Form 20-F
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Form 20-F



(Mark One)





For the fiscal year ended December 31, 2012



¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from             to            



¨ 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




(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


(Address of Principal Executive Offices)

Patrick de La Chevardière

Chief Financial Officer


2, place Jean Millier

La Défense 6

92400 Courbevoie


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   New York Stock Exchange*
American Depositary Shares   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.


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


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.

2,365,933,146 Shares, par value 2.50 each, as of December 31, 2012

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



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Item 1.


Identity of Directors, Senior Management and Advisers


Item 2.


Offer Statistics and Expected Timetable


Item 3.


Key Information


Selected Financial Data


Exchange Rate Information


Risk Factors


Item 4.


Information on the Company


History and Development


Business Overview


Other Matters


Item 4A.


Unresolved Staff Comments


Item 5.


Operating and Financial Review and Prospects


Item 6.


Directors, Senior Management and Employees


Directors and Senior Management




Corporate Governance


Employees and Share Ownership


Item 7.


Major Shareholders and Related Party Transactions


Item 8.


Financial Information


Item 9.


The Offer and Listing


Item 10.


Additional Information


Item 11.


Quantitative and Qualitative Disclosures About Market Risk


Item 12.


Description of Securities Other than Equity Securities


Item 13.


Defaults, Dividend Arrearages and Delinquencies


Item 14.


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


Item 15.


Controls and Procedures


Item 16A.


Audit Committee Financial Expert


Item 16B.


Code of Ethics


Item 16C.


Principal Accountant Fees and Services


Item 16D.


Exemptions from the Listing Standards for Audit Committees


Item 16E.


Purchases of Equity Securities by the Issuer and Affiliated Purchasers


Item 16F.


Change in Registrant’s Certifying Accountant


Item 16G.


Corporate Governance


Item 16H.


Mine Safety Disclosure


Item 17.


Financial Statements


Item 18.


Financial Statements


Item 19.






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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, 2012.

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, 2012. 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 website at and from certain commercial document retrieval services. See also “Item 10. Additional Information — Documents on Display”.



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



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



American Depositary Receipts evidencing ADSs.



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



Barrels of crude oil, condensates, NGL or bitumen.






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 condensates plus NGL.



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.



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



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



Liquids consist of crude oil, bitumen, condensates and NGL.



Liquefied natural gas.



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. LPG is included in NGL.



Natural gas liquids (NGL) are a mixture of light hydrocarbons that exist in the gaseous phase at atmospheric pressure and are recovered as liquids in gas processing plants; NGL include very light hydrocarbons (ethane, propane and butane).


“oil and gas”

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



As used in this report, “project” may encompass different meanings, such as properties, agreements, investments, developments, phases, activities or components, each of which may also informally be described as a “project”. Such use is for convenience only and is not intended as a precise description of the term “project” as it relates to any specific governmental law or regulation.


“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,



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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 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 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.



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



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.



Temporary shutdowns of facilities for maintenance, overhaul and upgrading.




   barrel   k    thousand


   cubic feet   M    million


   barrel of oil equivalent   B    billion


   metric ton   W    watt


   cubic meter   GWh    gigawatt-hour


   per day   TWh    terawatt-hour


   per year   Wp    watt peak
     Btu    British thermal unit



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1 acre

   = 0.405 hectares   

1 b

   = 42 U.S. gallons   

1 boe

   = 1 b of crude oil    = 5,434 cf of gas in 2012(a)
      = 5,447 cf of gas in 2011
      = 5,478 cf of gas in 2010

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   



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.



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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”.



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Not applicable.


Not applicable.







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, 2012, 2011, 2010, 2009 and 2008. 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.



(M , except share and per share data)   2012     2011     2010     2009     2008  



Revenues from sales

    182,229        166,550        140,476        112,153        160,331   

Net income, Group share

    10,694        12,276        10,571        8,447        10,590   

Earnings per share

    4.74        5.46        4.73        3.79        4.74   

Fully diluted earnings per share

    4.72        5.44        4.71        3.78        4.71   



Cash flow from operating activities

    22,462        19,536        18,493        12,360        18,669   

Total expenditures

    22,943        24,541        16,273        13,349        13,640   



Total assets

    171,829        164,049        143,718        127,753        118,310   

Non-current financial debt

    22,274        22,557        20,783        19,437        16,191   

Non-controlling interests

    1,281        1,352        857        987        958   

Shareholders’ equity — Group share

    72,912        68,037        60,414        52,552        48,992   

Common shares

    5,915        5,909        5,874        5,871        5,930   



Dividend per share (euros)

    2.34 (a)      2.28        2.28        2.28        2.28   

Dividend per share (dollars)

    $3.05 (a)(b)      $2.97        $3.15        $3.08        $3.01   



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

    2,255,801,563        2,247,479,529        2,234,829,043        2,230,599,211        2,234,856,551   

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

    2,266,635,745        2,256,951,403        2,244,494,576        2,237,292,199        2,246,658,542   



Subject to approval by the shareholders’ meeting on May 17, 2013.


Estimated dividend in dollars includes the first quarterly interim dividend of $0.73 paid in September 2012 and the second quarterly interim dividend of $0.78 paid in December 2012, as well as the third quarterly interim dividend of 0.59 payable in March 2013 (ADR-related payment in April 2013) and the proposed final dividend of 0.59 payable in June 2013 (ADR-related payment in July 2013), both converted at a rate of $1.30/.


The number of common shares shown has been used to calculate per share amounts.



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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.




   Average Rate  











The table below shows the high and low dollar/euro exchange rates for the three months ended December 31, 2012, and for the first three months of 2013, based on the daily ECB reference exchange rates published during the relevant month expressed in dollars per 1.00.




   High      Low  

September 2012

     1.3095         1.2568   

October 2012

     1.3120         1.2877   

November 2012

     1.2994         1.2694   

December 2012

     1.3302         1.2905   

January 2013

     1.3550         1.3012   

February 2013

     1.3644         1.3077   

March 2013(a)

     1.3090         1.2910   



Through March 25, 2013.

The ECB reference exchange rate on March 25, 2013, for the dollar against the euro was $1.2935/.





For the period 2008 — 2012, 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: 2008 — 1.47; 2009 — 1.40; 2010 — 1.32; 2011 — 1.40; and 2012 —1.29.



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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”.

Our operating results and future rate of growth are exposed to the effects of changing commodity prices.

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 unconventional energies as well as changes in the valorization of oil sands, which may affect our realized prices, notably under our long-term gas sales contracts, and asset valuations, notably in North America;


cost and availability of new technology;


governmental regulations and actions;


global economic and financial market conditions;


war or other conflicts;


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 2013, 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 0.110 billion (calculated with a base case exchange rate of $1.30 per 1.00 and a Brent price of $100 per barrel). 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 a review of the Group’s properties and oil and natural gas reserves. Such review would reflect the Company’s view based on estimates, assumptions and judgments and could result in a reduction in the Group’s reported reserves and/or a charge for impairment that could have a significant effect on our results 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, negatively impact our asset sale program and reduce our liquidity, thereby decreasing our ability to finance capital expenditures and/or causing us to cancel or postpone investment projects. If we are unable to follow through with investment 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 significant 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 downstream earnings are primarily dependent upon the supply and demand for refined products and the associated margins on refined product sales, with the impact of changes in oil and gas prices on downstream earnings being dependent upon the speed at which the prices of refined products adjust to reflect movements in oil and gas prices.

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 that we extract from underground reserves developed as part of our Upstream business. The development of oil and gas fields, the construction of facilities and the drilling of production or injection wells is capital intensive, requires advanced technology and, due to difficult environmental challenges, cost projections are uncertain. In order for this Upstream 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




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acquire and develop new reserves successfully is uncertain and can be negatively affected by a number of factors, including:



the geological nature of oil and gas fields, notably unexpected drilling conditions, including pressure or irregularities in geological formations;


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


equipment failures, fires, blow-outs or accidents;


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


our inability to anticipate market changes in a timely manner;


adverse weather conditions;


compliance with both anticipated and unanticipated governmental requirements, including U.S. and EU regulations that may give a competitive advantage to companies not subject to such regulations;


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 and development 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. It is impossible to guarantee that new reserves of oil and gas will be discovered in sufficient quantities to replace our reserves currently being developed, produced and marketed. Furthermore, some of these factors may also affect our projects and facilities further down the oil and gas chain. 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 reserves 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 that are beyond our control and that 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 to which we are entitled 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.

Our production growth depends on the delivery of our major development projects.

Our targeted production growth relies heavily on the successful execution of our major development projects, which are complex and capital-intensive. These major projects are subject to a number of challenges, including:



negotiations with partners, governments, suppliers, customers and others;




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cost overruns and delays related to the availability of skilled labor or delays in manufacturing and delivery of critical equipment, or shortages in the availability of such equipment;


unforeseen technical difficulties that could delay project startup or cause unscheduled project downtime;


the actual performance of the reservoir and natural field decline; and


timely issuance or renewal of permits and licenses by government agencies.

Poor delivery of any major project that underpins production or production growth could adversely affect our financial performance.

Many of our projects are conducted by equity affiliates. This may reduce our degree of control, as well as our ability to identify and manage risks.

A significant and growing number of our projects are conducted by equity affiliates. In cases where a company in which the Group holds an interest is not the operator, it may have limited influence over, and control of, the behavior, performance and costs of the partnership, its ability to manage risks may be limited and it may, nevertheless, be pursued by regulators or claimants in the event of an incident. Additionally, the partners of the Group (particularly local partners in developing countries) may not be able to meet their financial or other obligations to the projects, which may threaten the viability of a given project, and they may not have the financial capacity to fully indemnify us in the event of an incident.

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 and reserves is located in countries outside of the Organisation for Economic Co-operation and Development (OECD). In recent years, a number of these countries have experienced varying degrees of one or more of the following: economic instability, political volatility, civil war, violent conflict, social unrest and actions of terrorist groups. Any of these conditions alone or in combination could disrupt our operations in any of these regions, causing substantial declines in production. In Africa, which represented 31% of our 2012 combined liquids and gas production, certain of the countries in which we have production have recently suffered from some of these conditions, including Nigeria, where we had in 2012 our highest hydrocarbon production, and Libya. The Middle East, which represented 21% of our 2012 combined liquids and gas production, has recently suffered increased political volatility in connection with violent conflict and

social unrest, including Syria, where European Union (EU) economic sanctions have prohibited us from producing oil and gas, and Yemen. In South America, which represented 8% of our 2012 combined liquids and gas production, certain of the countries in which we have production have recently suffered from some of the above-mentioned conditions, including Argentina and Venezuela. In addition, uncertainties surrounding enforcement of contractual rights in these regions may adversely impact our results. 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 and/or cause certain investors to reduce their holdings of TOTAL’s securities.

TOTAL, like other major international energy 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 political and economic risks. However, there can be no assurance that such events will not have a material adverse impact on the Group.

Our operations throughout emerging countries are subject to intervention by the governments of these countries, which could have an adverse effect on our results of operations.

We have significant exploration and production activities, 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 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;




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the imposition of specific drilling obligations;


price and/or production quota controls and export limits;


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 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 or value of our assets to decrease, potentially having a material adverse effect on our results of operations, including profits.

For example, the Nigerian government has been contemplating new legislation to govern the petroleum industry which, if passed into law, could have an impact on our existing and future activities in that country through increased taxes and/or costs of operation and could adversely affect our financial returns from projects in that country.

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 (for additional information on our Code of Conduct, see “Item 4. Other Matters — Fair operating procedures”). Ethical misconduct or non-compliance with applicable laws and regulations, including non-compliance with anti-bribery, anticorruption and other applicable laws, by us, our partners, agents or others that act on our behalf, could expose TOTAL and our employees to criminal and civil penalties and could be damaging to our reputation and shareholder value. In addition to such penalties, a monitor is likely to be appointed to review the Group’s compliance and internal control procedures and may, if need be, recommend improvements of such procedures. Refer to “Item 8. Legal or arbitration proceedings — Iran” for an overview of the investigation since 2003 by the SEC and Department of Justice (DoJ) concerning the pursuit of business in Iran by certain oil companies, including TOTAL.

At this point, the Company considers that the resolution of this matter is not expected to have a significant impact on the Group’s financial situation or its future planned operations.

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

We engage 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 and specialty chemicals, and involve a wide range of operational risks. These risks include explosions, fires, accidents, equipment failures, leakage of toxic products, emissions or discharges into the air, water or soil, and related environmental and health 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 maritime, river-maritime, pipelines, rail and road), the volumes involved and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environment). 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 and property damage.

Like most industrial groups, TOTAL is concerned by reports of occupational illnesses, particularly those caused by past exposure of the Group’s employees to asbestos. Asbestos exposure has been subject to close monitoring at all of the Group’s business segments. As of December 31, 2012, the Group estimates that the ultimate cost of all pending or future asbestos-related claims is not likely to have a material impact on the Group’s financial position.

Certain segments or activities face specific additional risks. Our Upstream segment activities face risks related to the physical characteristics of oil or gas fields. These risks include eruptions of oil or gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and explosions or fires. These events, which may cause injury, death or environmental damage, can also damage or destroy oil or gas wells as well as equipment and other property, lead to a disruption of the Group’s operations or reduce its production. In addition, since exploration and production activities may take place on sites that are ecologically sensitive (for example, in tropical forests or in a




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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 a Group entity is not the operator, the Group may have reduced influence and control over third parties, which may limit the Group’s ability to manage and control these risks. The activities of our Refining & Chemicals and Marketing & Services segments also entail additional health, safety and environmental risks related to the overall life cycle of the products manufactured, as well as the raw materials used in the manufacturing process, such as catalysts, additives and monomers. 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.

Contracts signed by the Group’s entities may provide for indemnification obligations, either by the Group’s entities in favor of third-parties or by third-parties for the Group’s entities’ benefit, if, for example, an event occurs leading to death, personal injury, property damage or discharge of hazardous materials into the environment. With respect to joint ventures the assets of which are operated by an entity of the Group, contractual terms generally provide that this entity assumes liability for damages caused by its gross negligence or willful misconduct. With respect to joint ventures in which an entity of the Group has an interest but the 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 these types of joint ventures 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 the liability assumed by the third party depends on the context and may be limited by contract. With respect to the Group’s customers, the Group’s entities seek to ensure that their products meet applicable specifications and abide 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 the Group’s results of operations, financial condition and reputation.

Crisis management systems are necessary to respond effectively to emergencies and to avoid potential disruptions in our business and operations.

We have crisis management plans in place to deal with emergencies, such as the leak in the Elgin field in the North Sea (see “Item 4. Other Matters — Environmental protection — Accident risk”). If we do not respond to such emergencies in an appropriate manner, our business and operations could be severely disrupted. We also have implemented business continuity plans in order to continue or resume operations following a shutdown or incident (see “Item 4. Other Matters — Management”). An inability to timely restore or replace critical capacity could prolong the impact of any disruption and could have a material adverse effect on our business and operations.

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 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 countries 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 loss of life, injuries, property damage or environmental damage and could result in regulatory action and legal liability against entities of the Group and damage to our reputation.




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We incur, and will continue to incur, substantial expenditures to comply with increasingly complex laws and regulations aimed at protecting worker health and safety and the natural environment.

These expenditures include:



costs incurred 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;


increased production costs or costs related to changes in product specifications or sales; and


costs related to the decommissioning of drilling platforms and other facilities.

If our financial reserves prove inadequate, such expenditures could have a material effect on our results of operations and our financial position.

Furthermore, in countries where we operate or plan to operate, the introduction of new laws and regulations, stricter enforcement or new interpretations of existing laws and regulations or the imposition of tougher license requirements may also cause the Group’s entities to incur higher 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 the introduction of any new laws and regulations or other factors, we could also be compelled 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.

All TOTAL entities monitor legal and regulatory developments in order to remain in compliance with local and international rules and standards for the assessment and management of industrial and environmental risks. With regard to the permanent shutdown of an activity, the Group’s environmental contingencies and asset retirement obligations are addressed in the “Asset retirement obligation” and “Provisions for environmental contingencies” sections of the Group’s Consolidated Balance Sheet (see Note 19 to the Consolidated Financial Statements). Future expenditures related to asset retirement obligations are accounted for in accordance

with the accounting principles described in Note 1Q to the Consolidated Financial Statements.

Laws and regulations related to climate change and its physical effects may adversely affect our businesses.

Growing public concern in a number of countries over greenhouse gas emissions and climate change, as well as stricter regulations in this area, could adversely affect the Group’s businesses and product sales, increase its operating costs and reduce its profitability.

More of our future production is expected to come from unconventional sources in order to help meet the world’s growing demand for energy. Since energy intensity of oil and gas production from unconventional sources can be higher than that of production from conventional sources, the CO2 emissions produced by the Group’s activities may increase. Therefore, we may incur additional costs from delayed projects or reduced production from certain projects.

In addition, 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.

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.

We are exposed to trading risks that could adversely affect our business.

Our trading business is particularly sensitive to market risk and more specifically to price risk as a consequence of the volatility of oil prices, to liquidity risk (inability to buy or sell oil cargoes at quoted prices) and to performance risk (counterparty does not fulfill its contractual obligations). We use various instruments such as futures, forwards, swaps and options on organized markets or over-the-counter markets to hedge against fluctuations in the price of crude oil, refined products, natural gas, power, coal, emissions and freight-rates. Although we believe we have established appropriate risk management procedures, large market fluctuations may adversely affect our business and results of operations and make it more difficult to optimize revenues from our oil and gas production and to obtain favorable pricing to supply our refineries.




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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 potentially having a material adverse effect on our results of operations, including profits.

We have activities in certain countries that are targeted by economic sanctions under relevant U.S. and EU laws, and if our activities are not conducted in accordance with the relevant conditions, we could be sanctioned or otherwise penalized.

The United States has adopted various laws and regulations designed to restrict trade with Cuba, Iran, Sudan and Syria, and the U.S. Department of State has identified these countries as state sponsors of terrorism. The European Union (“EU”) has similar restrictions with respect to Iran and Syria. A violation of these laws or regulations could result in criminal and material financial penalties, including being prohibited from transacting in U.S. dollars. We currently have limited marketing and trading activities in Cuba and a limited presence in Iran and Syria (for more information, see “Item 4. Other Matters —Cuba, Iran and Syria”). Since the independence of South Sudan on July 9, 2011, TOTAL is no longer present in Sudan.

With respect to Iran, the United States has adopted a number of measures since 1996 that provide for the possible imposition of sanctions against non-U.S. companies engaged in certain activities in and with Iran, especially in Iran’s energy sector. The United States first adopted legislation in 1996 authorizing sanctions against non-U.S. companies doing business in Iran and Libya (the Iran and Libya Sanctions Act, referred to as “ILSA”). In 2006, ILSA was amended to concern only business in Iran (then renamed the Iran Sanctions Act, referred to as “ISA”). Pursuant to ISA, which as described below has since been amended and expanded, the President of the United States is authorized to initiate an investigation into the activities of non-U.S. companies in Iran’s energy sector and the possible imposition of sanctions 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 ISA 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 any of TOTAL’s other activities in Iran. 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. Since 2011, TOTAL has 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 both the list of activities with Iran that could lead to sanctions and the list of sanctions available. In particular, CISADA authorized sanctions for knowingly providing refined petroleum products above certain monetary thresholds to Iran and for providing goods, services, technology, information or support that could directly and significantly either facilitate Iran’s domestic production of refined petroleum products or contribute to Iran’s ability to import refined petroleum products. 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 potentially sanctionable sales of refined petroleum 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.

Since the applicability of the “Special Rule” to TOTAL was announced by the U.S. State Department, the United States has imposed a number of additional measures targeting activities in Iran. On November 21, 2011, President Obama issued Executive Order 13590, which authorized sanctions for knowingly, on or after November 21, 2011, selling, leasing, or providing to Iran goods, services, technology or support above certain monetary thresholds that could directly and significantly contribute to the maintenance or expansion of Iran’s ability to develop petroleum resources located in Iran, or domestic




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production of petrochemical products. TOTAL does not conduct activities in Iran that could be sanctionable under Executive Order 13590. In any event, there is no provision in Executive Order 13590 that modifies the aforementioned “Special Rule”, and the U.S. State Department issued guidance that completion of existing contracts is not sanctionable under Executive Order 13590.

On July 30, 2012, President Obama issued Executive Order 13622, which authorized sanctions for, amongst other activities, (i) knowingly, on or after July 30, 2012, engaging in a significant transaction for the purchase or acquisition of petroleum, petroleum products or petrochemical products from Iran, and (ii) materially assisting, sponsoring or providing financial, material, or technological support for, or goods or services in support of, the National Iranian Oil Company, the Naftiran Intertrade Company, or the Central Bank of Iran. There is no provision in Executive Order 13622 that modifies the aforementioned “Special Rule”. In addition, Executive Order 13622 contains an exception for the Shah Deniz gas field pipeline project, in which we (10%) and Naftiran Intertrade Company (“NICO”) (10%) participate, to supply natural gas from the Shah Deniz gas field in Azerbaijan to Europe and Turkey. We do not conduct activities targeted by Executive Order 13622.

On August 10, 2012, President Obama signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRSHRA”), which, amongst other things, amended ISA and CISADA. ITRSHRA, like CISADA before it, expanded both the list of activities with Iran that could lead to sanctions and the list of sanctions available. Amongst other things, ITRSHRA authorized sanctions for (i) provision to Iran of goods, services, technology, information or support above a certain market value that could directly and significantly facilitate the maintenance or expansion of Iran’s domestic production of refined petroleum products, including any direct and significant assistance with the construction, modernization, or repair of petroleum refineries or infrastructure directly associated with petroleum refineries, (ii) participation in a joint venture established on or after January 1, 2002 with respect to the development of petroleum resources outside of Iran where either the Government of Iran is a substantial partner or investor or where the joint venture could enhance Iran’s ability to develop petroleum resources in Iran, and (iii) owning, operating, controlling or insuring a vessel used to transport crude oil from Iran to another country. ITRSHRA also contains an exception for the Shah Deniz gas field project. We do not conduct activities targeted by ITRSHRA.

ITRSHRA also added a new Section 13(r) to the Securities Exchange Act of 1934, as amended (“Exchange Act”), which requires us to disclose whether TOTAL or any of its

affiliates has engaged during the calendar year in certain Iran-related activities, including those targeted under ISA, without regard to whether such activities are sanctionable under ISA, and any transaction or dealing with the Government of Iran that is not conducted pursuant to a specific authorization of the U.S. government (see “Item 4. Other Matters — Iran”). Section 13(r) also requires us to file a separate notice to the United States Securities and Exchange Commission (“SEC”) concerning any Section 13(r)-related disclosure provided in our annual report. Following receipt of this notice, the SEC must transmit a report to the President and Congress, and the President must initiate an investigation and make a sanctions determination within 180 days after initiating the investigation. We believe that our Iran-related activities required to be disclosed by Section 13(r) are not sanctionable.

Also with regard to Iran, 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 or from an Iranian individual or entity shall require a prior authorization of the competent authorities of the EU Member States. We conduct our activities in compliance with these EU measures.

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

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




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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. The U.S. also has various measures regarding Syria. Since early December 2011, the Group 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 economic sanctions programs, some of which are based on the United Nations Security Council resolutions referred to above, against targeted foreign countries, territories, entities and individuals (including those engaged in activities related to terrorism or the proliferation of weapons of mass destruction and other threats to the national security, foreign policy or economy of the United States). 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, Sudan and Syria. TOTAL does not believe that these sanctions are applicable to any of its activities in the OFAC-targeted countries.

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, 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. If our presence in Iran were determined to fall within the prohibited scope of these laws, and we 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.

We continue to closely monitor legislative and other developments in France, the EU and the United States in order to determine whether our limited activities or presence in sanctioned or potentially sanctioned jurisdictions could subject us to the application of sanctions. We cannot assure that current or future regulations or developments will not have a negative impact on our business or reputation.










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 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.






Based on market capitalization (in dollars) as of December 31, 2012.

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TOTAL’s worldwide operations in 2012 were conducted through three business segments: Upstream, Refining & Chemicals and Marketing & Services. 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
     Africa      Rest of



Non-Group sales(a)

     45,981         103,862         17,648         17,921         14,649         200,061   

Property, plant and equipment, intangible assets, net

     4,560         17,697         15,220         24,999         19,714         82,190   

Capital expenditures

     1,589         4,406         3,148         7,274         6,526         22,943   



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   



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   



Non-Group sales from continuing operations.





TOTAL’s Upstream segment includes the activities of Exploration & Production and Gas & Power. The Group has exploration and production activities in more than fifty countries and produces oil or gas in approximately thirty countries. Gas & Power 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. Effective July 1, 2012, the Upstream segment no longer includes the activities of New Energies, which are now reported with Marketing & Services. As a result, certain information has been restated according to the new organization.



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 77% of the 2,016 Mboe added to the Upstream segment’s proved reserves during the three-year period ended December 31, 2012 (before deducting production and sales of reserves in place and adding any acquisitions of reserves in place during this period). The remaining 23% comes from revisions of previous estimates. The level of revisions during this three-year period was significantly impacted by the effects of the increase of the reference oil price (from $59.91/b in 2009 to $111.13/b in 2012 for Brent crude) and the decrease of the U.S. onshore gas price (from $4.21/MBtu in 2011 to $2.85/MBtu in 2012 for Henry Hub), which together induced a substantial negative revision.

In 2012, the exploration investments of consolidated subsidiaries amounted to 2,634 million (including exploration bonuses included in the unproved property acquisition costs). Exploration investments were made primarily in Angola, the United Kingdom, the United States, Norway, Iraq, Nigeria, Brazil, Malaysia, the Republic of Congo and French Guiana. In 2011, the exploration investments of consolidated subsidiaries amounted to 1,629 million (including exploration bonuses included in the unproved property acquisition costs). The main exploration investments were made 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) notably in Angola, Norway, Brazil, the United Kingdom, the United States, Indonesia, Nigeria and Brunei.

The Group’s consolidated Exploration & Production subsidiaries’ development investments amounted to 14 billion in 2012, primarily in Angola, Norway, Canada,




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Australia, Nigeria, the United Kingdom, Gabon, Kazakhstan, Indonesia, the Republic of the Congo, the United States and Russia. 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, mostly in Angola, Nigeria, Kazakhstan, Norway, Indonesia, the Republic of the Congo, the United Kingdom, the United States, Canada, Thailand, Gabon and Australia.


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, 2012, 2011 and 2010, 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 2012, 2011 and 2010 were, respectively, $111.13/b, $110.96/b, and $79.02/b for Brent crude.

As of December 31, 2012, TOTAL’s combined proved reserves of oil and gas were 11,368 Mboe (51% of which were proved developed reserves). Liquids (crude oil, condensates, natural gas liquids and bitumen) represented approximately 50% of these reserves and natural gas the remaining 50%. 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, Argentina and Venezuela), in the Middle East (mainly in Qatar, the United Arab Emirates and Yemen), and in Asia (mainly in Australia, Kazakhstan and Russia).

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, condensates, 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, condensates, 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 and the United Kingdom), in Africa (mainly in Angola, Gabon, Libya, Nigeria and the Republic of the




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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).

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 25% of TOTAL’s reserves as of December 31, 2012). 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.

Lastly, for any type of contract, a decrease of the reference price of petroleum products may involve a significant reduction of proved reserves.


For the full year 2012, average daily oil and gas production was 2,300 kboe/d compared to 2,346 kboe/d in 2011. Liquids accounted for approximately 53% and natural gas for approximately 47% of TOTAL’s combined liquids and natural gas production in 2012.

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 geographic area” on the following pages for a description of TOTAL’s producing assets.

As in 2011 and 2010, substantially all of the liquids production from TOTAL’s Upstream segment in 2012 was marketed by the Trading & Shipping division of TOTAL’s Refining & Chemicals segment (see the table “— Business Overview —Trading & Shipping — Trading’s crude oil sales and supply and refined products sales”).

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 2013-2015 to be 4,070 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)”).




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      2012      2011      2010  


     574         705         713         517         715         659         616         712         756   


     6         90         23         16         94         33         25         87         41   


     172         44         179         128         39         135         157         34         163   


                             2         1         3         9         2         9   


     54         19         57         55         17         58         63         20         67   


     62                 62         20                 20         55                 55   


     173         521         279         179         534         287         192         542         301   

The Congo, Republic of

     107         31         113         117         30         123         115         27         120   

North America

     25         246         69         27         227         67         30         199         65   


     12                 12         11                 11         10                 10   

United States

     13         246         57         16         227         56         20         199         55   

South America

     59         682         182         71         648         188         76         569         179   


     12         394         83         14         397         86         14         381         83   


     3         124         27         3         118         25         3         94         20   


     1         23         6         5         27         11         11         34         18   

Trinidad & Tobago

     4         70         16         4         47         12         3         2         3   


     39         71         50         45         59         54         45         58         55   


     27         1,089         221         27         1,160         231         28         1,237         248   


             29         5                 25         4                 6         1   


     2         54         12         2         56         13         2         59         14   


             7         1                                                   


     16         605         132         18         757         158         19         855         178   


             127         16                 119         15                 114         14   


     9         267         55         7         203         41         7         203         41   


     27         909         195         22         525         119         13         56         23   


     4         64         16         4         57         14         3         54         13   


     23         845         179         18         468         105         10         2         10   


     197         1,259         427         245         1,453         512         269         1,690         580   


     2         58         13         5         69         18         5         85         21   

The Netherlands

     1         184         33         1         214         38         1         234         42   


     159         622         275         172         619         287         183         683         310   

United Kingdom

     35         395         106         67         551         169         80         688         207   

Middle East

     311         990         493         317         1,370         570         308         1,185         527   

United Arab Emirates

     233         70         246         226         72         240         207         76         222   


                                                     2                 2   


     6                 6                                                   


     24         61         37         24         62         36         23         55         34   


     38         560         139         44         616         155         49         639         164   


                             11         218         53         14         130         39   


     10         299         65         12         402         86         13         285         66   

Total production

     1,220         5,880         2,300         1,226         6,098         2,346         1,340         5,648         2,378   

Including production share of equity affiliates

     308         1,635         611         316         1,383         571         300         781         444   


                             10         3         10         19         4         20   


                             4                 4         7                 7   


     38         7         40         44         7         45         45         6         46   

United Arab Emirates

     225         61         237         219         62         231         199         66         212   


     23         60         34         22         62         34         22         55         32   


     7         364         74         8         382         78         8         367         75   


     15         844         171         9         465         95                           


             299         55                 402         74                 283         52   



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



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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, 2012 (a)      
      Year of
entry into
the country


(Group share in %)



(Group share in %)




               Tin Fouye Tabankort (35.00%)



Girassol, Jasmim,

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


Cabinda Block 0 (10.00%)

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

Oombo (Block 3/91) (50.00%)



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%)



zones 15, 16 & 32 (75.00%)(b)

zones 70 & 87 (75.00%)(b)

zones 129 & 130 (30.00%)(b)

zones 130 & 131 (24.00%)(b)



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%)

OML 138 (20.00%)


Shell Petroleum Development Company (SPDC 10.00%)

OML 118 - Bonga (12.50%)

The Congo, Republic of


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%)



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      Year of
entry into
the country


(Group share in %)



(Group share in %)

North America



               Surmont (50.00%)

United States


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

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

Chinook (33.33%)

Tahiti (17.00%)

South America




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%)



San Alberto (15.00%)

San Antonio (15.00%)

Itaú (41.00%)

Trinidad & Tobago

               Angostura (30.00%)


               PetroCedeño (30.323%) Yucal Placer (69.50%)




               Several assets in UJV GLNG (27.50%)(d)


   1986    Maharaja Lela Jamalulalam (37.50%)     


   2006         South Sulige (49.00%)



Bekapai (50.00%)

Handil (50.00%)

Peciko (50.00%)

Sisi-Nubi (47.90%)

South Mahakam (50.00%)

Tambora (50.00%)

Tunu (50.00%)


Badak (1.05%)

Nilam-gas and condensates (9.29%)

Nilam-oil (10.58%)


   1992    Yadana (31.24%)     


               Bongkot (33.33%)

Commonwealth of Independent States



               Shah Deniz (10.00%)


   1991    Kharyaga (40.00%)   
               Several fields through the participation in Novatek (15.34%)





Lacq (100.00%)

Meillon (100.00%)

Pécorade (100.00%)

Lagrave (100.00%)

Lanot (100.00%)




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      Year of
entry into
the country


(Group share in %)



(Group share in %)



Atla (40.00%)

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%)

Islay (5.51%)(e)

Kristin (6.00%)

Kvitebjørn (5.00%)

Mikkel (7.65%)

Morvin (6.00%)

Oseberg (14.70%)

Oseberg East (14.70%)

Oseberg South (14.70%)

Sleipner East (10.00%)

Sleipner West (9.41%)

Snøhvit (18.40%)

Tor (48.20%)

Troll I (3.69%)

Troll II (3.69%)

Tune (10.00%)

Tyrihans (23.18%)

Vale (24.24%)

Vilje (24.24%)

Visund (7.70%)

Visund South (7.70%)

Yttergryta (24.50%)

The Netherlands


F6a gaz (55.66%)

F6a huile (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%)

L4d (55.66%)


E16a (16.92%)

E17a/E17b (14.10%)

J3b/J6 (25.00%)

Q16a (6.49%)



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      Year of
entry into
the country


(Group share in %)



(Group share in %)

United Kingdom


Alwyn North, Dunbar, Ellon, Grant,

Nuggets (100.00%)

Elgin-Franklin (EFOG 46.17%)(f)

Forvie Nord (100.00%)

Glenelg (49.47%)

Islay (94.49%)(e)

Jura (100.00%)

West Franklin (EFOG 46.17%)(f)


Bruce (43.25%)

Markham unitized fields (7.35%)

Keith (25.00%)

Middle East



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

Abu Dhabi offshore (13.33%)(g)

Abu Dhabi onshore (9.50%)(h)

GASCO (15.00%)

ADGAS (5.00%)


   1920         Halfaya (18.75%)(i)



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

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


   1936    Al Khalij (100.00%)   
               North Field-Bloc NF Dolphin (24.50%) North Field-Bloc NFB (20.00%) North Field-Qatargas 2 Train 5 (16.70%)


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


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



The Group’s interest in the local entity is approximately 100% in all cases except for Total Gabon (58.28%) and certain entities in Abu Dhabi and Oman (see notes b through l below).


TOTAL’s stake in the foreign consortium.


TOTAL’s interest in the joint venture with Chesapeake.


TOTAL’s interest in the uncorporated Joint Venture


The field of Islay extends partially in Norway. Total E&P UK holds a 94.49% interest and Total E&P Norge holds a 5.51% interest.


TOTAL has a 46.17% indirect interest in Elgin Franklin through its interest in EFOG.


Through ADMA (equity affiliate), TOTAL has a 13.33% interest and participates in the operating company, Abu Dhabi Marine Operating Company.


Through ADPC (equity affiliate), TOTAL has a 9.50% interest and participates in the operating company, Abu Dhabi Company for Onshore Oil Operation.


TOTAL has an interest of 18.75% in the consortium.


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).


TOTAL has a direct interest of 2.00% in Block 53.


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”.



In 2012, TOTAL’s production in Africa was 713 kboe/d, representing 31% of the Group’s overall production, compared to 659 kboe/d in 2011 and 756 kboe/d in 2010.

In Algeria, TOTAL’s production was 23 kboe/d in 2012, compared to 33 kboe/d in 2011 and 41 kboe/d in 2010. These declines in production were mainly due to the sale in July 2011 of TOTAL’s 48.83% share in CEPSA. All of the Group’s production in Algeria now comes from the Tin Fouyé Tabenkort (TFT) field (35%). TOTAL also has stakes of 37.75% and 47% in the Timimoun and Ahnet gas development projects, respectively.


On the TFT field, plateau production was maintained at 170 kboe/d.


Pursuant to the ALNAFT national agency approval, at end 2010, of the development plan, the Timimoun group, operator of the development and the exploitation of the field, has been created. The answers for the main tendering for the construction of the facility are being processed. A 3D seismic survey has started at year end 2012. Commercial gas production is scheduled to start up by the end of 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




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July 2011. Discussions are underway with the project partners and the authorities. The anticipated plateau production is 4 Bm3/y (400 Mcf/d) as from the end of 2017.

In Angola, the Group’s production was 179 kboe/d in 2012, compared with 135 kboe/d in 2011 and 163 kboe/d in 2010. Production comes mainly from Blocks 0, 14 and 17. Highlights of 2010 to 2012 included the launch of the CLOV project in August 2010, the start-up of production on Pazflor in August 2011, several discoveries on Blocks 15/06 and 17/06 and, finally, the acquisition of interests in Blocks 25, 39 and 40 in the Kwanza basin.



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

Production on Pazflor, which comprises the Perpetua, Zinia, Hortensia and Acacia fields and which started in August 2011, was 196 kb/d in 2012.

The development of CLOV started in 2010 and will result in the installation of a fourth floating production, storage and offloading units (FPSOs) with a production 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 2009 and adds to production from the Benguela-Belize-Lobito-Tomboco and Kuito fields.


The development of the Lianzi (10%) field was approved in 2012. Located in the offshore unitization zone between Angola and the Republic of Congo, this field will be developed by a connection with the existing Benguela-Belize-Lobito-Tomboco platform (Block 14). Production start-up is expected in 2015.


On Block 0, the development of Mafumeira Sul (10%) was approved by the partners and the authorities. This project is the second phase of the development of the Mafumeira field. The first oil is expected in 2015.


On the ultra-deep offshore Block 32 (30%, operator), exploration work continues and the basic engineering studies are underway for the Kaombo project. These studies are expected to permit the development of the discoveries made in the southeast portion of the block through two FPSOs with an estimated capacity of 100 kb/d each. The calls for tender have been issued and the final decision on investment should be made in 2013.


On Block 15/06 (15%), the development of a first production hub including the discoveries located in the northwest portion of the block began in early 2012.

TOTAL has operations on exploration Blocks 33 (55%, operator), 17/06 (30%, operator), 25 (35%, operator), 39 (15%) and 40 (50%, operator). The Group plans to drill for pre-salt targets in Blocks 25, 39 and 40.

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 now complete and start-up is expected mid-2013.

In Cameroon, TOTAL finalized in April 2011 the sale of its entire 75.8% stake in its Upstream subsidiary Total E&P Cameroun. Since that time, the Group no longer owns any exploration or production assets in the country. Production was 3 kboe/d in 2011 and 9 kboe/d in 2010.

In Côte d’Ivoire, TOTAL is active in four deep offshore exploration licenses.

TOTAL is the operator of the CI-100 (60%) license and, since February 2012, the CI-514 (54%) license and also holds, since February 2012, a stake in the CI-515 (45%) and CI-516 (45%) licenses. A comprehensive 3D seismic survey was conducted on the CI-100 license, and the first exploration drilling started at the beginning of January 2013. The 2,000 km2 license is located approximately 100 km southeast of Abidjan in water depths ranging from 1,500 m to 3,100 m.

A 3D seismic survey campaign, covering the whole of the three licenses CI-514, CI-515 and CI-516, was completed in December 2012. The data are currently being interpreted.

In Egypt, TOTAL signed a concession agreement in 2010 and became operator of Block 4 (East El Burullus Offshore). In January 2013, TOTAL sold a 40% interest in Block 4, but continues to operate this license with a 50% stake. The license, located in the Nile river 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 and should start in 2013.

In Gabon, the Group’s production was 57 kboe/d in 2012 compared to 58 kboe/d in 2011 and 67 kboe/d in 2010. The Group’s exploration and production activities in Gabon are mainly carried out by Total Gabon(1), one of the Group’s oldest subsidiaries in sub-Saharan Africa.



Under the Anguille field redevelopment project, the AGM North platform, from which twenty-one additional





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%.



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development wells are to be drilled, was installed in January 2012. The drilling campaign started early in the second quarter of 2012 and production from this platform, which should represent 20 kboe/d, is expected to start in 2013.


On the deep-offshore Diaba license, Total Gabon, the operator, sold off in June 2012 part of its interest, which now stands at 42.5%. A 6,000 km2 3D seismic survey was shot, processed and interpreted in 2010. Initial exploration drilling is planned for the first half of 2013.


Total Gabon farmed into the onshore Mutamba-Iroru (50%), DE7 (30%), and Nziembou (20%) exploration licenses in 2010. Following negative exploration drilling on license DE7, Total Gabon relinquished the license in 2011. After reprocessing the existing seismic data, the Nguongui-updip well was drilled on the Mutamba-Iroru license in 2012 and revealed the presence of hydrocarbons. The commercial viability of this discovery will be investigated further. A 2D seismic survey was made on the Nziembou license in 2012, and an exploration well is due to be drilled in 2014.

In Kenya, TOTAL acquired in September 2011 a 40% stake in five offshore licenses in the Lamu basin (L5, L7, L11a, L11b and L12), representing a total surface area of more than 30,600 km2 in water depths ranging from 100 m to 3,000 m. Following a 3,500 km2 3D seismic survey in the initial exploration period, 25% of the surface area of the five blocks has been relinquished and the decision was made to drill two exploration wells in 2013 on Blocks L7 and L11b. In June 2012, the Group also acquired the L22 offshore license (100%, operator), located in the same basin and covering a surface area of more than 10,000 km2 in water depths ranging from 2,000 m to 3,500 m.

In Libya, the Group’s production was 62 kb/d in 2012, compared to 20 kb/d in 2011 and 55 kb/d in 2010. TOTAL is present in the following contract zones: 15, 16 & 32 (75%(1)), 70 & 87 (75%(1)), 129 & 130 (30%(1)), 130 & 131 (24%(1)), and Block NC 191 (100%(1), operator).

In 2012, production recovered the level preceding the events of 2011 in the country that had caused the interruption of production in late February 2011.



In offshore zones 15, 16 and 32, production resumed in September 2011 and quickly reached its former level. The drilling of two wells is expected to start in the second quarter of 2013.


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


level. In addition, the Group is continuing the development of the Dahra and Garian fields, where production is expected to start at the beginning of 2014.


In onshore zones 129, 130 and 131, production resumed in October 2011. A return to plateau level production occurred in 2012. The seismic campaign started before the events and will be pursued in 2013.


In the onshore Murzuk basin, following a successful appraisal well drilled on the discovery made on a portion of Block NC 191, a development plan was submitted to the authorities in 2009. After the interruption related to the events of 2011 in the country, discussions with the authorities have restarted.

In Madagascar, TOTAL acquired in 2008 a 60% stake in the Bemolanga 3102 license (operator) to appraise the license’s oil sand accumulations. The exploitation of oil sand accumulations is no longer a consideration, TOTAL is focusing on exploration for conventional hydrocarbons. The conventional exploration of the block is expected to continue in 2013 with a 2D seismic survey following the approval of an additional two-year extension by the local authorities of the exploration phase.

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



Following a 2D seismic survey shot in 2011 on license Ta7, a well has been prepared and drilling operations started in February 2013.


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


A 900 km2 2D seismic shot was taken on Block Ta29 in 2012.


On Block C9, a 3D seismic campaign started at the end of January 2013.

In Morocco, an authorization of recognition was awarded in December 2011 to TOTAL and the ONHYM (National Bureau of Petroleum and Mines) for an offshore zone of 100,000 km2. In the 2012, the Group led geological studies and realized a seabed survey. In December 2012, the authorization of recognition was extended by one year and 3D seismic survey shot of 5,000 km2 started at the end of 2012.





TOTAL’s stake in the foreign consortium.



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In Mozambique, TOTAL acquired a 40% stake in the contract to share the production of the offshore Blocks 3 and 6 in September 2012. Located in the prolific Rovuma basin, these two blocks cover a total surface area of 15,250 km² in water depths ranging from 0 m to 2,500 m. An exploration well was drilled in 2012. The results are currently being analyzed.

In Nigeria, the Group’s production was 279 kboe/d in 2012, compared to 287 kboe/d in 2011 and 301 kboe/d in 2010. This level of production makes of Nigeria the first contributing country for the productions of the Group in 2012. TOTAL has been present in Nigeria since 1962. It operates seven production licenses (OML) out of the thirty-eight in which it has a stake, and two exploration licenses (OPL) out of the five in which it has a stake. TOTAL is also the operator of the exploration Block 1 in the Joint Development Zone (JDZ administered jointly by Nigeria and São Tomé and Principe). The Group is also active in LNG through Nigeria LNG and the Brass LNG project. Regarding recent variations in the mining fields:



In November 2012, TOTAL announced the signing of an agreement to sell its 20% stake in Block OML 138, which includes the Usan field. The agreement is subject to approval by the relevant authorities.


In 2011, TOTAL (operator) increased its stake from 45.9% to 48.6% in Block 1 of the JDZ.


The divestment of the 10% Group’s stakes held through the joint venture operated by Shell Petroleum Development Company (SPDC) in Blocks OML 26 and 42 was finalized in 2011, and in Blocks OML 30, 34 and 40 in 2012. Blocks OML 4, 38 and 41 were sold in 2010.


TOTAL owns 15% of the Nigeria LNG gas liquefaction plant, located on Bonny Island, with an overall LNG capacity of 22Mt/y.

With respect to the Brass LNG gas liquefaction plant project (17%), preliminary work continued in 2012 prior to launching 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:



As part of its joint venture with the Nigerian National Petroleum Company (NNPC), TOTAL pursued the project to increase the gas production capacity of the OML 58 license (40%, operator) from 370 Mcf/d to 550 Mcf/d. The second phase of this project will be the development of additional reserves.

A drilling incident on OML 58 in late March 2012 resulted in the facilities being stopped. The incident

was resolved and production gradually ramped up as of June 2012. The facilities were stopped again and secured in October 2012 due to exceptionally high rainfall. Production resumed in November 2012.


On the OML 112/117 licenses (40%), TOTAL continued development studies in 2012 for the Ima gas field.


On the OML 99 license (40%, operator), engineering work is underway to develop the Ikike field, where production is expected to start in 2016 (estimated capacity: 55 kboe/d).


On the OML 102 license (40%, operator), TOTAL continues to develop the Ofon phase 2 project, which was launched in 2011, with an expected capacity of 60 kboe/d and production start-up scheduled end of 2014. In 2011, the Group also discovered Etisong North, located 15 km of the currently-producing Ofon field. The exploration campaign continued in 2012 with the drilling of the Eben well, which is also south of Ofon. The positive results produced by this well further enhance the appeal of the future Etisong-Eben development hub as a satellite of the Ofon field.


On the deep water acreage, TOTAL drilled three exploration wells in 2012: Obo and Enitimi on JDZ block 1, and Owowo West on OPL 223. Results are under study.


On the OML 130 license (24%, operator), the Akpo field reached plateau production of 225 kboe/d in 2010. The Group is actively working on the Egina field (capacity of 200 kboe/d), for which a development plan has been approved by the relevant authorities. Calls for tender are underway and the contracts should be signed in the second quarter of 2013.


On the OML 138 license (20%, operator), TOTAL started production on the Usan offshore field in February 2012 (180 kb/d, capacity of the FPSO), which reached a level of 120 kboe/d at the end of 2012. As described above, on November 2012, TOTAL signed an agreement on the sale of its 20% stake in Block OML 138. This agreement is subject to approval by the relevant authorities, expected in 2013.


The production that is not operated by the Group in Nigeria comes mainly from the SPDC association, in which TOTAL holds a 10% stake. Gas production by the SPDC association in 2011 remained strong due to the contribution made by the Gbaran-Ubie project, which started up in 2010. However, the sharp increase of oil bunkering in 2012 had an impact on onshore production, as well as on the integrity of the facilities and the environment. TOTAL also holds a 12.5% interest in the Shell Nigeria Exploration and Production Company (SNEPCO) association, which operates notably on the OML 118 license. On this license, the




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Bonga field contributed approximately 15 kboe/d to the Group’s production in 2012.


On the operated deep water acreage, the Bonga Northwest development project was progressed in 2012 on the OML 118 licence (12.5%).

In Uganda, TOTAL finalized in February 2012 its farm-in for an interest of 33.33% covering the EA-1, EA-1A 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.

TOTAL is the operator of EA-1 and EA-1A and a partner on the other licenses. TOTAL and its partners are embarking on an exploration and appraisal program from 2012 onwards.



The Kanywataba exploration well was drilled in June 2012 and produced negative results. The license expired in August 2012 and was returned to the authorities.


The EA-1A license expired in February 2013, following a campaign of several exploration drillings.


On the appraisal license EA-1, a campaign of appraisal wells, production tests and a 3D seismic survey are planned for 2012-2014. Five development plans will be submitted to the authorities before the end of 2013 (Ngiri, Jobi-Rii, Mpyo, Gunya and Jobi East).


On the appraisal license EA-2, the campaign of appraisal wells and production tests started in 2012 will continue in 2013. Several development plans will be submitted to the authorities before the end of 2013 (Waraga, Kasamene, Wahrindi, Kigogole, Ngege, Ngara and Nsoga).


The development plan of the EA-3 production license of the Kingfisher field was finalized by the operator in November 2012 and submitted to the authorities for approval.

In the Republic of Congo, the Group’s production was 113 kboe/d in 2012, compared to 123 kboe/d in 2011 and 120 kboe/d in 2010.



The development of the Lianzi field (26.75%) was approved in 2012. Located in the offshore unitization zone between Angola and the Republic of Congo, this field will be developed by a tieback to the existing Benguela-Belize-Lobito-Tomboco platform (Block 14 in Angola). Production start-up is expected in 2015.



The Moho Bilondo offshore field (53.5%, operator), reached plateau production of 90 kboe/d in mid-2010. The field has now started its decline.

The existence of additional resources in the southern portion of the license was confirmed in 2010, creating the prospects for additional development of the

existing facilities (“Phase 1b”). The basic engineering studies were finished in 2012.

A series of agreements on the contractual and fiscal conditions applicable to the Moho Bilondo license were signed with the authorities in July 2012 and approved by a law passed in October 2012, triggering the development of the northern portion of the license, the potential of which was bolstered by appraisal and exploration wells drilled in 2008 and 2009 (Moho North project). The basic engineering studies were finished in 2012.

The Phase 1b and Moho North projects have been launched in March 2013, with production start-up planned in 2015 and 2016 respectively. The estimated production capacities are about 140 kboe/d in 2017 (“Phase 1b” 40 kboe/d, “Moho Nord” 100 kboe/d).



Production on Libondo (65%, operator), which is part of the Kombi-Likalala-Libondo operating license, started up in March 2011. Plateau production reached 12 kboe/d in 2011. 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 in 2011 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 and subsequently extended by an additional year due to the postponement of the works resulting from the general security situation in the eastern part of the country. This block is located in the Lake Albert region. TOTAL acquired an additional 6.66% of this block in March 2012. The prospecting program is limited to the northern portion of the license, which is outside the Virunga park. A helicopter acquisition of gravimetric and magnetic data was completed in August 2012.

In the Republic of South Sudan, TOTAL holds an interest in Block B and is working with state authorities to resume exploration activities on this zone. Since the independence of the Republic of South Sudan on July 9, 2011, TOTAL is no longer present in Sudan.

North America

In 2012, TOTAL’s production in North America was 69 kboe/d, representing 3% of the Group’s overall production, compared to 67 kboe/d in 2011 and 65 kboe/d in 2010.

In Canada, TOTAL signed in March 2011 a partnership with Suncor related to the Fort Hills and Joslyn mining




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projects and the Voyageur upgrader. This partnership 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. The Group’s production was 12 kboe/d in 2012, compared to 11 kboe/d in 2011 and 10 kboe/d in 2010.



On the Surmont lease, gross commercial production in SAGD mode of the first development phase in 2012 was around 25 kboe/d of bitumen from forty well pairs. The operator plans to drill additional wells in 2013 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 addition, a project to debottleneck the steam has been initiated which will allow to increase the production of Phase 1.

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 kboe/d. In April 2011, the authorities issued a license permitting production (phases 1 and 2) of up to 136 kboe/d.



The Joslyn license is expected to be exploited using mining techniques. After the public hearings in 2010 and the 2011 provincial and federal Canadian authorities approval for a project of 100 kboe/d, the engineering studies including a review of the design to optimize the production of the Joslyn North Mine project are underway. On-site preliminary works were launched (surface waters drainage and civil engineering).


TOTAL closed in September 2010 the acquisition of UTS and its main asset: a 20% stake in the Fort Hills lease. In 2011, as part of their partnership, TOTAL acquired from Suncor an additional 19.2% stake in the lease, thereby increasing its stake to 39.2%. The pre-project studies and site preparation work are underway. The Fort Hills mining project has already been approved by the authorities for a first development phase with a capacity of 180 kboe/d. After the completion of the pre-project studies in June 2012, the basic engineering studies are


now in progress, with a final decision on investment expected for 2013. Some contracts for detailed engineering works have already been awarded.


TOTAL also acquired in December 2010 a 49% interest in the Voyageur upgrader project, which is operated by Suncor, located in the Canadian province of Alberta and intended to upgrade bitumen from the Fort Hills and Joslyn mines. In 2012, the estimate of this project’s cost and the evolution of North American oil markets modified its strategic and economic perspectives. As a consequence, the partners, TOTAL and Suncor, launched a joint strategic review of the development plan for the Voyageur upgrader. This detailed review included, notably, the optimization of the development plan, production evacuation logistics studies and implications of possible evolutions of the project. Pending the finalization of this review, development spending on the project was minimized during this period and until a joint decision on the future development of this project by both partners, TOTAL and Suncor.

On March 27, 2013, TOTAL entered into an agreement for the sale to Suncor Energy Inc. of its 49% interest in the Voyageur upgrader project. The mining developments of Fort Hills and Joslyn are not affected by this transaction and continue according to the production evacuation logistics studies jointly conducted with Suncor (see “Item 8. Significant changes”).



The Group also holds a 50% stake in the Northern Lights project, which is expected to be developed through mining techniques.

In the United States, the Group’s production was 57 kboe/d in 2012, compared to 56 kboe/d in 2011 and 55 kboe/d in 2010.



In the Gulf of Mexico:


The deep-offshore Tahiti oil field (17%) reached peak production of 135 kboe/d in 2009. Phase 2, which was launched in September 2010, comprises drilling four injection wells and two producing wells. The injection of water, which attempts to limit the decline of the wells, started in February 2012. The second producing well is currently being drilled.


The Chinook 4 well in the deep offshore Chinook project (33.33%) started production in the third quarter of 2012. More drilling operations are planned, including one well underway (Chinook 5).


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




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campaign was interrupted due to the U.S. government’s moratorium on deep offshore drilling operations in 2010 and resumed in 2012 with the drilling of the Ligurian 2 and North Platte wells. A significant discovery of oil was made in the latter in December 2012. Appraisal works are planned.


In 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 in 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 to reach 1.4 Bcf/d at the end of 2011. Following the drop in gas prices in the United States, drilling activity was sharply reduced in 2012, with around 100 wells being drilled. The hook-up of certain wells drilled in 2011 helped to maintain production in 2012.

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 in Ohio. More than 100 wells were drilled in 2012 and forty-seven were connected and started producing.

Engineers from TOTAL are assigned to the teams led by Chesapeake.



The Group holds a 50% stake in American Shale Oil LLC (AMSO) to develop in situ shale oil technology. The pilot to develop this technology is underway in Colorado.


In March 2012, TOTAL entered a 50/50 joint venture with Red Leaf Resources for the ex-situ development of oil shale and agreed to fund a production pilot before any larger-scale development.



In October 2012, TOTAL finalized an agreement to buy about 30,000 additional acres in Colorado and Utah, with a view to developing in situ shale oil techniques (AMSO technique) or ex-situ techniques (Red Leaf technique).

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 2012, TOTAL’s production in South America was 182 kboe/d, representing 8% of the Group’s overall production, compared to 188 kboe/d in 2011 and 179 kboe/d in 2010.

In Argentina, where TOTAL has been present since 1978, the Group operated 30%(1) of the country’s gas production in 2012. The Group’s production was 83 kboe/d in 2012, compared to 86 kboe/d in 2011 and 83 kboe/d in 2010.



In Tierra del Fuego, the Group notably operates the Carina and Aries offshore fields (37.5%). Further to the re-appraisal of the reserves of the Carina field, two additional wells are expected to be drilled from the existing platform. These wells should allow production levels from the facilities operated by the Group in Tierra del Fuego to be maintained at about 615 Mcf/d until the Vega Pleyade field (37.5%, operator) starts up in 2015.


In the Neuquén basin, TOTAL started a drilling campaign in 2011 on its mining licenses in order to assess their shale gas and oil potential. In 2012, this campaign, which started on the Aguada Pichana license (27.3%, operator), was extended to all the blocks operated by the Group: San Roque (24.7%, operator), Rincón la Ceniza and La Escalonada (85%, operator), Aguada de Castro (42.5%, operator), and Pampa de las Yeguas II (42.5%, operator), as well as to the blocks operated by third parties: Cerro Las Minas (40%), Cerro Partido (45%), Rincón de Aranda (45%) and Veta Escondida (45%). The first results of the production tests on the wells drilled during this campaign are positive and analyses are underway. The conventional production continues on the Group’s assets in this basin.

In Bolivia, the Group’s production, primarily gas, amounted to 27 kboe/d in 2012, compared to 25 kboe/d in 2011 and 20 kboe/d in 2010. 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. In early 2011, TOTAL decreased its stake to 41% in Block XX Tarija Oeste after divesting 34% and is no longer the operator. The development of phase 2, which was approved by the local authorities in 2011, continued in 2012 and is expected to increase the field’s production by 1.5 Mm3/d to 4.5 Mm3/d over the course of 2013.





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



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In 2004, TOTAL discovered the Incahuasi gas field on the Ipati Block. In 2011, an appraisal well confirmed the extension of the discovery northwards onto the adjacent Aquio Block. TOTAL consequently filed a declaration of commerciality for the Aquio and Ipati Blocks, which was approved by the local authorities in 2011. Additional appraisal work is underway, notably with the drilling of a second well on the Ipati Block, which started in January 2012 with encouraging results. In December 2012, TOTAL submitted to the Bolivian authorities a Phase 1 development plan, including two wells tied to a central processing plant of 6.5 Mm3/d for which calls for tenders have been launched. A third appraisal well should be drilled in 2013 which will be tied back to the Phase 1 project in case of success.

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 BC-2, with an extension on Block BM-C-14. In 2012 TOTAL became the operator of the field. Following seismic reprocessing, a pre-salt prospect was found under the Xerelete discovery made in 2001 at a water depth of 2,400 m. Further to approval by the authorities, TOTAL expects to resume drilling activity on the block at the end of 2013.


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. Between October 2011 and July 2012, an exploration/delineation campaign was conducted on the block, enabling a second structure (Epitonium) identified on Block BM-S-54 to be drilled, the productivity of the well drilled in 2010 to be tested and an appraisal well to be drilled in the northern part of the Gato do Mato structure. The encouraging results achieved on Gato do Mato are currently being analyzed in order to define the next steps in the appraisal of the field.

In Colombia, where TOTAL has had operations since 1973, the Group’s production was 6 kboe/d in 2012, compared to 11 kboe/d in 2011 and 18 kboe/d in 2010. The drop in production in 2011 was due in particular to TOTAL’s disposal of its interest in CEPSA, which was finalized in July 2011. The drop in production in 2012 was due to the sale in October 2012 of the Group’s 100% owned subsidiary, TEPMA BV, which held an interest in the Cusiana field. This operation also involved the disposal of stakes in the OAM and ODC pipelines.

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

Following the discovery of Huron-1 in 2009 on the Niscota (50%) exploration license and a 3D seismic survey of this discovery in 2010, the first appraisal well, Huron-2, also found hydrocarbons and should be tested during the second quarter of 2013. The drilling of a second appraisal well, Huron-3, is in progress. The conceptual development studies have started for a declaration of commerciality in late 2013.

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 24,100 km² in water depths ranging from 200 m to 3,000 m. At the end of 2011, the authorities extended the research permit until May 31, 2016.

After a 2,500 km2 3D seismic survey of the eastern portion of the block in 2009 and 2010, drilling started in 2011 of the GM-ES-1 well, about 170 km northeast of Cayenne on the Zaedyus prospect, at a water depth of more than 2,000 m. This well revealed two hydrocarbon columns in the gravelly reservoirs.

Two 3D seismic survey campaigns covering a total surface area of more than 5,000 km2 were conducted in the center and extreme eastern portions of the block in 2012. The results of the GM-ES-2 appraisal well are disappointing, but they do not call the potential of the license into question. Drilling started on the GM-ES-3 exploration well at the end of 2012, and could be followed by two more exploration wells in 2013 and 2014.

In Trinidad and Tobago, where TOTAL has had operations since 1996, the Group’s production was 16 kboe/d in 2012, compared to 12 kboe/d in 2011 and 3 kboe/d in 2010. TOTAL holds a 30% stake in the offshore Angostura field located on Block 2C and an 8.5% stake in the adjacent exploration Block 3A. Production started up in May 2011 on Phase 2, which corresponds to the gas development phase. The process to sell the companies owning these two assets was engaged in April 2012, with a sale anticipated in the first half of 2013.

In Uruguay, TOTAL acquired Block 14, located about 250 km offshore, in an auction sale in March 2012. The license covers an area of approximately 6,700 km² in water depths ranging from 2,000 m to 3,500 m. Under the terms of the contract to share production, signed in October 2012, TOTAL agreed to conduct a 3D seismic survey of the entire block, which started in November 2012, and to drill one well in the first three-year exploration phase.

In Venezuela, where TOTAL has had operations since 1980, the Group’s production was 50 kboe/d in 2012, compared to 54 kboe/d in 2011 and 55 kboe/d in 2010. TOTAL has equity stakes in PetroCedeño (30.3%), which produces and upgrades extra heavy oil in the Orinoco Belt,




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in Yucal Placer (69.5%), which produces gas dedicated to the domestic market, and in the offshore exploration Block 4, located in Plataforma Deltana (49%). The development phase of the southern zone of the PetroCedeño field started in the second half of 2011. Pursuant to an amendment to the gas sale contract, a new development phase of the Yucal Placer field, which will boost the production capacity from 100 Mcf/d to 300 Mcf/d, started in June 2012.


In 2012, TOTAL’s production in Asia-Pacific was 221 kboe/d, representing 10% of the Group’s overall production, compared to 231 kboe/d in 2011 and 248 kboe/d in 2010.

In Australia, where TOTAL has held leasehold rights since 2005, the Group owns 30% of the Ichthys project, 27.5% of the Gladstone LNG project and seven offshore exploration licenses, including three that it operates, off the northwest coast in the Browse and Bonaparte basins. The Group’s production was 5 kboe/d in 2012, compared to 4 kboe/d in 2011 and 1 kboe/d in 2010.



At the start of 2013, TOTAL acquired an additional 6% in the Ichthys project, increasing its stake to 30%. This project, launched in early 2012, 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 (with a maximum capacity of 100 kb/d of condensates) to stabilize and export condensates, an 889 km gas pipeline and an onshore liquefaction plant (capacities of 8.4 Mt/y of LNG and 1.6 Mt/y of NGL) located in Darwin. The LNG has already been sold under long-term contracts mainly to Asian buyers. 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 early 2011 and start-up is expected in 2015. LNG production is expected to eventually reach 7.2 Mt/y. The upstream development of the project and the construction of the pipeline are underway.


Two wells were drilled in 2011 on the WA-403 license (60%, operator). As one well demonstrated the presence of hydrocarbons, additional appraisal work will take place on this block (3D seismic) in the coming years.


At the end of 2012, TOTAL reduced its exposure on the WA-408 license (50%, operator) by disposing of 50% of its stake to partners. Three new exploration wells are planned, the first of which started in December 2012.

In 2012, TOTAL signed an agreement to enter four shale gas exploration licenses in the South Georgina basin in the center of the country. Under the terms of the agreement, TOTAL can increase its stake to 68% and become the operator in the event of development, which remains subject to approval by the authorities.

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 12 kboe/d in 2012, compared to 13 kboe/d in 2011 and 14 kboe/d in 2010. The gas is delivered to the Brunei LNG liquefaction plant.

On Block B, the drilling campaign that started in 2009 continued until 2011. Two of the wells were connected to production facilities in 2010 and 2011. The other wells, which were exploratory, revealed new reserves in the southern portion of the field. A ten-year extension of the mining rights period was granted in December 2011 by the Brunei government, which has allowed a project to be launched to develop new reserves which will bring additional gas production, with deliveries to the Brunei LNG liquefaction plant starting in 2015.

On deep-offshore exploration Block CA1 (54%, operator), formerly Block J, exploration operations that were suspended in May 2003 due to a border dispute between Brunei and Malaysia resumed in September 2010. A new seismic survey started before the summer of 2011 and an initial campaign of three drilling operations started in October 2011. This campaign, which continued until October 2012, was disappointing, despite the identification of some layers containing hydrocarbons. Surveys to re-appraise the block’s potential are underway and should result in a new exploration strategy.

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 to a development plan pursuant to which CNPC is the operator and TOTAL has a 49% stake.

The authorities gave the operator permission to undertake preliminary development work in the spring of 2011. The first development wells have been drilled and the facilities are presently in the test phase.

TOTAL is discussing with Sinopec a joint study agreement on the potential of the shale gas in a zone of around




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4,000 km2 near Nanjing, on which Sinopec plans to conduct seismic and drilling operations. An agreement could be negotiated with the authorities to exploit these unconventional resources at a later stage.

In Indonesia, where TOTAL has had operations since 1968, the Group’s production was 132 kboe/d in 2012, compared to 158 kboe/d in 2011 and 178 kboe/d in 2010.

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 2012, gas production operated by TOTAL decreased to 1,871 Mcf/d from 2,227 Mcf/d in 2011 due to the maturity of most of the fields on the Mahakam field, which is now in decline. The gas operated and delivered by TOTAL accounted for nearly 79% of Bontang LNG’s supply. Operated condensates and oil production from the Handil and Bekapai fields are added to this gas production.



On the Mahakam permit:


On the Tunu field in 2012, additional wells were drilled in the main reservoir and development wells targeted shallow gas reservoirs.


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


On South Mahakam, which contains the Stupa, West Stupa and East Mandu condensate gas fields, production started at the end of October 2012. Other development wells are being drilled.


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.



On the Sebuku license (15%), the development of the Ruby gas field started in February 2011. Production start-up is scheduled for the end of 2013, with an estimated capacity of 100 Mcf/d.


On the Sageri exploration Block (50%), the first exploration well (Lempuk-1X), completed in early 2012, produced negative results.


In October 2012, TOTAL acquired a 100% stake in the exploration Block Bengkulu I – Mentawai in the offshore Bengkulu basin, southwest of Sumatra.


In October 2012, the Group also acquired a 100% stake in the exploration Block Telen, in the offshore Kutai basin in the East Kalimantan province.


In May 2011, TOTAL acquired a 100% stake in the onshore and offshore exploration Block South West Bird’s Head, located in the Salawati basin in the province of West Papua. The preparatory work on the Anggrek Hitam 1 exploration well started at the end of 2012 and drilling start up is planned for April 2013.


In December 2011, the Group signed an agreement for a 18.4% stake in a coal bed methane (CBM) block on Kutai II in East Kalimantan province. This supplements the 50% stake acquired in March 2011 on the similar Kutai Timur Block. The first wells and core drilling operations are planned for 2013.


Finally, TOTAL conducted surveys of several other exploration blocks in which it holds an interest: Amborip VI (24.5%), Arafura Sea (24.5%), Sadang (30%), South East Mahakam (50%, operator), South Mandar (33%) and South Sageri (45%).

In Malaysia, TOTAL signed a production sharing agreement in 2008 for the offshore exploration Blocks PM303 and PM324. TOTAL withdrew from the PM303 offshore exploration Block in early 2011 following seismic surveys. Exploration operations continued on Block PM 324 (50%, operator) and the first high-pressure/high-temperature drilling started in October 2011. The drilling continued under difficult technical conditions until September 2012. In geological terms, the results were disappointing. Surveys are underway to continue the appraisal of the block’s potential.

TOTAL also signed in November 2010 a new production sharing agreement for the deep offshore exploration Block SK 317 B (85%, operator) located off the state of Sarawak. The interpretation of the 3D seismic data is underway and could result in the drilling of an exploration well in 2013.

In Myanmar, the Group’s production was 16 kboe/d in 2012, compared to 15 kboe/d in 2011 and 14 kboe/d in 2010. TOTAL is the operator of the Yadana field (31.2%), which is located on offshore Blocks M5 and M6. This field produces gas that is delivered mainly to PTT (the Thai state-owned company) for use in Thai power plants as well as the domestic market via two pipelines that were built and are operated by MOGE, a state-owned company.

In September 2012, TOTAL entered into an agreement to take a 40% share of a production sharing agreement on the M-11 offshore Block in the Martaban basin. The acquisition was approved by the authorities at the start of 2013. The drilling of an exploration well is planned for 2013.

In Papua New Guinea, TOTAL acquired in October 2012, subject to the authorities’ approval, a 40% stake, in the PPL234 and PPL244 offshore permits, 50% in the PRL10 offshore permit and an option for 35% of the PPL338 and




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PPL339 onshore permits. The program includes the drilling of two exploration wells in 2013.

In the Philippines, TOTAL has held a 75% stake in the SC56 license in the southern Sulu Sea since September 2012. The program of operations includes the refurbishment of the oldest seismic lines and a new seismic campaign which was realized at the beginning of year 2013.

In Thailand, the Group’s production, which was 55 kboe/d in 2012, compared to 41 kboe/d in 2011 and 2010, comes from the Bongkot (33.33%) offshore gas and condensates field. PTT purchases all of the natural gas and condensates production from this field.



In the northern portion of the Bongkot field, new investments are in progress to allow gas demand to be met and plateau production to be maintained:



phase 3J (two well platforms) was launched in late 2010 and started up as scheduled in 2012;


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


phase 3L (two well platforms) was approved in September 2012 with start-up scheduled for 2015; 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. Production of the first phase (phase 4A), with a capacity of 350 Mcf/d, started in June 2012.

In Vietnam, TOTAL holds a 35% stake in the production sharing contract for the offshore 15-1/05 exploration Block following an agreement signed in 2007 with PetroVietnam. TOTAL has put its share up for sale.

In 2009, TOTAL and PetroVietnam signed a production sharing agreement for the onshore Blocks DBSCL-02 and DBSCL-03 (75%, operator). Based on the seismic information obtained in 2009 and 2010, the partners have decided not to continue the exploration work and the license was returned to the authorities when it expired in April 2012.

Commonwealth of Independent States (CIS)

In 2012, TOTAL’s production in the CIS was 195 kboe/d, representing 8% of the Group’s overall production, compared to 119 kboe/d in 2011 and 23 kboe/d in 2010.

In Azerbaijan, where TOTAL has had operations since 1996, on the field of Shah Deniz (10%), production was 16 kboe/d in 2012 and continues to progress regularly from one year to the next since 2010. TOTAL also holds a 10% stake 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 of the Baku-Tbilisi-Ceyhan (BTC) oil pipeline, which connects Baku and the Mediterranean Sea and evacuates among others the condensates of Shah Deniz’s gas.

Gas deliveries to Turkey and Georgia continued throughout 2012, at a lower pace for Turkey due to weaker demand than expected. Conversely, state-owned SOCAR continued to take 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 field continued in 2012. 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 front end engineering and design (FEED) for the second phase were officially launched at the end of the first quarter of 2012. Negotiations and investigations into the means of transporting the gas from Shah Deniz to Europe are continuing at the same time. The goal is to reach a final decision on the investment in 2013 concerning the second development phase.

In 2009, TOTAL and 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 and production phase. In September 2011, the first exploration well revealed a significant accumulation of gas that was tested in the first quarter of 2012. A discovery and commerciality declaration was filed in June 2012. Operations on the well continued with the drilling of a sidetrack to the north of the structure, which was completed in September 2012 with positive results. The field’s development plan is under preparation and will be submitted to SOCAR for approval in the coming years, as required by the production sharing contract.

In Kazakhstan, TOTAL has owned since 1992 a 16.81% stake in the North Caspian license, which covers the Kashagan field in particular.

The Kashagan project is expected to develop the field in several phases. The development plan for the first phase (300 kb/d) was approved in February 2004 by the Kazakh authorities, permitting work to begin on the field. The consortium plans a start-up of production in 2013.




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In May 2012, the members of the North Caspian Sea Production Sharing Agreement (NCSPSA) consortium and the Kazakh authorities signed agreements to settle a number of issues regarding the contractual conditions of the first phase.

In November 2012, TOTAL acquired a 75% share in the North and South Nurmunai onshore exploration blocks. These two blocks cover 14,500 km2 and are located in the southwest of the country.

In Russia, where TOTAL has had operations through its subsidiary since 1991, the Group’s production, which was 179 kboe/d in 2012 compared to 105 kboe/d in 2011 and 10 kboe/d in 2010, comes from the Kharyaga field (40%, operator) and TOTAL’s stake in Novatek (15.34%).



In March 2012, the partners in the first development phase of the Shtokman project through Shtokman Development AG (TOTAL, 25%) decided to assess the feasibility of a project focusing exclusively on the production of liquefied natural gas (LNG). An analysis of the Shtokman project revealed that the technical solutions initially chosen to produce 23.7 Gm3/y of gas, half of which to be exported to Europe by pipeline and the other half to be shipped as LNG, involved capital outlay and operational costs that were too high to achieve acceptable profitability. The 2007 agreement between TOTAL and Gazprom expired on July 1, 2012, but technical discussions are ongoing between the two companies in order to agree on an economically viable development.


TOTAL and the Russian company Novatek, listed in Moscow and London, 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 19.40% within three years. In December 2011, TOTAL increased its stake in Novatek by 2% to 14.09%. Since April 2012, TOTAL has increased its stake in Novatek to reach 15.34% at year-end 2012.

TOTAL and its partner Novatek made the final investment decision to develop the Termokarstovoye field (capacity 65 kboe/d) at the end of 2011. This onshore deposit of gas and condensates is located in the Yamalo-Nenets district. The development and production license for the Termokarstovoye field is owned by ZAO Terneftegas, a joint venture between Novatek (51%) and TOTAL (49%).


In October 2011, TOTAL (20%) and Novatek signed the final agreements for the joint development of the Yamal LNG project. The Yamal LNG project covers the development of the South Tambey gas and condensates field, located on the Yamal Peninsula in the Arctic. The FEED studies were completed at the end of


2012, certain calls for tender have been issued and the final investment decision could be made in 2013.


On the Kharyaga field, work related to the development plan of phase 3 is ongoing. This development plan is intended to maintain plateau production above the 30 kboe/d 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 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. Pursuant to this agreement, TOTAL is planning to acquire a 17% share from KMG. This transaction will be subject to approval by the authorities.

In Tajikistan, TOTAL signed an agreement in December 2012 with a view to acquiring a 33.3% stake in the Bocktar PSC. This transaction is subject to approval by the authorities.


In 2012, TOTAL’s production in Europe was 427 kboe/d, representing 19% of the Group’s overall production, compared to 512 kboe/d in 2011 and 580 kboe/d in 2010.

In Bulgaria, the Han Asparuh license (100%, operator), which covers 14,220 km2 in the Black Sea, was awarded to TOTAL in July 2012 and a concession agreement was signed in August 2012. TOTAL has agreed to collect the seismic data and to drill two wells during the five-year term of the contract. An agreement to divest 30% stakes to OMV and Repsol was concluded in November 2012. Under the terms of this agreement, OMV will be the operator in the seismic phase and will then hand over the operatorship to TOTAL.

In Cyprus, TOTAL is present on two deep offshore exploration licenses for Blocks 10 and 11, which were obtained in the second offshore exploration round launched by the Cypriot government in 2012.

TOTAL signed two production sharing contracts at the beginning of 2013 for these blocks, which extend over 2,572 km2 and 2,958 km2, respectively, and are located in the southwest of Cyprus, in water depths ranging from 1,000 m to 2,500 m. The exploration of these blocks will begin with seismic surveys.

In Denmark, TOTAL has owned since 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,




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respectively. Following geoscience surveys on license 1/10 in 2011, the decision was made to drill a well. Initially planned for 2013, this well is expected to be delayed due to additional environmental studies requested by the local authorities. Geoscience surveys are ongoing on license 2/10.

In France, the Group’s production was 13 kboe/d in 2012, compared to 18 kboe/d in 2011 and 21 kboe/d in 2010. 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. 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. Most of the objectives of the experiment having been reached, the injection of carbon dioxide, came to an end in the first quarter of 2013.

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. The operation of these concessions and the production rights were transferred in January 2012. Agreements for the sale of the Lacq, Lagrave and Pécorade assets were also signed in February 2012. These agreements remain subject to approval by the authorities, expected in 2013.

The Montélimar exclusive exploration license, awarded to TOTAL in 2010 to assess, in particular, the 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 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 the Group’s principal exploration and production assets in the country. In March 2013, TOTAL finalized an agreement to sell a 25% interest in the Tempa Rossa field. The transfer of interests will take effect after the Italian authorities have approved the transaction.

In 2011, Total Italia acquired an additional 25% stake in the Tempa Rossa field, thereby increasing its share to 75%, as

well as an interest in two exploration licenses. Although preparation work started in early August 2008, 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. 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 and was tested in 2012, confirming the results of the previous wells. The final investment decision was made in July 2012, following the approval of the state and regional authorities. The extension plan for the Tarente refinery export system, needed for the development of the Tempa Rossa field, was approved at the end of 2011. Start-up of production is expected in 2016 with a capacity of 55 kboe/d.

In Norway, where the Group has had operations since the mid-1960s, TOTAL has equity stakes in ninety-one production licenses on the Norwegian continental shelf, twenty-three of which it operates. In 2012, the Group’s production was 275 kboe/d, compared to 287 kboe/d in 2011 and 310 kboe/d in 2010. 90 kboe/d is from the Greater Ekofisk Area located in the southern sector of the North Sea, 106 kboe/d comes from the central and northern portions of the North Sea and 79 kboe/d comes from the Haltenbanken region and the Barents Sea.



In the Norwegian North Sea, where a numerous of development projects have just been launched, the most substantial contribution to the Group’s production, for the most part non-operated, comes from the Greater Ekofisk Area (e.g., Ekofisk, Eldfisk, Embla).


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, each with a capacity of 70 kboe/d, were launched in June 2011 following approval of the development and operation plans by the authorities. The production is scheduled to start in 2014 for Ekofisk South and in 2015 for Eldfisk 2. The project relating to the construction and installation of the new Ekofisk accommodation and field services center platform is now in its third year.


On the Greater Hild Area, located in the north and in which the Group has a 51% stake (operator), the Martin Linge development scheme (capacity of 80 kboe/d, formerly known as Hild) was selected at the end of 2010 and approved by the authorities in 2012, with production start-up scheduled for 2016.


The Islay field, operated by the Group and fully owned by TOTAL, was put into production in April 2012. The Islay field extends on each side of the




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Norwegian/Great Britain border and the Group’s interest in the Norwegian part is 5.51%.


A number of successful exploration and appraisal activities were carried out in the North Sea in the 2010-2012 period. These activities have led to the launch of several development projects, some of them are already finalized, others are underway or are expected to be approved soon by the authorities:


In the central section of the North Sea, on license PL102C (40%, operator), a fast-track development project had been launched for the Atla field (formerly known as David), which was discovered in 2010. Gas production started in October 2012, less than two years after the discovery of the field.


Gas production on the Beta West field (10%), a satellite of Sleipner, 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 was completed in the fourth quarter of 2012. Production started up in November 2012. Visund North, a second fast-track development project, was launched at the end of 2011 to redevelop the northern portion of the Visund field and provide development infrastructure for the nearby exploration prospects and discoveries (Titan) inside the license. Production is scheduled to start at the end of 2013. The authorities approved the extension of the PL20 license (Visund) until the end of 2034.


The Stjerne project was launched in 2011 to develop the Katla structure discovered in 2009, located on license PL104 (14.7%) south of Oseberg in the Nordic North Sea. Start-up of production is expected in 2013.


The fast-track development project of the Vigdis North East structure (PL089, sold as part of the 2012 transaction with ExxonMobil described below), which was discovered in 2009 and is located south of Snorre, was launched in 2011.


A positive appraisal well was drilled in 2010 on the southern slope of the Dagny structure (38%) north of Sleipner. The development project was sanctioned at the end of 2012 and the plan of development and operation (PDO) submitted to the authorities, with an approval expected for mid 2013. Production is scheduled to start in 2017.


In the Norwegian Sea, the Haltenbanken area includes the Tyrihans (23.2%), Linnorm (20%), 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.

The Åsgard sub-sea compression project, which will increase hydrocarbon recovery on the Åsgard and Mikkel fields, was approved by the Norwegian authorities in 2012. All the main contracts have been awarded.

On the Linnorm gas field, the Onyx South exploration well is expected to be drilled in 2013. Gas from Linnorm will be exported from the Nyhamna onshore terminal through a new pipeline (Polarled project).

The Polarled project (5.11%) was sanctioned in December 2012 and the development plan was submitted to the Norwegian authorities in January 2013. The project consists in the installation of a 481 km long pipeline from the Aasta Hansen field to the Nyhamna terminal and in the expansion of the terminal.



In the Barents Sea, LNG production on Snøhvit (18.4%) started in 2007. This project included the development of the Snøhvit, Albatross and Askeladd natural gas fields, and the construction of the associated liquefaction facilities (capacity of 4.2 Mt/y). A project has been launched in 2012 with the objective of improving the performances of the plant.


Several exploration wells were successfully drilled over the 2011-2012 period:


In October 2012, TOTAL drilled a positive exploration well on the Garantiana structure (40%, operator) on license PL554 in the Nordic North Sea. The drilling of additional exploration and appraisal wells in the license is currently under study.


In July 2012, TOTAL announced a major gas and condensate discovery on the King Lear prospect in licenses 146 and 333 in the southern Norwegian North Sea (22.2%). An appraisal well is planned to be drilled in 2014.


In 2011, TOTAL successfully drilled an exploration well on the Alve North structure on license PL127 (50%, operator) near the Norne field. Preliminary studies have been performed. The data from a new seismic campaign is being interpreted.


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 preliminary development studies have been completed and an appraisal well should be drilled in 2013.




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



In the beginning of 2013, TOTAL obtained eight new licences of which four as operator at the occasion of licensing round APA 2012 (Awards in Predefined Areas). All these licenses are localized in the Nowergian North sea: PL661 (60%, operator), PL662 (60%, operator) and PL667 (50%, operator) in the Ekofisk area, PL675 (40%) and PL676S (20%) in the central part, and PL190B (10%), PL684 (5%) and PL685 (40%, operator) in the north.


In October 2012, TOTAL and ExxonMobil exchanged interests in a range of producing and undeveloped assets already in production or on the verge of being developed. In exchange for its interests in the PL089 license (5.6%) and in the Sygna (2.52%), Statfjord Øst (2.8%) and Snorre (6.18%) fields, TOTAL received the interest held by ExxonMobil in the Oseberg field (4.7%), the Oseberg gas transportation system (4.33%) and the PL029c (100%) and PL029b (30%) licenses, which contain part of the Dagny field. The agreement was finalized and approved by the Norwegian authorities in the fourth quarter of 2012. TOTAL’s share of the PL104 license is 14.7% and it holds a 38% stake in the Dagny structure. TOTAL no longer holds a stake in license PL089.


At the beginning of 2012, during licensing round APA 2011, TOTAL obtained eight new licenses including five as operator.

In 2011, TOTAL obtained four new exploration licenses during licensing round APA 2010, including one as operator. The Group also acquired in 2011 a 40% stake and the role of operator of license PL554, north of Visund. The exploration well drilled on this license in 2012 resulted in the discovery of Garantiana.



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 became effective at the end of 2011.


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

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%). The Group’s production was 33 kboe/d in 2012, compared to 38 kboe/d in 2011 and 42 kboe/d in 2010.


The L4-D field (55.66%, operator) started production in November 2012.


A 3D seismic survey of several offshore permits covering an area of 3,500 km2 was conducted between May and September 2012. The interpretation of the results of this campaign is expected at the end of 2013.


The K4-Z 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 2013.


The K5-CU 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 K5-A platform by a 15 km gas pipeline.

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 beginning of 2012, TOTAL signed an agreement to acquire a 49% stake in the Chelm and Werbkowice exploration concessions in order to assess their shale gas potential. A well was drilled and tested on the Chelm permit. The results from the well are being analyzed. TOTAL asked the authorities to relinquish the Werbkowice permit in September 2012 since it did not meet expectations.

In the United Kingdom, where TOTAL has had operations since 1962, the Group’s production was 106 kboe/d in 2012, compared to 169 kboe/d in 2011 and 207 kboe/d in 2010. About 90% of 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. In 2012, the shutdown of the Elgin, Franklin and West Franklin fields due to a gas leak from well G4 in Elgin severely impacted production.



On the Alwyn zone (100%), start-up of satellite fields or new reservoir compartments allowed production to be maintained. Wells N54, N53 and N52 started production in May 2012, September 2011 and February 2010, respectively.

On the Dunbar field (100%), a new drilling survey (Dunbar phase IV) should begin in the middle of 2013 including three work overs and six new wells.

The production on the Islay field (94.49%, gas and condensates) started in April 2012.

In February 2012, TOTAL finalized the divestment of its stake in the Otter field.




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In October 2011, the decision was made to redevelop the Brent South West formation in Alwyn by drilling two wells: one production well, which was started in August 2012, and one water injection well, which is expected to be drilled during the second semester 2013.



In Central Graben, at the end of 2011, TOTAL increased its stake in Elgin Franklin Oil & Gas (EFOG), a company through which it holds a stake in the Elgin and Franklin fields (46.2%, operator), from 77.5% to 100%. 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.

In May 2012, TOTAL confirmed that the leak from well G4 had been successfully stopped and at the end of October 2012, well G4 was definitively secured by installing five cement plugs.

The enquiry led by TOTAL permitted the clear identification of the causes of the accident and the definition of new criteria for well integrity to allow the restart of the production of Elgin/Franklin in total security.

The production on the Elgin/Franklin area restarted on March 9, 2013, following the approval of the safety case by the UK Health and Safety Executive (HSE). Production is resuming gradually, and is expected to soon reach close to 70 kboe/d (approximately 30 kboe/d in TOTAL’s share), corresponding to approximately 50% of the production potential from the fields.

In order to recover by 2015 the production level that existed before the Elgin incident, a redevelopment project envisaging drilling of new infill wells on Elgin and Franklin is currently under study.

In addition, the West Franklin Phase II development project remains ongoing with production start-up scheduled for 2014.



In addition to Alwyn and the Central Graben, a third area, West of Shetland, is undergoing development. This area covers the Laggan and Tormore fields, in which TOTAL acquired an 80% stake in early 2010.

The decision to develop these two 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 includes:



sub-sea production facilities;


off-gas treatment (gas and condensates) at a plant located near the Sullom Voe terminal in the Shetland Islands, 150 km away; and


a new pipeline connected to the Frigg gas pipeline (FUKA) for the export of gas to the Saint Fergus terminal.

In early 2011, a gas and condensate discovery was made on the Edradour license (75%, operator), near Laggan and Tormore. The development of Edradour East by using the infrastructures in place was decided in the end of December 2012.

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.

TOTAL also holds a stake in three assets operated by other parties: the Bruce (43.25%), Keith (25%), and Markham (7.35%) fields. The Group’s stakes in other fields operated by third parties (Seymour, Alba, Armada, Maria, Moira, Mungo/Monan and Everest) were sold off in 2012.

Nine new licenses (three in the Northern North Sea, three in Central Graben and three in West Shetland) were awarded to TOTAL in the twenty-seventh exploration round, the results of which were announced on October 25, 2012.

Middle East

TOTAL’s production in the Middle East in 2012 was 493 kboe/d, representing 21% of the Group’s overall production, compared to 570 kboe/d in 2011 and 527 kboe/d in 2010.

In the United Arab Emirates, where TOTAL has had operations since 1939, the Group’s production was 246 kboe/d in 2012, compared to 240 kboe/d in 2011 and 222 kboe/d in 2010. In 2012, the country maintained a steady rhythm of production, which led to a slight increase of TOTAL’s share of production. 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).

TOTAL holds a 75% stake (operator) in the Abu Al Bu Khoosh field, 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 NGL and condensates from the associated gas produced by ADCO, and a 5% stake in Abu Dhabi Gas Liquefaction Company (ADGAS), which produces LNG, NGL and condensates.

The ADCO license expires in January 2014. In 2012, the Abu Dhabi authorities started the discussions to define the future of ADCO beyond that date.




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In early 2011, TOTAL and IPIC, a government-owned entity in Abu Dhabi, signed a memorandum of understanding (MOU) with a view to developing projects of common interest in the upstream oil and gas sectors. The analyses continue.

The Group has a 24.5% stake in Dolphin Energy Ltd. alongside Mubadala, a company owned by the government of Abu Dhabi, 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 currently being started and is expected to permit FERTIL to double its production to 2 Mt/y by mid-2013.

In Iraq, TOTAL holds an 18.75% stake in the development and production contract of the Halfaya field in the Missan province. Production of phase 1 of the project (capacity of 100 kb/d) started in June 2012 and was 12 kboe/d over the last six months of 2012 (6 kboe/d on average over the year). The definitive development plan (estimated capacity of 535 kb/d) was submitted to the authorities in the beginning of 2013.

In mid-2012, TOTAL finalized the acquisition of a 35% stake in the Safen (TOTAL will become the operator when a discovery is declared) and Harir exploration Blocks (respectively covering 424 km2 and 705 km2, northeast of Erbil), and a 20% stake in the Taza Block (505 km2, southwest of Souleimaniye). The drilling of the Harir 1 well was completed in the beginning of 2013 and the drilling of the Taza 1 well is in progress. Two new wells are scheduled in 2013.

In Iran, the Group has had no production since 2010. The 2010 production of 2 kb/d came from remaining payments under buy-back contracts. For additional information, see “— Other Matters — Cuba, Iran and Syria”.

In Oman, the Group’s production in 2012 was 37 kboe/d, stable compared to 2011 and 2010. The Group produces oil primarily on Block 6 (4%)(1) as well as on Block 53 (2%)(2), and it produces liquefied natural gas through its stake in the Oman LNG (5.54%)/Qalhat LNG (2.04%) liquefaction plant(3), which has a capacity of 10.5 Mt/y.

In Qatar, where TOTAL has had operations since 1936, the Group’s production in 2012 was 139 kboe/d, compared to 155 kboe/d in 2011 and 164 kboe/d in 2010. The Group has equity stakes in the Al Khalij field (100%), the NFB Block (20%) in the North field and the Qatargas 1

liquefaction plant (10%). The Group also holds a 16.7% in Qatargas 2 train 5.



In November 2012, TOTAL and Qatar Petroleum signed a new agreement to continue their partnership on the Al Khalij field for an additional 25-year period. Under the terms of this protocol, as from 2014, TOTAL will remain the operator with a 40% stake and Qatar Petroleum will hold a 60% stake.


The production contract for the Dolphin gas project, 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 of Qatargas 2 train 5, which started in 2009, is 8 Mt/year. TOTAL has been a shareholder in this train since 2006. An agreement to share the two liquefaction trains of the Qatargas project (trains 4 and 5) was signed in 2011. The agreement provides for a 50/50 split of the physical production of the two trains as well as the associated operating costs and capital outlay. In addition, TOTAL began to off-take 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 became a partner in the offshore BC exploration permit (25%) in May 2011.

In Syria, TOTAL has interests in the Deir Ez Zor permit through its 50% stake in DEZPC (100%, operator) and through the Tabiyeh contract, which came into effect in October 2009. The Group had no production in 2012 compared to 53 kboe/d in 2011 and 39 kboe/d in 2010. TOTAL suspended its activities contributing to the production of hydrocarbons in Syria in December 2011, in compliance with the European Union’s regulations regarding this country. For additional information, see “— Other Matters — Cuba, Iran and Syria”.

In Yemen, where TOTAL has had operations since 1987, production was 65 kboe/d in 2012, compared to 86 kboe/d in 2011 and 66 kboe/d in 2010.

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 first LNG train was commissioned in October 2009 and the second came online in April 2010. The plant’s nominal





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 has an indirect interest of 2.00% in Block 53.


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



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capacity is 6.7 Mt of LNG per year. 2012 witnessed eight sabotage attacks on the pipeline, which resulted in production losses of nearly 24%.

TOTAL also has stakes in 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 five onshore exploration licenses: Blocks 69 and 71 (40%), Block 70 (50.1%, operated by TOTAL since July 2010), and Block 72 (36%, operated by TOTAL since October 2011). In December 2012, TOTAL’s acquisition of a 40% interest in the Block 3 exploration license, which it will operate, became effective.




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As of December 31,
(in thousands of acres)
  2012      2011      2010  


   Gross     10,015         724         6,478         781         6,802         776   
     Net     6,882         176         3,497         185         3,934         184   


   Gross     135,610         1,256         110,346         1,229         72,639         1,229   
     Net     88,457         337         65,391         333         33,434         349   


   Gross     16,604         1,705         15,454         1,028         16,816         1,022   
     Net     6,800         330         5,349         329         5,755         319   

Middle East

   Gross     32,369         1,896         31,671         1,461         29,911         1,396   
     Net     3,082         256         2,707         217         2,324         209   


   Gross     37,208         955         40,552         930         36,519         539   
     Net     18,184         270         19,591         255         17,743         184   


   Gross     231,806         6,536         204,501         5,429         162,687         4,962   
     Net(b)     123,405         1,369         96,535         1,319         63,190         1,245   



Undeveloped acreage includes leases and concessions.


Net acreage equals the sum of the Group’s equity stakes in gross acreage.



As of December 31,

(number of wells)

   2012      2011      2010  


   Oil      410         111         576         151         569         151   
     Gas      330         117         358         125         368         132   


   Oil      2,216         593         2,275         576         2,250         628   
     Gas      156         48         157         44         182         50   


   Oil      898         258         877         247         884         261   
     Gas      2,892         546         2,707         526         2,532         515   

Middle East

   Oil      6,488         462         7,829         721         7,519         701   
     Gas      371         49         372         49         360         49   


   Oil      206         75         209         75         196         75   
     Gas      1,912         578         1,589         498         1,258         411   


   Oil      10,218         1,499         11,766         1,770         11,418         1,816   
     Gas      5,661         1,338         5,183         1,242         4,700         1,157   



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



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As of December 31,   2012     2011     2010  
    Net dry
    Net total
dry  wells
    Net dry
    Net dry




    0.9        3.3        4.2        1.5        1.7        3.2        1.7        0.2        1.9   


    4.9        2.8        7.7        2.9        1.5        4.4        1.6        4.3        5.9   


    3.9        0.6        4.5        1.2        1.3        2.5        1.0        1.6        2.6   

Middle East

                         1.2        0.8        2.0        0.9        0.3        1.2   


    2.4        1.4        3.8        2.1        3.7        5.8        3.2        1.2        4.4   


    12.1        8.1        20.2        8.9        9.0        17.9        8.4        7.6        16.0   




    6.0        0.7        6.7        7.5               7.5        5.0               5.0   


    22.7               22.7        24.7               24.7        18.1               18.1   


    70.6        131.7        202.3        113.1        82.2        195.3        135.3        112.5        247.8   

Middle East

    43.3               43.3        32.6        2.6        35.2        29.5        1.4        31.0   


    127.8               127.8        118.4               118.4        59.3               59.3   


    270.4        132.4        402.8        296.3        84.8        381.1        247.3        113.9        361.2   


        282.5        140.5        423.0        305.2        93.8        399.0        255.7        121.5        377.2   



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



As of December 31,         2012      2011      2010  
(number  of wells)         Gross      Net (a)      Gross      Net (a)      Gross      Net (1)  




     1         1.0         2         2.0         3         2.1   


     4         1.3         2         0.8         4         1.4   


     7         3.4         3         1.0         2         0.9   

Middle East

     2         1.1                         2         1.2   


     2         1.3         1         0.6         2         1.1   


     16         8.1         8         4.4         13         6.7   




     23         6.2         21         4.5         21         3.8   


     25         6.4         31         11.3         29         6.4   


     29         8.2         22         5.7         99         29.2   

Middle East

     93         6.1         26         3.5         20         5.1   


     171         49.2         11         5.1         23         9.8   


     341         76.1         111         30.1         192         54.3   


         357         84.2         119         34.5         205         61.0   



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



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The table below sets forth TOTAL’s interests in oil and gas pipelines as of December 31, 2012.


Pipeline(s)   Origin   Destination   %
    Operator     Liquids     Gas  






  Network South West         100.00        x                x   


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     12.98                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           
Vestprosess   Kollsnes (Area E)   Vestprosess (Mongstad refinery)     5.00                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 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   





Mandji Pipes

  Mandji fields   Cap Lopez Terminal     100.00 (a)      x        x           

Rabi Pipes

  Rabi fields   Cap Lopez Terminal     100.00 (a)      x        x           





Gas Andes

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


  Network (Northern Argentina)         15.40                        x   


  TGN   Uruguyana (Brazil)     32.68                        x   




  Yacuiba (Bolivia)   Rio Grande (Bolivia)     11.00                        x   




  Bolivia-Brazil border   Porto Alegre via São Paulo     9.67                        x   




  Cusiana   Covenas Terminal     5.20                x           




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




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


  Baku (Azerbaijan)   Georgia/Turkey Border     10.00                        x   

Dolphin (International transport and network)

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



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



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Gas & Power




Gas & Power’s primary objective is to contribute to the growth of the Group by ensuring sales outlets for its current and future natural gas reserves and production.

In order to optimize these gas resources, particularly liquefied natural gas (LNG), Gas & Power’s activities include trading and marketing of natural gas, liquefied natural gas, liquefied petroleum gas (LPG) and electricity, as well as shipping. Gas & Power also has stakes in infrastructure companies (re-gasification terminals, natural gas transport and storage, power plants) necessary to implement its strategy.

Gas & Power also manages a coal business line, handling everything from production to marketing.

Liquefied natural gas

A pioneer in the LNG industry, TOTAL today is one of the world’s leading players(1) in the sector 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 its positions in most major production zones and markets.

Through its stakes in liquefaction plants(2) located in Qatar, the United Arab Emirates, Oman, Nigeria, Norway and Yemen, and its gas supply agreement with the Bontang LNG plant in Indonesia, TOTAL markets LNG in all worldwide markets. In 2012, TOTAL sold 11.4 Mt of LNG, a decrease of 13% compared to 2011 LNG sales (13.2 Mt) and 7% compared to 2010 sales (12.3 Mt). This decrease is due in particular to the decline of the Bontang LNG plant production and to the force majeure events reported by the Yemen LNG project in 2012. The planned start-up of the Angola LNG plant in 2013, together with the Group’s liquefaction projects in Australia, Russia and Nigeria are expected to allow for growth in the coming years.

Gas & Power is responsible for LNG operations downstream from liquefaction plants. It is in charge of LNG marketing to third parties on behalf of Exploration & Production, developing 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. 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 2007.