         1,166         386         221         507         2,556   

Consolidated subsidiaries

     276         1,157         22         14         507         1,976   

Equity affiliates

             9         364         207                 580   

As of December 31, 2010

                 

Proved developed and undeveloped reserves

     792         2,384         549         919         554         5,198   

Consolidated subsidiaries

     792         2,350         79         239         554         4,014   

Equity affiliates

             34         470         680                 1,184   

Proved developed reserves

     394         1,250         180         662         58         2,544   

Consolidated subsidiaries

     394         1,226         53         151         58         1,882   

Equity affiliates

             24         127         511                 662   

Proved undeveloped reserves

     398         1,134         369         257         496         2,654   

Consolidated subsidiaries

     398         1,124         26         88         496         2,132   

Equity affiliates

             10         343         169                 522   

As of December 31, 2011

                 

Proved developed and undeveloped reserves

     812         2,105         516         746         621         4,800   

Consolidated subsidiaries

     812         2,095         73         181         573         3,734   

Equity affiliates

             10         443         565         48         1,066   

Proved developed reserves

     351         1,206         165         565         91         2,378   

Consolidated subsidiaries

     351         1,202         48         116         50         1,767   

Equity affiliates

             4         117         449         41         611   

Proved undeveloped reserves

     461         899         351         181         530         2,422   

Consolidated subsidiaries

     461         893         25         65         523         1,967   

Equity affiliates

             6         326         116         7         455   

 

S-7


Table of Contents

Changes in bitumen reserves

Bitumen reserves as of December 31, 2008 and before are included in oil reserves presented in the table “Changes in oil reserves”.

 

Proved developed and undeveloped reserves    Consolidated subsidiaries  

(in million barrels)

   Europe      Africa      Americas     Middle
East
     Asia      Total  

Balance as of December 31, 2008

                                              

Revisions of previous estimates

                     176                        176   

Extensions, discoveries and other

                     192                        192   

Acquisitions of reserves in place

                                              

Sales of reserves in place

                                              

Production for the year

                     (3                     (3

Balance as of December 31, 2009

                     365                        365   

Revisions of previous estimates

                     3                        3   

Extensions, discoveries and other

                                              

Acquisitions of reserves in place

                     425                        425   

Sales of reserves in place

                                              

Production for the year

                     (4                     (4

Balance as of December 31, 2010

                     789                        789   

Revisions of previous estimates

                     (109                     (109

Extensions, discoveries and other

                                              

Acquisitions of reserves in place

                     308                        308   

Sales of reserves in place

                                              

Production for the year

                     (4                     (4

Balance as of December 31, 2011

                     984                        984   

Proved developed reserves as of

                

December 31, 2009

                     19                        19   

December 31, 2010

                     18                        18   

December 31, 2011

                     21                        21   

Proved undeveloped reserves as of

                

December 31, 2009

                     346                        346   

December 31, 2010

                     771                        771   

December 31, 2011

                     963                        963   

There are no bitumen reserves for equity affiliates.

There are no minority interests for bitumen reserves.

 

S-8


Table of Contents

Changes in gas reserves

 

Proved developed and undeveloped reserves   Consolidated subsidiaries  

(in billion cubic feet)

  Europe     Africa     Americas     Middle
East
    Asia     Total  

Balance as of December 31, 2008

    5,507        5,529        2,714        1,769        4,098        19,617   

Revisions of previous estimates

    73        (127     25        (18     (165     (212

Extensions, discoveries and other

    55        61        382        399               897   

Acquisitions of reserves in place

    58               752                      810   

Sales of reserves in place

    (13            (64                   (77

Production for the year

    (633     (217     (212     (122     (467     (1,651

Balance as of December 31, 2009

    5,047        5,246        3,597        2,028        3,466        19,384   

Revisions of previous estimates

    271        346        415        (80     15        967   

Extensions, discoveries and other

    193               88        70        138        489   

Acquisitions of reserves in place

    111                             51        162   

Sales of reserves in place

    (43     (20     (16            (4     (83

Production for the year

    (617     (258     (278     (151     (472     (1,776

Balance as of December 31, 2010

    4,962        5,314        3,806        1,867        3,194        19,143   

Revisions of previous estimates

    358        (216     367        (180     1        330   

Extensions, discoveries and other

    211                             2,824        3,035   

Acquisitions of reserves in place

    11               7               13        31   

Sales of reserves in place

           (46                          (46

Production for the year

    (528     (259     (317     (169     (445     (1,718

Balance as of December 31, 2011

    5,014        4,793        3,863        1,518        5,587        20,775   

Minority interest in proved developed and undeveloped reserves as of

  

December 31, 2009

    73        60                             133   

December 31, 2010

    83        67                             150   

December 31, 2011

           62                             62   
Proved developed and undeveloped reserves   Equity affiliates  

(in billion cubic feet)

  Europe     Africa     Americas     Middle
East
    Asia     Total  

Balance as of December 31, 2008

           215        110        6,276               6,601   

Revisions of previous estimates

           127        (13     363               477   

Extensions, discoveries and other

                                         

Acquisitions of reserves in place

                                         

Sales of reserves in place

                                         

Production for the year

           (1     (2     (141            (144

Balance as of December 31, 2009

           341        95        6,498               6,934   

Revisions of previous estimates

           50        (2     (52            (4

Extensions, discoveries and other

                                         

Acquisitions of reserves in place

                                         

Sales of reserves in place

                                         

Production for the year

           (1     (2     (282            (285

Balance as of December 31, 2010

           390        91        6,164               6,645   

Revisions of previous estimates

           (16     (10     (31            (57

Extensions, discoveries and other

                                         

Acquisitions of reserves in place

                                3,865        3,865   

Sales of reserves in place

           (10                          (10

Production for the year

           (1     (2     (331     (167     (501

Balance as of December 31, 2011

           363        79        5,802        3,698        9,942   

 

S-9


Table of Contents
     Consolidated subsidiaries and equity affiliates  

(in billion cubic feet)

   Europe      Africa      Americas      Middle
East
     Asia      Total  

As of December 31, 2009

                 

Proved developed and undeveloped reserves

     5,047         5,587         3,692         8,526         3,466         26,318   

Consolidated subsidiaries

     5,047         5,246         3,597         2,028         3,466         19,384   

Equity affiliates

             341         95         6,498                 6,934   

Proved developed reserves

     3,463         2,272         2,388         6,606         2,059         16,788   

Consolidated subsidiaries

     3,463         2,261         2,343         1,773         2,059         11,899   

Equity affiliates

             11         45         4,833                 4,889   

Proved undeveloped reserves

     1,584         3,315         1,304         1,920         1,407         9,530   

Consolidated subsidiaries

     1,584         2,985         1,254         255         1,407         7,485   

Equity affiliates

             330         50         1,665                 2,045   

As of December 31, 2010

                 

Proved developed and undeveloped reserves

     4,962         5,704         3,897         8,031         3,194         25,788   

Consolidated subsidiaries

     4,962         5,314         3,806         1,867         3,194         19,143   

Equity affiliates

             390         91         6,164                 6,645   

Proved developed reserves

     3,089         2,240         2,474         7,649         1,790         17,242   

Consolidated subsidiaries

     3,089         2,229         2,439         1,578         1,790         11,125   

Equity affiliates

             11         35         6,071                 6,117   

Proved undeveloped reserves

     1,873         3,464         1,423         382         1,404         8,546   

Consolidated subsidiaries

     1,873         3,085         1,367         289         1,404         8,018   

Equity affiliates

             379         56         93                 528   

As of December 31, 2011

                 

Proved developed and undeveloped reserves

     5,014         5,156         3,942         7,320         9,285         30,717   

Consolidated subsidiaries

     5,014         4,793         3,863         1,518         5,587         20,775   

Equity affiliates

             363         79         5,802         3,698         9,942   

Proved developed reserves

     2,943         2,308         2,600         7,170         4,854         19,875   

Consolidated subsidiaries

     2,943         2,216         2,567         1,450         1,594         10,770   

Equity affiliates

             92         33         5,720         3,260         9,105   

Proved undeveloped reserves

     2,071         2,848         1,342         150         4,431         10,842   

Consolidated subsidiaries

     2,071         2,577         1,296         68         3,993         10,005   

Equity affiliates

             271         46         82         438         837   

 

S-10


Table of Contents

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

The following tables do not include revenues and expenses related to oil and gas transportation activities and LNG liquefaction and transportation activities.

 

     Consolidated subsidiaries  

(M)

   Europe     Africa     Americas     Middle
East
    Asia     Total  

2009

            

Non-Group sales

     2,499        1,994        583        859        1,926        7,861   
Group sales      4,728        7,423        310        556        597        13,614   

Total Revenues

     7,227        9,417        893        1,415        2,523        21,475   

Production costs

     (1,155     (1,122     (193     (204     (243     (2,917

Exploration expenses

     (160     (265     (121     (81     (70     (697

Depreciation, depletion and amortization and valuation allowances

     (1,489     (1,471     (262     (314     (613     (4,149

Other expenses(a)

     (261     (895     (181     (170     (56     (1,563

Pre-tax income from producing activities

     4,162        5,664        136        646        1,541        12,149   

Income tax

     (2,948     (3,427     (103     (309     (747     (7,534

Results of oil and gas producing activities

     1,214        2,237        33        337        794        4,615   

2010

            
Non-Group sales      2,839        2,639        628        1,038        2,540        9,684   
Group sales      5,599        9,894        540        644        683        17,360   

Total Revenues

     8,438        12,533        1,168        1,682        3,223        27,044   

Production costs

     (1,281     (1,187     (222     (259     (279     (3,228

Exploration expenses

     (266     (275     (216     (8     (99     (864

Depreciation, depletion and amortization and valuation allowances

     (1,404     (1,848     (368     (264     (830     (4,714

Other expenses(a)

     (299     (1,014     (218     (241     (72     (1,844

Pre-tax income from producing activities

     5,188        8,209        144        910        1,943        16,394   

Income tax

     (3,237     (5,068     (83     (402     (950     (9,740

Results of oil and gas producing activities

     1,951        3,141        61        508        993        6,654   

2011

                                                
Non-Group sales      3,116        3,188        776        1,159        3,201        11,440   
Group sales      7,057        11,365        764        737        712        20,635   

Total Revenues

     10,173        14,553        1,540        1,896        3,913        32,075   

Production costs

     (1,235     (1,179     (250     (286     (304     (3,254

Exploration expenses

     (343     (323     (48     (11     (294     (1,019

Depreciation, depletion and amortization and valuation allowances

     (1,336     (1,845     (352     (278     (791     (4,602

Other expenses(a)

     (307     (1,181     (274     (276     (95     (2,133

Pre-tax income from producing activities

     6,952        10,025        616        1,045        2,429        21,067   

Income tax

     (5,059     (6,484     (293     (465     (1,302     (13,603

Results of oil and gas producing activities

     1,893        3,541        323        580        1,127        7,464   

 

(a) Included production taxes and accretion expense as provided for by IAS 37 (271 million in 2009, 326 million in 2010 and 338 million in 2011).

 

S-11


Table of Contents
     Equity affiliates  

(M)

   Europe      Africa     Americas     Middle
East
    Asia     Total  

2009

             

Non-Group sales

             203        528        231               962   
Group sales                            3,382               3,382   

Total Revenues

             203        528        3,613               4,344   

Production costs

             (31     (41     (271            (343

Exploration expenses

                    (17                   (17

Depreciation, depletion and amortization and valuation allowances

             (42     (73     (247            (362

Other expenses

             (9     (205     (2,800            (3,014

Pre-tax income from producing activities

             121        192        295               608   

Income tax

             (93     (74     (101            (268

Results of oil and gas producing activities

             28        118        194               340   

2010

             
Non-Group sales              148        120        596               864   

Group sales

             3        565        4,646               5,214   

Total Revenues

             151        685        5,242               6,078   

Production costs

             (44     (53     (195     (1     (293

Exploration expenses

             (7     (23                   (30

Depreciation, depletion and amortization and valuation allowances

             (44     (89     (259            (392

Other expenses

                    (268     (4,034            (4,302

Pre-tax income from producing activities

             56        252        754        (1     1,061   

Income tax

                    (44     (142            (186

Results of oil and gas producing activities

             56        208        612        (1     875   

2011

             

Non-Group sales

             26        15        1,080        256        1,377   

Group sales

                    831        6,804               7,635   

Total Revenues

             26        846        7,884        256        9,012   

Production costs

             (7     (48     (250     (28     (333

Exploration expenses

                                  (4     (4

Depreciation, depletion and amortization and valuation allowances

             (7     (44     (225     (109     (385

Other expenses

                    (550     (6,101     (36     (6,687

Pre-tax income from producing activities

             12        204        1,308        79        1,603   

Income tax

                    (95     (285     (34     (414

Results of oil and gas producing activities

             12        109        1,023        45        1,189   

 

S-12


Table of Contents

COST INCURRED

The following tables set forth the costs incurred in the Group’s oil and gas property acquisition, exploration and development activities, including both capitalized and expensed amounts. They do not include costs incurred related to oil and gas transportation and LNG liquefaction and transportation activities.

 

     Consolidated subsidiaries  

(M)

   Europe      Africa      Americas      Middle
East
     Asia      Total  

2009

                 

Proved property acquisition

     71         45         1,551         105                 1,772   

Unproved property acquisition

     26         8         403                 21         458   

Exploration costs

     284         475         222         87         123         1,191   

Development costs(a)

     1,658         3,288         618         250         1,852         7,666   

Total cost incurred

     2,039         3,816         2,794         442         1,996         11,087   

2010

                 

Proved property acquisition

     162         137         26         139         21         485   

Unproved property acquisition

     5         124         1,186         8         619         1,942   

Exploration costs

     361         407         276         17         250         1,311   

Development costs(a)

     1,565         3,105         718         247         2,007         7,642   

Total cost incurred

     2,093         3,773         2,206         411         2,897         11,380   

2011

                 

Proved property acquisition

     298         10         413         2         251         974   

Unproved property acquisition

     1         397         1,692         3         14         2,107   

Exploration costs

     505         384         239         17         417         1,562   

Development costs(a)

     2,352         3,895         1,329         329         2,823         10,728   

Total cost incurred

     3,156         4,686         3,673         351         3,505         15,371   

 

     Equity affiliates  

(M)

   Europe      Africa      Americas      Middle
East
     Asia      Total  

2009

                 

Proved property acquisition

                                               

Unproved property acquisition

                                               

Exploration costs

                     22         3                 25   

Development costs(a)

             28         93         293         23         437   

Total cost incurred

             28         115         296         23         462   

2010

                 

Proved property acquisition

                                               

Unproved property acquisition

                                               

Exploration costs

             4         30         4                 38   

Development costs(a)

             20         99         476         73         668   

Total cost incurred

             24         129         480         73         706   

2011

                 

Proved property acquisition

                                     2,691         2,691   

Unproved property acquisition

                                     1,116         1,116   

Exploration costs

                     2                         2   

Development costs(a)

             2         106         314         939         1,361   

Total cost incurred

             2         108         314         4,746         5,170   

 

(a) Including asset retirement costs capitalized during the year and any gains or losses recognized upon settlement of asset retirement obligation during the year.

 

S-13


Table of Contents

CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES

The following tables do not include capitalized costs related to oil and gas transportation and LNG liquefaction and transportation activities.

 

     Consolidated subsidiaries  

(M)

   Europe     Africa     Americas     Middle
East
    Asia     Total  
As of December 31, 2009             

Proved properties

     30,613        27,557        7,123        5,148        10,102        80,543   

Unproved properties

     337        1,138        839        30        555        2,899   

Total capitalized costs

     30,950        28,695        7,962        5,178        10,657        83,442   

Accumulated depreciation, depletion and amortization

     (21,870     (13,510     (2,214     (3,325     (3,085     (44,004

Net capitalized costs

     9,080        15,185        5,748        1,853        7,572        39,438   

As of December 31, 2010

            

Proved properties

     31,735        32,494        7,588        5,715        12,750        90,282   

Unproved properties

     402        1,458        2,142        49        1,433        5,484   

Total capitalized costs

     32,137        33,952        9,730        5,764        14,183        95,766   

Accumulated depreciation, depletion and amortization

     (23,006     (16,716     (2,302     (3,849     (4,092     (49,965

Net capitalized costs

     9,131        17,236        7,428        1,915        10,091        45,801   

As of December 31, 2011

            

Proved properties

     34,308        37,032        8,812        6,229        17,079        103,460   

Unproved properties

     460        1,962        4,179        62        911        7,574   

Total capitalized costs

     34,768        38,994        12,991        6,291        17,990        111,034   

Accumulated depreciation, depletion and amortization

     (24,047     (18,642     (2,294     (4,274     (5,066     (54,323

Net capitalized costs

     10,721        20,352        10,697        2,017        12,924        56,711   

 

     Equity affiliates  

(M)

   Europe      Africa     Americas     Middle
East
    Asia     Total  

As of December 31, 2009

             

Proved properties

             610        726        2,404               3,740   

Unproved properties

                    135               62        197   

Total capitalized costs

             610        861        2,404        62        3,937   

Accumulated depreciation, depletion and amortization

             (387     (171     (1,723            (2,281

Net capitalized costs

             223        690        681        62        1,656   

As of December 31, 2010

             

Proved properties

             639        887        3,110               4,636   

Unproved properties

             25        168               138        331   

Total capitalized costs

             664        1,055        3,110        138        4,967   

Accumulated depreciation, depletion and amortization

             (462     (307     (2,029            (2,798

Net capitalized costs

             202        748        1,081        138        2,169   

As of December 31, 2011

             

Proved properties

                    731        3,496        3,973        8,200   

Unproved properties

                                  1,146        1,146   

Total capitalized costs

                    731        3,496        5,119        9,346   

Accumulated depreciation, depletion and amortization

                    (96     (2,337     (213     (2,646

Net capitalized costs

                    635        1,159        4,906        6,700   

 

S-14


Table of Contents

STANDARDIZED MEASURE OF

DISCOUNTED FUTURE NET CASH FLOWS

(EXCLUDING TRANSPORTATION)

 

The standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities was developed as follows:

 

 

estimates of proved reserves and the corresponding production profiles are based on existing technical and economic conditions;

 

 

the estimated future cash flows are determined based on prices used in estimating the Group’s proved oil and gas reserves;

 

 

the future cash flows incorporate estimated production costs (including production taxes), future development costs and asset retirement costs. All cost estimates are based on year-end technical and economic conditions;

 

 

future income taxes are computed by applying the year-end statutory tax rate to future net cash flows after consideration of permanent differences and future income tax credits; and

 

 

future net cash flows are discounted at a standard discount rate of 10%.

These principles applied are those required by ASC 932 and do not reflect the expectations of real revenues from these reserves, nor their present value; hence, they do not constitute criteria for investment decisions. An estimate of the fair value of reserves should also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserves estimates.

 

 

S-15


Table of Contents
    Consolidated subsidiaries  

(M)

  Europe     Africa     Americas     Middle
East
    Asia     Total  

As of December 31, 2009

           

Future cash inflows

    50,580        107,679        18,804        9,013        32,004        218,080   

Future production costs

    (11,373     (23,253     (8,286     (2,831     (6,996     (52,739

Future development costs

    (12,795     (21,375     (5,728     (698     (6,572     (47,168

Future income taxes

    (17,126     (36,286     (1,293     (2,041     (5,325     (62,071

Future net cash flows, after income taxes

    9,286        26,765        3,497        3,443        13,111        56,102   

Discount at 10%

    (3,939     (13,882     (2,696     (1,558     (8,225     (30,300

Standardized measure of discounted future net cash flows

    5,347        12,883        801        1,885        4,886        25,802   

As of December 31, 2010

           

Future cash inflows

    65,644        142,085        42,378        14,777        41,075        305,959   

Future production costs

    (16,143     (29,479     (19,477     (4,110     (6,476     (75,685

Future development costs

    (18,744     (25,587     (8,317     (3,788     (8,334     (64,770

Future income taxes

    (20,571     (51,390     (3,217     (2,541     (7,281     (85,000

Future net cash flows, after income taxes

    10,186        35,629        11,367        4,338        18,984        80,504   

Discount at 10%

    (5,182     (16,722     (8,667     (2,106     (11,794     (44,471

Standardized measure of discounted future net cash flows

    5,004        18,907        2,700        2,232        7,190        36,033   

As of December 31, 2011

           

Future cash inflows

    85,919        167,367        53,578        14,297        67,868        389,029   

Future production costs

    (18,787     (31,741     (22,713     (3,962     (12,646     (89,849

Future development costs

    (21,631     (22,776     (11,548     (3,110     (11,044     (70,109

Future income taxes

    (28,075     (71,049     (4,361     (2,794     (12,963     (119,242

Future net cash flows, after income taxes

    17,426        41,801        14,956        4,431        31,215        109,829   

Discount at 10%

    (9,426     (17,789     (12,298     (2,186     (20,717     (62,416

Standardized measure of discounted future net cash flows

    8,000        24,012        2,658        2,245        10,498        47,413   

Minority interests in future net cash flows as of

           

December 31, 2009

    212        60                             272   

December 31, 2010

    273        344                             617   

December 31, 2011

           558                             558   
    Equity affiliates  

(M)

  Europe     Africa     Americas     Middle
East
    Asia     Total  

As of December 31, 2009

           

Future cash inflows

           1,432        16,750        48,486               66,668   

Future production costs

           (624     (6,993     (30,739            (38,356

Future development costs

           (26     (1,924     (3,891            (5,841

Future income taxes

           (245     (3,650     (1,843            (5,738

Future net cash flows, after income taxes

           537        4,183        12,013               16,733   

Discount at 10%

           (239     (2,816     (6,383            (9,438

Standardized measure of discounted future net cash flows

           298        1,367        5,630               7,295   

As of December 31, 2010

           

Future cash inflows

           1,814        22,293        59,472               83,579   

Future production costs

           (765     (8,666     (40,085            (49,516

Future development costs

           (26     (2,020     (3,006            (5,052

Future income taxes

           (349     (5,503     (2,390            (8,242

Future net cash flows, after income taxes

           674        6,104        13,991               20,769   

Discount at 10%

           (203     (3,946     (7,386            (11,535

Standardized measure of discounted future net cash flows

           471        2,158        6,605               9,234   

As of December 31, 2011

           

Future cash inflows

           210        29,887        64,977        7,116        102,190   

Future production costs

           (95     (17,393     (39,800     (2,683     (59,971

Future development costs

                  (1,838     (2,809     (1,297     (5,944

Future income taxes

           (29     (5,152     (3,942     (2,280     (11,403

Future net cash flows, after income taxes

           86        5,504        18,426        856        24,872   

Discount at 10%

           (36     (3,652     (9,757     (196     (13,641

Standardized measure of discounted future net cash flows

           50        1,852        8,669        660        11,231   

 

S-16


Table of Contents

CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED

FUTURE NET CASH FLOWS

 

     Consolidated subsidiaries  

(M)

   2009     2010     2011  

Beginning of year

     15,986        25,802        36,033   

Sales and transfers, net of production costs

     (17,266     (22,297     (27,026

Net change in sales and transfer prices and in production costs and other expenses

     35,738        30,390        44,315   

Extensions, discoveries and improved recovery

     (267     716        1,680   

Changes in estimated future development costs

     (4,847     (7,245     (4,798

Previously estimated development costs incurred during the year

     7,552        7,896        9,519   

Revisions of previous quantity estimates

     164        5,523        1,288   

Accretion of discount

     1,599        2,580        3,603   

Net change in income taxes

     (12,455     (6,773     (16,925

Purchases of reserves in place

     230        442        885   

Sales of reserves in place

     (632     (1,001     (1,161

End of year

     25,802        36,033        47,413   
     Equity affiliates  

(M)

   2009     2010     2011  

Beginning of year

     5,301        7,295        9,234   

Sales and transfers, net of production costs

     (987     (1,583     (1,991

Net change in sales and transfer prices and in production costs and other expenses

     2,789        2,366        3,715   

Extensions, discoveries and improved recovery

     407                 

Changes in estimated future development costs

     (88     195        (383

Previously estimated development costs incurred during the year

     854        651        635   

Revisions of previous quantity estimates

     (790     308        (749

Accretion of discount

     530        730        923   

Net change in income taxes

     (721     (728     (1,341

Purchases of reserves in place

                   1,812   

Sales of reserves in place

                   (624

End of year

     7,295        9,234        11,231   

 

S-17


Table of Contents

OTHER INFORMATION

Net gas production, production prices and production costs

 

     Consolidated subsidiaries  

  

   Europe      Africa      Americas      Middle
East
     Asia      Total  
2009                  

Natural gas production available for sale (Mcf/d)(a)

     1,643         480         545         297         1,224         4,189   

Production prices(b)

                 

Oil (/b)

     40.76         40.77         36.22         39.94         37.66         40.38   

Bitumen (/b)

                     23.17                         23.17   

Natural gas (/kcf)

     4.81         1.33         1.56         0.72         4.47         3.70   

Production costs per unit of production (/boe)(c)

                 

Total liquids and natural gas

     5.30         4.35         3.59         3.86         2.52         4.30   

Bitumen

                     25.45                         25.45   
     Equity affiliates  

  

   Europe      Africa      Americas      Middle
East
     Asia      Total  
2009                  

Natural gas production available for sale (Mcf/d)(a)

                             268                 268   

Production prices(b)

                 

Oil (/b)

             42.98         33.14         43.98                 42.18   

Bitumen (/b)

                                               

Natural gas (/kcf)

                             3.53                 3.53   

Production costs per unit of production (/boe)(c)

                 

Total liquids and natural gas

             4.21         2.24         2.81                 2.81   

Bitumen

                                               
     Consolidated subsidiaries  

  

   Europe      Africa      Americas      Middle
East
     Asia      Total  

2010

                 

Natural gas production available for sale (Mcf/d)(a)

     1,603         608         732         375         1,234         4,552   

Production prices(b)

                 

Oil (/b)

     55.70         56.18         45.28         55.83         52.33         55.39   

Bitumen (/b)

                     33.19                         33.19   

Natural gas (/kcf)

     5.17         1.55         1.83         0.63         5.67         3.94   

Production costs per unit of production (/boe)(c)

                 

Total liquids and natural gas

     6.23         4.53         3.29         4.82         2.93         4.72   

Bitumen

                     17.49                         17.49   
     Equity affiliates  

  

   Europe      Africa      Americas      Middle
East
     Asia      Total  

2010

                 

Natural gas production available for sale (Mcf/d)(a)

                             650                 650   

Production prices(b)

                 

Oil (/b)

             53.96         43.81         57.03                 54.95   

Bitumen (/b)

                                               

Natural gas (/kcf)

                             2.30                 2.30   

Production costs per unit of production (/boe)(c)

                 

Total liquids and natural gas

             6.31         2.76         1.54                 1.91   

Bitumen

                                               

 

S-18


Table of Contents
     Consolidated subsidiaries  
      Europe      Africa      Americas      Middle
East
     Asia      Total  

2011

                 

Natural gas production available for sale (Mcf/d)(a)

     1,350         607         839         424         1,162         4,382   

Production prices(b)

                 

Oil (/b)

     74.24         74.72         55.13         73.73         68.76         73.34   

Bitumen (/b)

                     31.36                         31.36   

Natural gas (/kcf)

     6.58         1.81         2.06         0.54         7.45         4.72   

Production costs per unit of production (/boe)(c)

                 

Total liquids and natural gas

     6.86         5.14         3.41         5.36         3.40         5.20   

Bitumen

                     20.70                         20.70   
     Equity affiliates  
      Europe      Africa      Americas      Middle
East
     Asia      Total  

2011

                 

Natural gas production available for sale (Mcf/d)(a)

                             891         457         1,348   

Production prices(b)

                 

Oil (/b)

             66.21         61.15         77.07         30.75         73.61   

Bitumen (/b)

                                               

Natural gas (/kcf)

                             1.29         0.95         1.23   

Production costs per unit of production (/boe)(c)

                 

Total liquids and natural gas

             1.99         2.75         1.66         0.79         1.61   

Bitumen

                                               

 

(a) The reported volumes are different from those shown in the reserves table due to gas consumed in operations.
(b) The volumes used for calculation of the average sales prices are the ones sold from the Group’s own production.
(c) The volumes of liquids used for this computation are shown in the proved reserves tables of this report. The reported volumes for natural gas are different from those shown in the reserves table due to gas consumed in operations.

 

S-19