e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
2009 FORM 10-K
(Mark One)
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Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934 |
For the fiscal year ended December 31, 2009
OR
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934 |
For the transition period from to
Commission file number 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
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Delaware
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20-0467835 |
(State or other jurisdiction
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(I.R.S. Employer |
of incorporation or organization)
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Identification No.) |
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5100 Tennyson Parkway, |
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Suite 1200, Plano, TX
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75024 |
(Address of principal executive offices)
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(Zip Code) |
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Registrants telephone number, including area code:
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(972) 673-2000 |
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Securities registered pursuant to Section 12(b) of the Act: |
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Title of Each Class:
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Name of Each Exchange on Which Registered: |
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Common Stock $.001 Par Value
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New York Stock Exchange |
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Securities registered pursuant to Section 12(g) of the Act: None
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 o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. Yes o 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 o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).
Yes
þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a small reporting company. See definition of large accelerated filer,
accelerated filer, and small reporting company in Rule 12-b2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule
12b-2).
Yes o No þ
The aggregate market value of the registrants common stock held by non-affiliates, based on the
closing price of the registrants common stock as of the last business day of the registrants most
recently completed second fiscal quarter was $2,625,591,935.
The number of shares outstanding of the registrants Common Stock as of January 31, 2010, was
262,364,085.
DOCUMENTS INCORPORATED BY REFERENCE
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Document:
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Incorporated as to: |
1. Notice and Proxy Statement for the Annual Meeting
of Shareholders to be held May 19, 2010.
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1. Part III, Items 10, 11, 12, 13, 14 |
Denbury Resources Inc.
2009 Annual Report on Form 10-K
Table of Contents
2
Denbury Resources Inc.
Glossary and Selected Abbreviations
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Bbl
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One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons. |
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Bbls/d
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Barrels of oil produced per day. |
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Bcf
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One billion cubic feet of natural gas or CO2. |
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Bcfe
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One billion cubic feet of natural gas equivalent using the ratio of one
barrel of crude oil, condensate or natural gas liquids to 6 Mcf of
natural gas. |
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BOE
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One barrel of oil equivalent using the ratio of one barrel of crude oil,
condensate or natural gas liquids to 6 Mcf of natural gas. |
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BOE/d
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BOEs produced per day. |
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Btu
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British thermal unit, which is the heat required to raise the temperature
of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. |
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CO2
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Carbon dioxide. |
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Finding and
Development Cost
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The average cost per BOE to find and develop proved reserves during a
given period. It is calculated by dividing costs, which includes the
total acquisition, exploration and development costs incurred during the
period plus future development and abandonment costs related to the
specified property or group of properties, by the sum of (i) the change
in total proved reserves during the period plus (ii) total production
during that period. |
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MBbls
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One thousand barrels of crude oil or other liquid hydrocarbons. |
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MBOE
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One thousand BOEs. |
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Mbtu
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One thousand Btus. |
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Mcf
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One thousand cubic feet of natural gas or CO2. |
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Mcf/d
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One thousand cubic feet of natural gas or CO2 produced per day. |
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Mcfe
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One thousand cubic feet of natural gas equivalent using the ratio of one
barrel of crude oil, condensate or natural gas liquids to 6 Mcf of
natural gas. |
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Mcfe/d
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Mcfes produced per day. |
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MMBbls
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One million barrels of crude oil or other liquid hydrocarbons. |
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MMBOE
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One million BOEs. |
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MMBtu
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One million Btus. |
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MMcf
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One million cubic feet of natural gas or CO2. |
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MMcf/d
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One million cubic feet of natural gas or CO2 per day. |
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MMcfe
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One thousand Mcfe. |
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MMcfe/d
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MMcfes produced per day. |
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PV-10 Value
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When used with respect to oil and natural gas reserves, PV-10 Value means
the estimated future gross revenue to be generated from the production of
proved reserves, net of estimated future production, development and
abandonment costs, and before income taxes, discounted to a present value
using an annual discount rate of 10%. PV-10 Values calculated as of
December 31, 2009 were prepared using an average price equal to the
unweighted arithmetic average of hydrocarbon prices on the first day of
each month within a 12-month period ended December 31, 2009. PV-10
Values calculated prior to December 31, 2009 were prepared using prices
and costs in effect at the determination date. PV-10 Value is a non-GAAP
measure and its use is further discussed in footnote 4 to the table on
page 24. |
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Proved Developed
Reserves*
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Reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. |
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Proved Reserves*
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The estimated quantities of crude oil, natural gas and natural gas
liquids that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions. |
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Proved Undeveloped
Reserves*
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Reserves that are expected to be recovered from new wells on undrilled
acreage or from existing wells where a relatively major expenditure is
required. |
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Tcf
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One trillion cubic feet of natural gas or CO2. |
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* |
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This definition is an abbreviated version of the complete definition as defined by the SEC in
Rule 4-10(a) of Regulation S-X. For the complete definition
see:
http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?type=simple;c=ecfr;cc=ecfr;sid=9cb6302b536b7a2f8af3f13fc 182642a;region=DIV1;q1=regulation%20s-x;rgn=div7;view=text;idno=17;node=17%3A2.0.1.1.8.0.21. |
3
Denbury Resources Inc.
PART I
Item 1. Business
Website Access to Reports
We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of
the Securities Exchange Act of 1934, available free of charge on or through our Internet website,
www.denbury.com, as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the SEC.
The Company
Denbury Resources Inc. is a Delaware corporation organized under Delaware General Corporation
Law (DGCL) and is engaged in the acquisition, development, operation and exploration of oil and
natural gas properties in the Gulf Coast region of the United States, primarily in Mississippi,
Louisiana, Texas and Alabama. Our corporate headquarters is located at 5100 Tennyson Parkway,
Suite 1200, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2009, we had
830 employees, 492 of whom were employed in field operations or at the field offices. Our employee
count does not include the approximately 675 employees of Genesis Energy, LLC as of December 31,
2009, as its employees exclusively carry out the business activities of Genesis Energy, L.P., which
we do not consolidate in our financial statements. On February 5, 2010, we sold our interest in
Genesis Energy, LLC, the general partner of Genesis Energy, L.P. (see Notes 1 and 15 to the
Consolidated Financial Statements). On October 31, 2009, we signed a definitive merger agreement
to acquire Encore Acquisition Company (Encore) in a
merger, which merger is subject to approval
by shareholders of Denbury and Encore and other conditions, is scheduled to close on or about March
9, 2010.
Incorporation and Organization
Denbury was originally incorporated in Canada in 1951. In 1992, we acquired all of the shares
of a United States operating company, Denbury Management, Inc. (DMI), and subsequent to the
merger we sold all of its Canadian assets. Since that time, all of our operations have been in the
United States.
In April 1999, our stockholders approved a move of our corporate domicile from Canada to the
United States as a Delaware corporation. Along with the move, our wholly owned subsidiary, DMI,
was merged into the new Delaware parent company, Denbury Resources Inc. This move of domicile did
not have any effect on our operations or assets.
Effective December 29, 2003, Denbury Resources Inc. changed its corporate structure to a
holding company format. As part of this restructure, Denbury Resources Inc. (predecessor entity)
merged into a newly formed limited liability company, and survived as Denbury Onshore, LLC, a
Delaware limited liability company and an indirect subsidiary of the newly formed holding company,
Denbury Holdings, Inc. Denbury Holdings, Inc. subsequently assumed the name Denbury Resources Inc.
Stockholders ownership interests in the business did not change as a result of the new structure
and shares of the Company continue to trade publicly under the same symbol (DNR) on the New York
Stock Exchange.
Business Strategy
As part of our corporate strategy, we believe in the following fundamental principles:
remain focused in specific regions where we either have, or believe we can
create, a competitive advantage as a result of our ownership or use of
CO2 reserves, oil fields and CO2
infrastructure;
acquire properties where we believe additional value can be created through
tertiary recovery operations and a combination of other exploitation, development,
exploration and marketing techniques;
acquire properties that give us a majority working interest and operational
control or where we believe we can ultimately obtain it;
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Denbury Resources Inc.
maximize the value of our properties by increasing production and reserves
while controlling cost; and
maintain a highly competitive team of experienced and incentivized personnel.
Definitive Merger Agreement to Acquire Encore Acquisition Company.
On November 1, 2009, Denbury and Encore Acquisition Company (NYSE: EAC) (Encore) announced
that we had entered into a definitive merger agreement providing for Encore to merge with and into
Denbury, in a stock and cash transaction valued at approximately $4.5 billion at that time,
including the assumption of debt and the value of the noncontrolling interest in Encore Energy
Partners LP (NYSE: ENP) (Encore MLP). The combined company will continue to be known as Denbury
Resources Inc. and will be headquartered in Plano, Texas.
The Agreement and Plan of Merger by and between Denbury and Encore dated October 31, 2009 (the
Merger Agreement) was unanimously approved by the boards of directors of both Denbury and Encore.
The Merger Agreement contemplates a merger (the Merger) whereby Denbury and Encore have agreed
to combine their businesses such that Encore will be merged with and into Denbury, with Denbury
surviving the Merger. The Merger is subject to the stockholders of each of Denbury and Encore
approving the Merger, including approval by Denburys stockholders of the issuance of Denbury
common stock to be used as Merger consideration. Each company has scheduled a special stockholder
meeting on March 9, 2010, for stockholders to vote on the Merger.
Encore is engaged in the acquisition and development of oil and natural gas reserves from
onshore fields in the United States. Encores properties and oil and gas reserves are located in
four core areas: the Cedar Creek Anticline in the Williston Basin in Montana and North Dakota; the
Permian Basin in west Texas and southeastern New Mexico; the Rocky Mountain region, which includes
non-Cedar Creek Anticline assets in the Williston, Big Horn and Powder River Basins in Wyoming,
Montana and North Dakota and the Paradox Basin in southeastern Utah; and the Mid-Continent region,
which includes the Arkoma and Anadarko Basins in Oklahoma, the North Louisiana Salt Basin and the
East Texas Basin.
The acquisition by Denbury of Encore positions the combined company as one of the largest
crude oil-focused, independent North American exploration and production companies, with oil
constituting approximately 75% of its combined proved reserves and with future growth predominantly
in oil. The acquisition also creates one of the largest CO2 EOR platforms in
both the Gulf Coast and Rocky Mountain regions, complemented by Denburys ownership and control of
the Jackson Dome CO2 source in Mississippi and CO2 supply
contracts with potential anthropogenic sources of CO2 in the Gulf Coast,
Midwest and Rockies. Denbury expects the combined companys size and scale, access to capital and
geographic presence to facilitate larger CO2 projects, additional property
acquisitions and opportunities to partner with CO2 emitters, in both the Gulf
Coast and Rocky Mountain regions. The combined company will nearly double Denburys inventory of
oil reserves (prior to the Conroe acquisition) potentially recoverable with CO2
tertiary operations. Denbury believes that the longer lead-time of CO2
project development in the Rocky Mountain region, where Encores legacy oil assets are
distinguished by their long reserve lives and low decline rates, is well-matched with a strong
growth profile from low-risk development of unconventional resource plays in Encores large acreage
positions in the Bakken oil shale in North Dakota and positions in the Haynesville shale in north
Louisiana.
For more information regarding Encore, its properties and the reasons for the merger, please
see Encores 2009 Form 10-K filed with the SEC on
February 25, 2010, and our joint proxy
statement/prospectus dated February 5, 2010.
Merger Agreement
Under the Merger Agreement, Encore stockholders will receive $50.00 per share for each share
of Encore common stock, comprised of $15.00 in cash and $35.00 in Denbury common stock, subject to
both an election feature and a collar mechanism on the stock portion of the consideration as set
forth in more detail below.
Exchange Ratio
In calculating the exchange ratio range for the collar mechanism, the Denbury common stock was
initially valued at $15.10 per share. The collar mechanism is limited to a 12% upward or downward
movement in the Denbury share price. The final number of Denbury shares to be issued will be
adjusted based on the volume
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Denbury Resources Inc.
weighted average price of Denbury common stock on the NYSE for the 20-day trading period
ending on the second day prior to closing. Based on this mechanism, if Denbury stock trades
between $13.29 and $16.91, the Encore stockholders will receive between 2.0698 and 2.6336 shares of
Denbury common stock for each of their shares of Encore common stock, but not higher or lower than
these share amounts if Denbury common stock trades outside this range. If Denbury common stock
trades outside of this range, the value of the shares of Denbury received will represent either
more or less than $35 per share.
Encore stockholders will also have an option to elect to receive all stock or all cash,
subject to a proration feature, such that if Denbury stock trades within this range, the overall
mix of consideration will be 70% Denbury common stock and 30% cash in the aggregate. Subject to
proration, Encore stockholders electing to receive all cash will receive $50 per share in cash, and
Encore stockholders electing to receive only Denbury common stock will receive for each Encore
share between 2.9568 and 3.7622 shares of Denbury common stock. In addition, upon completion of
the Merger, all Encore stock options will fully vest and their value will be paid in cash. All
Encore restricted stock will vest and each holder will have the opportunity to make the same
elections as other holders of Encore common stock as described above, except for shares of Encore
restricted stock granted as a 2009 bonus pursuant to the Encore annual incentive program, which
will be converted into restricted shares of Denbury common stock.
Covenants
The Merger Agreement contains customary covenants by each party to the Merger Agreement. Such
covenants include, among others, covenants that, prior to the effective time of the Merger, both
Denbury and Encore will operate their respective businesses in the ordinary course and in a manner
consistent with past practices, subject to limited exceptions, and covenants by both Denbury and
Encore that their respective boards of directors not change their recommendations to the
stockholders of each of them to vote in favor of the Merger, subject to exceptions specified in the
Merger Agreement. Encore has also agreed not to solicit or initiate discussions with third parties
regarding other proposals to acquire Encore and to certain restrictions on its ability to respond
to any such proposal.
Conditions to Closing
Consummation of the Merger is subject to customary conditions, including, among others, (a)
the adoption of the Merger Agreement by the requisite approval of the stockholders of both Denbury
and Encore, (b) the absence of any material adverse effect, (c) the absence of any order or
injunction prohibiting the consummation of the Merger, (d) the approval of the listing of the
shares of Denbury common stock to be issued in the Merger on the New York Stock Exchange, (e) the
accuracy of the parties respective representations and warranties as set forth in the Merger
Agreement, subject, as to certain of the representations and warranties as specified in the Merger
Agreement, to materiality, (f) the receipt of legal opinions stating, among other things, that the
Merger will constitute a reorganization under Section 368(a) of the Internal Revenue Code of 1986,
as amended, and (g) the receipt of all approvals or reviews required by federal and state
regulatory authorities.
Financing of the Merger
We received a financing commitment from J.P. Morgan, subject to customary conditions, to
underwrite a new $1.6 billion senior secured revolving credit facility. We have been advised by
the co-arrangers of this new senior secured revolving credit facility, J.P. Morgan and Bank of
America, N.A., that the syndication phase is complete, and documentation for this facility is being
prepared. Subject to final documentation and satisfaction of closing conditions, we anticipate
finalizing this facility prior to the Denbury and Encore stockholder meetings. The newly committed
financing, coupled with the funds from our recent senior subordinated debt offering (see next
paragraph), will be used to fund the cash portion of the merger consideration (inclusive of
payments due to Encore stock option holders), repay amounts outstanding under our existing $750
million revolving credit facility, which had $125 million outstanding as of February 15, 2010,
potentially retire and replace up to $825 million of Encores senior subordinated notes that are
outstanding, all of which have a change of control put option at 101% of par value, repay amounts
outstanding under Encores existing revolving credit facility which had $155 million outstanding as
of February 15, 2010, pay Encores severance costs, pay transaction fees and expenses and provide
additional liquidity. The aggregate commitment of the senior secured lenders is a $1.6 billion
facility with a term of four years. The new facility is expected to be on substantially the same
terms as our existing facility, conformed to current market conditions.
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Denbury Resources Inc.
We also received a financing
commitment from J.P. Morgan for a $1.25 billion unsecured bridge
loan facility; however, this bridge loan facility has been terminated and will not be utilized to
fund the Merger as we have instead issued $1 billion of 8.25% Senior Subordinated Notes due 2020.
On February 10, 2010, we sold $1 billion of 8.25% Senior Subordinated Notes due 2020 at 100% of par
in a public offering. The net proceeds from the notes offering were placed in escrow pending the
closing of the Merger, subject to mandatory redemption of the notes if the Merger does not close,
and partial redemption of the notes to the extent that three series of Encore outstanding senior
subordinated notes are not repurchased. Upon the closing of the Merger, $400 million of the
escrowed proceeds will be released to us to finance a portion of the merger consideration, and the
remaining amount of escrowed proceeds will be used to fund
repurchases of up to $600 million principal amount of three series of Encores outstanding senior
subordinated notes (or newly issued 8.25% Senior notes to the extent
not used to repurchase Encore notes). On February 8, 2010, we initiated a tender offer for these Encore subordinated
notes, the closing of which is subject to closing of the Merger.
We also received a financing commitment from J.P. Morgan and JPMorgan Chase to fund a new $375
million senior secured revolving credit facility to replace an existing senior secured revolving
credit facility of Encore Energy Partners Operating LLC, a subsidiary of ENP, if required to allow
for the Merger. On November 24, 2009, ENP obtained an amendment to its existing revolving credit
facility to allow for the Merger; consequently this third financing commitment will not be used.
Fee letters executed in connection with the financing commitments require Denbury to pay up to
approximately $48 million in fees if the Merger does not close.
Termination
The Merger Agreement contains certain termination rights for both us and Encore, including,
among others, if the Merger has not occurred on or before May 31, 2010. On a termination of the
Merger Agreement under certain circumstances, Encore may be required to pay us a termination fee of
either $60 million or $120 million, or we may be required to pay Encore a termination fee of either
$60 million, $120 million or $300 million, in each case depending on the circumstances of the
termination. In addition, Encore is obligated to reimburse us for up to $10 million of our expenses
related to the Merger if specified termination events occur.
Other Acquisitions
Information as to recent acquisitions and divestitures by Denbury is set forth under Note 2,
Acquisitions and Divestitures, to the Consolidated Financial Statements.
Oil and Natural Gas Operations
Our CO2 Assets
Overview. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999,
we have gradually increased our emphasis on these types of operations. During this time, we have
learned a considerable amount about tertiary operations and working with carbon dioxide. Our
tertiary operations have grown to the point that approximately 65% of our December 31, 2009 proved
reserves are proved tertiary oil reserves, almost 65% of our forecasted 2010 production is expected
to come from tertiary oil operations (on a BOE basis), and almost all of our 2010 capital
expenditures are related to our current or future tertiary operations. We particularly like this
play as (i) it has a lower risk as we are working with oil fields that have significant historical
production and data, (ii) it provides a reasonable rate of return at relatively low oil prices (we
estimate our economic break-even before corporate overhead and expenses on these projects at
current oil prices is in the range of the mid-thirties, depending on the specific field and area),
and (iii) we have limited competition for this type of activity in our geographic areas.
Generally, from East Texas to Florida, there are no known significant natural sources of
CO2 in the Gulf Coast area except our own, and these large volumes of
CO2 that we own drive the play. In addition, we are pursuing anthropogenic
(man-made) sources of CO2 to use in our tertiary operations, which we believe
will not only help us recover additional oil, but will provide an economical way to sequester
CO2. We have acquired several old oil fields in our areas of operations with
potential for tertiary recovery and plan to acquire additional fields, and we are continuing to
expand our CO2 pipeline infrastructure to transport CO2.
During 2009, we added 17.6 MMBbls of tertiary-related proved oil reserves, primarily initial
proven tertiary oil reserves at Cranfield Field (Phase 4), (see discussion of the individual fields
below), increasing our proved tertiary oil reserves from 125.8 MMBbls at December 31, 2008 to 134.5
MMBbls as of December 31, 2009. In order to recognize proved tertiary oil reserves, we must either
have an oil production response to the CO2 injections or the
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Denbury Resources Inc.
field must be analogous to an existing tertiary flood. The magnitude of proved reserves that
we can book in any given year will depend on our progress with new floods and the timing of the
associated production response.
CO2 used in enhanced oil recovery (EOR) is one of the most
efficient tertiary recovery mechanisms for crude oil. The CO2 acts somewhat
like a solvent for the oil, removing it from the oil-bearing formation as the CO2
passes through the rock. CO2 tertiary floods are unique because they
require large volumes of CO2, the location of which, to our knowledge, is
limited to a few geological basins, one of which is our source near Jackson, Mississippi. The most
efficient way to transport CO2 is via dedicated pipelines, which are also in
limited supply. Because the sources and methods of transportation of CO2 are
limited, only 5% or approximately 250,000 Bbls/d of the United States domestic oil production is
derived from tertiary recovery projects.
Our CO2 source field, Jackson Dome, located near Jackson, Mississippi, was
discovered during the 1970s while being explored for hydrocarbons. This significant source of
CO2 is the only known one of its kind in the United States east of the
Mississippi River. Mississippis first enhanced oil recovery project began in the mid 1980s in
Little Creek Field following the installation of Shell Oil Companys Choctaw CO2
Pipeline. The 183-mile Choctaw Pipeline (now referred to as NEJD Pipeline) transported
CO2 produced from Jackson Dome to Little Creek Field. While the
CO2 flood proved successful in recovering significant amounts of oil, commodity
prices at that time made the project unattractive for Shell and they later sold their oil fields in
this area, as well as the CO2 source wells and pipeline.
While enhanced oil recovery projects utilizing CO2 may not be considered a
new technology, Denbury applies several additional technologies to the fields: well evaluations,
new completion or stimulation techniques, operating equipment and seismic interpretations. We
began our CO2 operations in August 1999, when we acquired Little Creek Field,
followed by our acquisition of Jackson Dome CO2 reserves and NEJD pipeline in
2001. Based upon our success at Little Creek, we embarked upon a strategic program to improve our
understanding and knowledge of CO2 production and tertiary recovery to build a
dominant position in this enhanced oil play.
Tertiary Recovery Phases. We categorize our tertiary operations by labeling operating areas
or groups of fields as phases.
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Phase 1 includes several fields along our 183-mile NEJD CO2
Pipeline that runs through southwest Mississippi and into Louisiana. The most
significant fields in this area are Little Creek, Mallalieu, McComb, and Brookhaven
Fields, all fields which have been producing oil for some time, and one of our newer
enhanced oil fields, Lockhart Crossing Field. We saw our first tertiary oil production
from Lockhart Crossing Field, located in South Louisiana, during 2008. Lockhart
Crossing, although a relatively small field, was the first of three fields to be
CO2 flooded in Louisiana and is our first flood outside the state
of Mississippi. Although Phase 1 fields have been producing for some time, they
accounted for approximately 50% of our total 2009 CO2 EOR
production. |
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Phase 2, which began with the early 2006 completion of the Free State
CO2 Pipeline to East Mississippi, includes Eucutta, Soso, and
Martinville Fields which have been producing oil for over three years, and Heidelberg
Field where we started injecting CO2 in December 2008. Heidelberg
had its first EOR production response to CO2 injections during May
2009. |
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Phase 3, Tinsley Field, located northwest of Jackson, Mississippi, acquired in
January 2006, is serviced by the Delta CO2 Pipeline completed in
January 2008. Tinsley Field had its first oil production response in the second
quarter of 2008. |
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Phase 4 includes Cranfield, where we began CO2 injection
operations during July 2008 and had our first oil production response in the first
quarter of 2009, and Lake St. John Field, a project currently scheduled to commence
during 2011 or 2012. Both Phase 4 fields are located near the Mississippi/Louisiana
border, near Natchez, Mississippi. |
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Phase 5 is Delhi Field, a Louisiana field acquired in 2006, located southwest of
Tinsley Field and east of Monroe, Louisiana. CO2 injection in
Delhi Field began during the fourth quarter of 2009, following completion of an
additional 81-mile segment of the Delta CO2 Pipeline. We expect
our first oil production response to CO2 injection at Delhi Field
by mid-2010. |
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Phase 6 is Citronelle Field in Southwest Alabama, another field acquired in 2006.
Citronelle will require an extension to the Free State CO2
Pipeline, or a man-made source of CO2 in order to |
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Denbury Resources Inc.
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commence this project, the timing of which is uncertain at this time. |
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Phases 7 and 8 will require completion of our 320-mile Green Pipeline, which will
run from Southern Louisiana to Hastings Field, south of Houston, Texas, and is
scheduled for completion late 2010. Hastings Field, a field on which we acquired a
purchase option late 2006 and purchased in February 2009, is our Phase 7, the
Seabreeze Complex (Oyster Bayou Field), acquired in 2007, will be our Phase 8. We
expect to commence CO2 injections at Oyster Bayou Field in mid-2010
and at Hastings field in early 2011. |
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Phase 9 is Conroe Field, acquired in December 2009. |
Jackson Dome. In February 2001, we acquired approximately 800 Bcf of proved producing
CO2 reserves for $42 million, a purchase that gave us control of most of the
CO2 supply in Mississippi, as well as ownership and control of a critical
183-mile CO2 pipeline. This acquisition provided the platform to significantly
expand our CO2 tertiary recovery operations by assuring that
CO2 would be available to us on a reliable basis and at a reasonable and
predictable cost. Since February 2001, we have acquired two wells and drilled 21 additional
CO2 producing wells, significantly increasing our estimated proved
CO2 reserves to approximately 6.3 Tcf as of December 31, 2009, which is almost
enough for our existing and currently planned phases of operations. The estimate of 6.3 Tcf of
proved CO2 reserves is based on 100% ownership of the CO2
reserves, of which Denburys net ownership (net revenue interest) is approximately 5.0 Tcf and is
included in the evaluation of proved CO2 reserves prepared by DeGolyer and
MacNaughton. In discussing our available CO2 reserves, we make reference to
the gross amount of proved reserves, as this is the amount that is available both for Denburys
tertiary recovery programs and for industrial users who are customers of Denbury and others, as
Denbury is responsible for distributing the entire CO2 production stream.
Although our current proved and potential CO2 reserves are quite large, in
order to continue our tertiary development of oil fields in the area, incremental deliverability of
CO2 is required. In order to obtain additional CO2
deliverability, we continued our exploration efforts by evaluating a 136-square-mile 3-dimensional
seismic program during 2009. The 3-D seismic program, located west of the DRI Ice Field, was
acquired during 2008 over existing known CO2 fields and adjacent lead areas. We
anticipate drilling three wells during 2010, one or two of which will be exploratory wells based
upon the interpretation of the seismic data. During 2009, we drilled and completed one additional
CO2 production well. The 2009 well added approximately 340 Bcf of additional
CO2 reserves and increased our estimated Jackson Dome total
CO2 production capacity to approximately 1.0 Bcf/d. Additional
CO2 reserves were added by acquiring additional proved non-producing acreage
over one of our existing fields. In addition to increasing our proved reserves by 0.9 Bcf (after
the effect of 2009 production), and in order to ensure future production rates, processing
capabilities and deliverability to our fields, during 2009 we constructed a 150 MMcf/d dehydration
facility, installed additional pump capacity at the Brandon Pump Station and constructed a 14-mile
pipeline from the Barksdale dehydration facility to the Brandon Pump Station. This 14-mile Brandon
pipeline and pump station will provide additional capacity to the southern end of the NEJD
Pipeline.
During 2009, we sold an average of 88 MMcf/d of CO2 to commercial users,
and we used an average of 595 MMcf/d for our tertiary activities. We are continuing to increase
our CO2 production, which averaged 790 MMcf/d during the fourth quarter of
2009, a 3% increase over the fourth quarter of 2008 production levels. We estimate that our
planned tertiary operations will not require any significant additional deliverability through 2010
above the production capacity of 1.0 Bcf/d.
Man-made CO2 Sources. In addition to our natural source of
CO2, we have entered into long-term contracts to purchase man-made
CO2 from eight proposed plants that will emit large volumes of
CO2, four of which are in the Gulf Coast region and four in the Midwest region
(Illinois, Indiana and Kentucky.) The Midwest purchases are conditioned on both the specific plant
being constructed and Denbury contracting enough volumes of CO2 for purchase in
the general area of our proposed Midwest pipeline system, such that an acceptable economic
rate-of-return on the CO2 pipeline will be achieved. If all eight of these
plants were to be built, these CO2 sources are currently anticipated to provide
us with aggregate CO2 volumes of 1.2 Bcf/d to 1.9 Bcf/d, although the earliest
source of this man-made CO2 is not expected to be available to us until 2014.
These plants have all been delayed due to current economic conditions and there is some doubt as to
whether they will be constructed at all. Several of these plants are seeking funds from government
sources, which if secured, could increase the probability that the plants are ultimately
constructed.
The base price of CO2 per Mcf from these CO2 sources varies by plant and
location, but is generally higher than
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Denbury Resources Inc.
our most recent all-in cost of CO2 from our natural source (Jackson Dome) using
current oil prices. Prices for CO2 delivered from these projects are expected to be
competitive with the cost of our natural CO2 after adjusting for our share of potential
carbon emissions reduction credits using estimated futures prices of carbon emissions reduction
credits. If all eight plants are built, the aggregate purchase obligation for this CO2
would be around $280 million per year, assuming a $70 per barrel oil price, before any potential
savings from our share of carbon emissions reduction credits. All of the contracts have price
adjustments that fluctuate based on the price of oil. Construction has not yet commenced on any of
these plants, and their construction is contingent on the satisfactory resolution of various
issues, including financing. While it is likely that not every plant currently under contract will
be constructed, there are several other plants under consideration that could provide
CO2 to us that would either supplement or replace some of the CO2 volumes
from the eight proposed plants for which we currently have CO2 output purchase
contracts. We are having ongoing discussions with several of these other potential sources.
CO2 Pipelines. We acquired the NEJD 183-mile
CO2 pipeline that runs from Jackson Dome to near Donaldsonville, Louisiana, as
part of the 2001 acquisition of our Jackson Dome source field (see above). Construction of our
Free State Pipeline was completed in 2006 and it is currently transporting CO2
to our four existing Phase 2 tertiary fields in East Mississippi (Eucutta, Soso, Martinville and
Heidelberg) and will also be used for our proposed projects at South Cypress Creek and other fields
in Phase 2.
During 2008, we continued our expansion of our CO2 pipeline infrastructure
with the completion of the first segment of our Delta Pipeline between Jackson Dome and Tinsley
Field in January (31 miles), which significantly increased the transportation capacity of
CO2 to that field. We also reconditioned and converted the natural gas
pipeline we acquired from Southern Natural Gas Company in 2007 to CO2 service,
which we are currently using to transport CO2 to our first Phase 4 field,
Cranfield Field. During 2009, we completed construction on the 68-mile extension of the Delta
Pipeline from Tinsley Field to Delhi Field.
In late 2006, we purchased an option to acquire Hastings Field, a potential tertiary flood
located near Houston, Texas, which we subsequently acquired in February 2009. In order to flood
Hastings Field, we are building a CO2 pipeline from the southern end of our
existing NEJD CO2 Pipeline that terminates near Donaldsonville, Louisiana, to
Hastings Field, estimated to be approximately 320 miles (the Green Pipeline). Based on our
latest estimates, this pipeline is expected to cost between $850 million and $875 million. Our
efforts during 2007 and 2008 were focused on engineering design, pipe manufacturing and
right-of-way acquisitions. Construction of the pipeline began during November 2008 near
Donaldsonville, Louisiana, and was welded-out to Oyster Bayou Field, near Houston, Texas, in
December 2009. Construction will continue during 2010 to complete the final segments of the
pipeline from Oyster Bayou to Hastings Field (approximately 53 miles). Construction crews will
complete the pipeline and its connecting line to Oyster Bayou Field, east of Galveston Bay, in
early 2010 and on to Hastings Field by year-end 2010. Initially, we anticipate transporting
CO2 from our natural source at Jackson Dome on this line, but ultimately we
expect that it will be used to ship predominately man-made (anthropogenic) sources of
CO2.
Overall tertiary economics. When we began our tertiary operations several years ago, they
were generally economic at oil prices below $20 per Bbl, although the economics varied by field.
Our costs have escalated during the last few years due to general cost inflation in the industry
and higher oil prices, and we estimate that our current economic break-even, before corporate
overhead and interest, is in the mid-thirties per barrel if oil prices remain at their current
level. Our inception-to-date finding and development costs (including future development and
abandonment costs but excluding expenditures on fields without proved reserves) for our tertiary
oil fields through December 31, 2009, are approximately $12.68 per BOE. Currently, we forecast
that our finding and development costs for most of our tertiary projects will average less than $10
per BOE over the life of each field, depending on the state of a particular field at the time we
begin operations, the amount of potential oil to be recovered, the proximity to a pipeline or other
facilities, and other factors. The finding and development costs to date do not include additional
probable reserves in fields with current proved reserves. Our operating costs for tertiary
operations are highly dependent on commodity prices and could range from $15 per BOE to $25 per BOE
over the life of each field, again depending on the specific field.
While these economic factors have wide ranges, our rate of return from these operations has
generally been better than our rate of return on traditional oil and natural gas operations, and
thus our tertiary operations have become our single most important focus area. While it is
extremely difficult to accurately forecast future production, we do believe that our tertiary
recovery operations provide significant long-term production growth potential at reasonable rates
of return, with relatively low risk, and thus will be the backbone of our Companys growth for the
foreseeable future. Although we believe that our plans and projections are reasonable and
achievable,
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Denbury Resources Inc.
there could be delays or unforeseen problems in the future that could delay or affect the
economics of our overall tertiary development program. We believe that such delays or price
effects, if any, should only be temporary.
Tentatively, we plan to invest approximately $74 million in 2010 in the Jackson Dome area to
drill three additional wells, install additional pump stations and gathering lines for discovery
wells drilled during the period. These investments will add CO2 deliverability
for future operations along the Gulf Coast. Approximately $365 million in capital expenditures is
budgeted in 2010 at the oil field level in Phases 1 through 9, plus an additional $159 million for
CO2 pipelines, making our combined CO2 related expenditures just
over 90% of our projected $650 million 2010 capital budget, before consideration of capital
expenditures to be incurred on Encore properties if the proposed acquisition of Encore is
completed.
Our Tertiary Oil Fields with Proved Tertiary Reserves
On December 31, 2009, we had total tertiary-related proved oil reserves of approximately 134.5
MMBbls, as further outlined on the table under Item 1. Field Summaries. Overall, our production
from tertiary operations has increased from approximately 1,350 Bbls/d in 1999, the then existing
production at Little Creek Field at the time of acquisition, to an average of 26,307 Bbls/d during
the fourth quarter of 2009. We expect this production to continue to increase for several years as
we expand our tertiary operations to additional fields.
Phase 1 Fields
Mallalieu Field. Mallalieu Field consists of two units, West Mallalieu Unit and the smaller
East Mallalieu Unit. Our initial injections of CO2 commenced in 2001 and our
first oil production from EOR commenced in 2002. Mallalieu field is currently our most prolific
tertiary flood in terms of production, producing 4,005 Bbls/d during the fourth quarter of 2009,
although we believe that the production at this field has peaked and is expected to generally
decline in the future as the field is essentially fully developed. In contrast to many of our
existing fields, Mallalieu Field was not waterflooded prior to CO2 injection.
Therefore, we estimate that the tertiary recovery of oil from Mallalieu Field as a result of
CO2 injection will be higher than the recoveries at other fields. Our December
31, 2009 proved reserves currently project that we will recover an estimated 22% at this field,
higher than our 17% recovery factor that we assume for most other fields in this area. A total of
$20.1 million was invested in this field during 2009 to improve the compression and fluid handling
capabilities at the production facilities. The expansion of the central processing facility in this
field increased CO2 recycle rates from 160 MMcf/d to approximately 230 MMcf/d.
From inception through December 31, 2009, we had net positive cash flow (revenue less
operating expenses and capital expenditures, including the acquisition cost) from Mallalieu Field
of $464.1 million.
McComb and Smithdale Fields. We commenced tertiary recovery operations in 2003 at McComb
Field and started injecting CO2 late that year. The first production response
occurred in the second quarter of 2004 and has generally increased since that time, averaging 2,412
Bbls/d in the fourth quarter of 2009. During 2009, the technical team improved their understanding
of the reservoir and increased production rates by monitoring injection patterns, reworking
producing wells, and using injection surveys for conformance issues within the reservoir. Our
teams efforts lead to increased production without any additional development during 2009. During
2010, the team plans to drill three injection wells and four producing wells and increase
CO2 injection volumes at McComb Field.
The reservoir at Smithdale is channel sand and thus our drilling was based on the
interpretation of our 2007 3-D seismic survey covering the McComb and Smithdale Fields. By
utilizing the 3-D seismic data, our geoscientists are able to put our wells in optimal positions
within the channels at Smithdale to maximize the aerial coverage and sweep of the
CO2 injected. During 2010, we plan to drill two producing wells and one
CO2 injection well based on seismic and reservoir data.
From inception through December 31, 2009, we had not yet recovered our costs in these fields,
with net negative cash flow (revenue less operating expenses and capital expenditures, including
the acquisition costs) from these fields of $76.9 million.
Brookhaven Field. Our first tertiary CO2 production response at
Brookhaven Field occurred during the fourth quarter of 2005, and has generally increased to an
average rate of 3,416 Bbls/d during 2009. Brookhaven Field has three discrete reservoirs that are
being simultaneously CO2 flooded. Our detailed production and reservoir
evaluations identified certain areas of high permeability within the Tuscaloosa Reservoir that act
as thief zones and take a disproportionate volume of CO2 from the injection
wells. Polymer treatments designed to reduce CO2
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Denbury Resources Inc.
injection into these thief zones were pumped successfully on two wells. The polymer
treatments are designed to alter the injection profiles and improve the reservoir sweep
efficiencies in the first and second development areas of Brookhaven Field. We are also
considering the use of water during 2010 to further counteract these thief zones in an attempt to
improve our sweep efficiency, as the initial results from the use of water and microbes at Little
Creek Field have been encouraging (see below). Expansion at Brookhaven will continue during 2010,
with the drilling of approximately four wells, and the reentry or workover of an additional sixteen
wells.
From inception through December 31, 2009, we had net positive cash flow (revenue less
operating expenses and capital expenditures, including the acquisition cost) from Brookhaven of
$52.3 million.
Little Creek Area. Little Creek field, Denburys most mature enhanced oil recovery project,
was acquired in 1999. During the fourth quarter of 2009, production averaged 1,479 Bbls/d from the
Little Creek area, which includes Lazy Creek. During subsequent years we learned and developed
three additional units, Little Creek West, Lazy Creek and Lazy Creek West, which combined with
Little Creek Field comprise the Little Creek area. Production at Little Creek area began declining
during 2006 and is expected to gradually decline in the future, even though we are working to
mitigate production declines by monitoring injection patterns, reworking producing wells and using
injection surveys to control at which intervals the CO2 is injected.
A project was initiated in 2008 between Denbury, Mississippi State University, and the U.S.
Department of Energy to study the process of alternating CO2 injection with
nutrient-enriched water in a CO2 injection well to stimulate the growth and
development of microbes in the reservoir. The one-year project will monitor injection pressures
and offset oil samples for evidence of improved sweep efficiencies within the reservoir as a result
of the growth of the microbes. If successful, the technique could be expanded to other portions of
the field and to other fields. Our initial results from this study have shown encouraging results.
From inception through December 31, 2009, we had net positive cash flow (revenue less
operating expenses and capital expenditures, including the acquisition cost) from Little Creek
(including adjoining smaller fields) of $196.5 million.
Lockhart Crossing Field. Lockhart Crossing, located in Livingston Parish, Louisiana, was our
first CO2 project outside of Mississippi. Lockhart Crossing produces from the
Wilcox formation at an average depth of 10,200 and has similar reservoir characteristics to the
Tuscaloosa formation, which had great success from tertiary flooding at Little Creek and Mallalieu
Fields.
We initiated CO2 injections during December 2007 after completing a
six-mile supply line connecting Lockhart Crossing to the NEJD Pipeline. We saw our first tertiary
production in July 2008. By the end of 2009, we had completed two of the five development phases
in the field and we are using 3-D seismic data to assist us with the remaining development. During
the fourth quarter of 2009, production at Lockhart Crossing Field averaged 1,025 Bbls/d. Expansion
of the third development phase will be completed during 2010, with the drilling of four wells and
the reentry or workover of an additional two wells.
From inception through December 31, 2009, we had not yet recovered our costs in this field,
with net negative cash flow (revenue less operating expenses and capital expenditures, including
the acquisition costs) from this field of $49.0 million.
Phase 2 Fields
Eucutta Field. The oil production response we have experienced in Eucutta confirmed the
results of the pilot project performed in the early 1980s. During the 1980s, Amerada Hess
installed an inverted 5-spot injection pilot in the First City Bank sand (one of the Eutaw sands)
to test the application of CO2 flooding. Although the pilot test only covered
approximately 20 acres, the pilot was successful in recovering an additional 17% of the original
oil in place within the pattern. Based on this success, we designed and constructed a
CO2 flood and facility for the Eucutta Field. Initial well work was completed
and CO2 injection started during the first quarter of 2006. Initial tertiary
oil production occurred in the fourth quarter of 2006. During 2009, we developed the remaining
injection patterns in the field, and expanded the CO2 facility. Oil production
continued to increase as the Eutaw Reservoir was more fully developed, averaging 3,912 Bbls/d
during the fourth quarter of 2009. We anticipate that production from this field has peaked, or is
about to peak, as the field is generally fully developed. With the completion of the majority of
the field development, our 2010 plans will consist of expanded fluid handling capabilities at the
central facility and monitoring compression requirements.
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Denbury Resources Inc.
From inception through December 31, 2009, we had net positive cash flow (revenue less
operating expenses and capital expenditures, including the acquisition cost) from Eucutta of $71.2
million.
Soso Field. Soso Field, near Laurel, Mississippi, produced from numerous reservoirs during
primary production including the Rodessa, Bailey and Cotton Valley sands, all of which we plan to
CO2 flood. We elected to co-develop the Bailey sand and Rodessa sand to accelerate the
development of the potential tertiary oil reserves at Soso. In essence, we will flood the Bailey in
one portion of the field and the Rodessa in the other, with plans to switch formations when each is
depleted. During the first quarter 2006, we initiated our first injections of CO2 into
five Bailey injection wells and initiated injection in the Rodessa during the second quarter of
2006. We saw our first tertiary production in early 2007 from the Bailey and our first response
from the Rodessa in the fourth quarter of 2007.
We made significant additions to the CO2 recycle facility during 2009,
increasing the water separation and handling. Once fluid handling capabilities were addressed,
several jet pumps were installed which assisted in lifting the water in the wellbore and
subsequently increased oil production. The installation of jet pumps is temporary in that as soon
as the well begins producing oil, we are able to recover the pump and install the pump in another
well if necessary. During the fourth quarter of 2009, production at Soso had increased to 3,224
Bbls/d. Additional compression and handling of recycled CO2 will be addressed
during 2010, along with four workovers and/or recompletions to add another injection pattern.
From inception through December 31, 2009, we had not yet recovered our costs in this field
with net negative cash flow (revenue less operating expenses and capital expenditures, including
the acquisition cost) from Soso of $28.2 million.
Martinville Field. We initiated our first injections of CO2 in Martinville Field
during the first quarter of 2006 in both the Rodessa and Mooringsport formations. As is the case
with most of the East Mississippi fields, Martinville produces from multiple reservoirs. Unlike
the majority of our other planned CO2 projects, Martinville does not contain a single
large reservoir to CO2 flood, but rather several smaller reservoirs. We completed
construction of the CO2 facilities and completed the development of the Mooringsport
formation during 2006. During 2008, an additional producing well was drilled to expand the
development of the Rodessa sand. A Lower Hosston huff and puff project was also initiated. The
Lower Hosston project consists of injecting a predetermined volume of CO2 into the
reservoir, allowing the CO2 time to disperse and contact oil, then flowing the well back
and producing the oil that contacted the CO2. We experienced operational difficulties
in producing the first cycle of this huff and puff test during 2009 and moved uphole to another
Hosston interval. Early in 2010, we started the production cycle from this interval and its
preliminary results are promising.
During the fourth quarter of 2009, production at Martinville averaged 724 Bbls/d, almost
all of which is from the Mooringsport. To date, we have booked additional proved reserves in the
Mooringsport, Rodessa IX and a small amount in the Wash-Fred reservoirs. There are several
additional Rodessa reservoirs that will be developed following completion of the
CO2 flood in the Rodessa IX. From inception through December 31, 2009, we had
not yet recovered our costs in this field with net negative cash flow (revenue less operating
expenses and capital expenditures, including the acquisition cost) from Martinville of $2.6
million.
The Martinville Field Wash Fred 8500 reservoir development continues to evolve. The Wash
Fred formation contains a low oil gravity (thick oil), 15o API, which will not develop
miscibility with CO2 at reservoir conditions. Denbury has several fields with
similar low gravity oils, which like the Wash Fred 8500 have had lower recoveries due to the low
oil gravities and strong water drives, which do not sweep the oil efficiently. We have
experimented with this reservoir since 2006 but have not had much success until recently, when an
offset producing well began to produce oil during 2009.
We plan on reactivating one more well to production in 2010, and continue to increase
CO2 injection into this reservoir over time. The ability to produce and
process this heavy crude has been difficult, but if we can economically and satisfactorily resolve
these issues, this field could provide the impetus to look at other heavy oil reservoirs and fields
that we have not previously considered.
Heidelberg Field. During 2009, we added Heidelberg Field as our twelfth producing EOR field.
Construction of the CO2 facility, connecting pipeline and well work commenced
during 2008, with our, first CO2 injections beginning in December 2008. During
2009, we added eight new injection patterns and expanded the central processing facility. Our
first tertiary oil production response occurred during May 2009. The first four stages of
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Denbury Resources Inc.
Heidelbergs CO2 flood are in the West Heidelberg Unit (WHEOUP) Eutaw
formation, the same formation we are CO2 flooding at Eucutta Field. Although
similar in many respects, the Eutaw reservoir at Heidelberg contains two to three times the
potential oil reserves as the Eutaw formation at Eucutta Field. During the fourth quarter of 2009,
production at Heidelberg Field averaged 1,506 Bbls/d. During 2010, we plan to complete the
development of the CO2 flood in WHEOUP at an estimated cost of approximately
$40 million. Development of the East Heidelberg Units will begin in 2011.
From inception through December 31, 2009, we had not yet recovered our cost in this field,
with net negative cash flow (revenue less operating expenses and capital expenditures, including
the acquisition cost) from Heidelberg of $60.8 million.
Phase 3 Field
Tinsley Field. Tinsley Field was acquired in January 2006 and is the largest oil field in the
state of Mississippi. As is the case with the majority of fields in Mississippi, Tinsley produces
from multiple reservoirs. Our primary target in Tinsley for CO2 enhanced oil
recovery operations is the Woodruff formation, although there is additional potential in the Perry
sandstone. We initiated limited CO2 injections in January 2007 through a
previously existing 8 pipeline, but replaced this line in 2008 with the 24 Delta Pipeline. We
had our first tertiary oil production commencing in April 2008. During 2009, we expanded the
central processing facilities and completed Phase 3, which consisted of 31 producing wells and six
injection well conversions. A similar capital investment level of approximately $44 million is
scheduled during 2010, as we continue to expand into Phase 4. During the fourth quarter of 2009,
the average oil production was 3,942 Bbls/d. Tinsley Field produced an additional 351 Bbls/d from
non-CO2 operations during the fourth quarter of 2009.
From inception through December 31, 2009, we had not yet recovered our costs in this field,
with net negative cash flow (revenue less operating expenses and capital expenditures, including
the acquisition cost) from Tinsley of $218.8 million.
Phase 4 Field
Cranfield Field. During 2008, we began development of Cranfield with the drilling or re-entry
of 11 CO2 injectors and 11 producers and reconditioned the natural gas pipeline
that we purchased, converting it to CO2 service. We commenced injections into
the Lower Tuscaloosa reservoir in the third quarter of 2008 and had our first tertiary oil
production in the first quarter of 2009. We continued to expand the flood during 2009 with the
drilling of an additional 2 producers and 2 CO2 injection wells along with two
re-entries of existing wells. During the fourth quarter of 2009, production at Cranfield Field
averaged 728 Bbls/d. During 2010 we plan to spend approximately $35 million for the drilling of an
additional five producers and nine CO2 injection wells, along with seven
re-entries of existing wells. We are participating with the Bureau of Economic Geology (BEG) at the
University of Texas as they study CO2 injection and sequestration at Cranfield,
to better define and understand the movement of CO2 through the Lower
Tuscaloosa reservoir. The results of this study could lead to a greater recovery of the oil in the
reservoir.
From inception through December 31, 2009, we had not yet recovered our investment in this
field, with net negative cash flow (revenue less operating expenses and capital expenditures,
including the acquisition cost) from Cranfield of $86.5 million.
Our Tertiary Oil Fields Without Proved Tertiary Reserves
Conroe Field. On December 18, 2009, we purchased a 95% interest in the Conroe Field, a
potentially significant tertiary flood north of Houston, Texas, for approximately $254.2 million in
cash and 11,620,000 shares of Denbury common stock. We have internally estimated that the Conroe
Field interests have significant estimated net reserve potential from CO2
tertiary recovery, the largest EOR potential of our Gulf Coast oil fields. The acquired Conroe
Field interests have estimated proved conventional reserves of approximately 18.5 MMBbls at
December 31, 2009, nearly all of which are proved developed. The Conroe Field assets are currently
producing around 2,500 BOE/d net to our acquired interest. We will need to build a pipeline to
transport CO2 to this field, preliminarily estimated to cover 80 miles, as an
extension of our Green pipeline. Based on our preliminary estimates, Denbury will spend an
additional $750 million to $1.0 billion, including the cost of the CO2
pipeline, to develop the Conroe Field as a tertiary flood. The development of this tertiary flood
is not expected to begin for four or five years.
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Denbury Resources Inc.
Delhi Field. During May 2006, we purchased the Delhi Holt-Bryant Unit (Delhi) in Northern
Louisiana for $50 million, plus a 25% reversionary interest to the seller after we achieve $200
million in net operating income. We began well work development in 2008 and drilled or recompleted
additional wells in 2009 and built a processing facility. We began delivering CO2 to the field in
the fourth quarter of 2009 via the recently completed Delta Pipeline (Tinsley to Delhi). Based on
early indications, the first enhanced oil production response is anticipated mid-2010. Our 2010
capital plans for the Delhi Field include the drilling of 26 wells and the workover or re-entry of
an additional 30 wells. As of December 31, 2009, there was no significant oil production nor
proved tertiary oil reserves at Delhi Field.
Hastings Field. During November 2006, we entered into an agreement with a subsidiary of
Venoco, Inc. that gave us an option to purchase their interest in Hastings Field, a strategically
significant potential tertiary flood candidate located near Houston, Texas. We exercised the
purchase option prior to September 2008, and closed the $201 million acquisition during February
2009. As consideration for the option agreement, we made total payments of $50 million.
The purchase price of $201 million included approximately $4.9 million for certain surface
land, oilfield equipment and other related assets. Under the terms of the agreement, Venoco, Inc.,
the seller, retained a 2% override and reversionary interest of approximately 25% following payout,
as defined in the option agreement. During the fourth quarter of 2009, production from Hastings
Field averaged 1,983 BOE/d, with conventional proved reserves at December 31, 2009 of approximately
8.9 MMBOE. We plan to commence flooding the field with CO2 beginning in late
2010 or early 2011, after completion of our Green Pipeline currently under construction.
Based on preliminary engineering data, the West Hastings Unit (the most likely area to be
initially developed as a tertiary flood) has significant net reserve potential from
CO2 tertiary floods, the second largest reserve potential of any other single
field in our inventory. We started construction of the Green Pipeline during November 2008 to
transport CO2 to this field (see CO2 Pipelines above).
Based on our latest estimates, it will cost between $400 million and $600 million to develop the
West Hastings Unit as a tertiary flood, excluding the cost of the Green Pipeline.
Oyster Bayou, Fig Ridge and Gillock Fields. During 2007, we acquired an interest in three
fields in Southeast Texas with significant tertiary potential. The Oyster Bayou and Fig Ridge
Fields are located in close proximity to each other and are located on or close to the Green
Pipeline. We acquired the majority interest in Oyster Bayou Field and a relatively small interest
in Fig Ridge Field. We initiated unitization hearings at Oyster Bayou Field during 2009. Because
of current lack of majority interest at Fig Ridge Field, we will need the cooperation of other
operators and lease owners to form the necessary unit. We plan to commence flooding the
Oyster-Bayou Field with CO2 beginning in mid-2010.
Our acquisitions in Gillock Field include an acquisition of almost all of the South Gillock
Unit, the Southeast Gillock unit and the acquisition of a key lease in the Gillock Field. The
Gillock acquisitions are located near the proposed Green Pipeline and Hastings Field. Denbury
continues to evaluate potential acquisition candidates in Southeast Texas and in Louisiana in
proximity to our Green Pipeline and near our pipelines in Mississippi.
Overall Tertiary Economics to Date. Through December 31, 2009, we have invested a total of
$1.8 billion on tertiary oil fields (including the allocated acquisition costs and amounts assigned
to Goodwill), and received $1.6 billion in net operating income (revenue less operating expenses),
or net unrecovered cash flow of $225.7 million, the deficit primarily due to the significant funds
expended on acquisitions during 2009. Of our total spending, approximately $487.4 million was
invested to date on fields that had little or no proved reserves at December 31, 2009 (i.e.,
significant incremental proved reserves are anticipated in future years). These amounts do not
include the capital costs or related depreciation and amortization of our CO2
producing properties at Jackson Dome, which had an unrecovered net cash flow of $1.4 billion
as of December 31, 2009, including $1.1 billion associated with CO2 pipelines.
At year-end 2009, the proved oil reserves in our tertiary recovery oil fields had a PV-10 Value of
approximately $2.3 billion, using 12-month first-day-of-the-month unweighted average NYMEX pricing
of $61.18 per barrel. In addition, there are significant probable and possible reserves at several
other fields for which tertiary operations are under way or planned.
Potential Tertiary Oil Properties from Proposed Acquisition of Encore. The proposed
acquisition of Encore (see Item 1. Business Definitive Merger Agreement to Acquire Encore
Acquisition Company) includes Encores legacy oil fields located in Montana, North Dakota and
Wyoming which will allow us to expand our EOR platform to this region. At the time that the merger
was announced, these fields nearly doubled our total potential
15
Denbury Resources Inc.
oil reserves recoverable through EOR. These legacy oil assets are estimated to have over 6
billion barrels of original oil in place, assets that are distinguished by their long reserve life
and low decline rates and that have significant potential for recovery of crude oil through
CO2 EOR. Denbury expects its significant expertise in EOR in the Gulf Coast to be
directly applicable to Encores Rocky Mountain oilfield assets.
East Mississippi Fields without Proved Tertiary Oil Reserves
We have been active in East Mississippi since Denbury was founded in 1990 and are by far the
largest oil producer in the basin and the state. Conventional or non-tertiary production during
the fourth quarter of 2009 averaged approximately 8,914 BOE/d from this area (20% of our Company
total), and we had proved reserves of 36.1 MMBOE as of December 31, 2009 (17% of our Company
total). Since we have generally owned these Eastern Mississippi properties longer than properties
in our other regions, they tend to be more fully developed, and although most are targeted for
tertiary operations in the future, only four currently have tertiary operations (Soso, Martinville,
Eucutta and Heidelberg Fields). Production from our conventional and secondary recovery operations
in our East Mississippi fields has been gradually depleting, as expected, over the last three
years, averaging 12,479 BOE/d in 2007, 11,897 BOE/d during 2008 and 9,937 BOE/d during 2009.
During 2009, we invested very little capital in the non-tertiary assets in these reserves.
Heidelberg Field. The largest field in the region and one of our largest fields corporately is
Heidelberg Field, which for the fourth quarter of 2009 produced an average of 5,411 BOE/d of
conventional or non-tertiary production. Heidelberg Field was acquired from Chevron in December
1997. The field is a large salt-cored anticline that is divided into western and eastern segments
due to subsequent faulting. Most of the past and current production comes from the Eutaw, Selma
Chalk and Christmas sands at depths from 3,500 to 5,000.
The majority of the conventional oil production at Heidelberg is from waterflood units that
produce from the Eutaw formation (at approximately 4,400). Most of our recent development at
Heidelberg, other than our tertiary operations, has been in the Selma Chalk, a natural gas
reservoir at around 3,700, which subsequent to the sale of our Barnett Shale assets during 2009,
is our only significant remaining natural gas property (prior to the pending Encore acquisition).
We have steadily developed the Selma Chalk since 2001, increasing the natural gas production at
Heidelberg to a peak quarterly average of 19.4 MMcf/d in the fourth quarter of 2008. During late
2006 and early 2007, we drilled our first horizontal wells in West Heidelberg Field where vertical
wells were generally uneconomic. The horizontal wells have performed well and thus we expect to be
able to expand our Selma Chalk development throughout West Heidelberg Field. We severely curtailed
capital expenditures on non-tertiary operations at Heidelberg in 2009 as a result of lower
commodity prices and a desire to allocate our capital resources to our core tertiary operations.
Our current plans include drilling one additional well in the Selma Chalk during 2010.
Field Summaries Production and Proved Reserves
Denbury operates in five primary areas: Eastern Mississippi, Western Mississippi, Texas,
Alabama and Louisiana. Our 19 largest fields (listed below) constitute approximately 97% of our
total proved reserves on a BOE basis, and 96% of our total proved reserves on a PV-10 Value basis.
Within these 19 fields, we own a weighted average 95% working interest and operate all of these
fields. The concentration of value in a relatively small number of fields allows us to benefit
substantially from any operating cost reductions or production enhancements we achieve, and allows
us to effectively manage the properties from our four primary field offices located in Laurel,
Mississippi; Jackson, Mississippi; Little Creek, Mississippi; and Alvin, Texas.
16
Denbury Resources Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Average Daily |
|
|
|
|
Proved Reserves as of December 31, 2009(1) |
|
Production |
|
|
|
|
|
|
Oil |
|
Natural Gas |
|
|
|
|
|
BOE |
|
PV-10 Value(2) |
|
Oil |
|
Natural Gas |
|
Avg |
|
|
(MBbls) |
|
(MMcf) |
|
MBOEs |
|
% of total |
|
(000s) |
|
(Bbls/d) |
|
(Mcf/d) |
|
NRI |
|
|
|
Tertiary Oil Fields |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tinsley(3) |
|
|
33,910 |
|
|
|
|
|
|
|
33,910 |
|
|
|
16.3 |
% |
|
$ |
583,973 |
|
|
|
3,328 |
|
|
|
|
|
|
|
79.9 |
% |
Heidelberg |
|
|
25,433 |
|
|
|
|
|
|
|
25,433 |
|
|
|
12.3 |
% |
|
|
410,680 |
|
|
|
651 |
|
|
|
|
|
|
|
85.6 |
% |
Brookhaven |
|
|
15,972 |
|
|
|
|
|
|
|
15,972 |
|
|
|
7.7 |
% |
|
|
329,918 |
|
|
|
3,416 |
|
|
|
|
|
|
|
81.3 |
% |
McComb Area |
|
|
12,518 |
|
|
|
|
|
|
|
12,518 |
|
|
|
6.0 |
% |
|
|
197,465 |
|
|
|
2,391 |
|
|
|
|
|
|
|
79.0 |
% |
Cranfield |
|
|
10,778 |
|
|
|
|
|
|
|
10,778 |
|
|
|
5.2 |
% |
|
|
189,935 |
|
|
|
448 |
|
|
|
|
|
|
|
77.9 |
% |
Eucutta |
|
|
10,187 |
|
|
|
|
|
|
|
10,187 |
|
|
|
4.9 |
% |
|
|
166,240 |
|
|
|
3,985 |
|
|
|
|
|
|
|
83.5 |
% |
Mallalieu |
|
|
9,984 |
|
|
|
|
|
|
|
9,984 |
|
|
|
4.8 |
% |
|
|
181,118 |
|
|
|
4,107 |
|
|
|
|
|
|
|
79.0 |
% |
Soso |
|
|
8,028 |
|
|
|
|
|
|
|
8,028 |
|
|
|
3.9 |
% |
|
|
119,425 |
|
|
|
2,834 |
|
|
|
|
|
|
|
77.3 |
% |
Lockhart Crossing |
|
|
3,705 |
|
|
|
|
|
|
|
3,705 |
|
|
|
1.8 |
% |
|
|
57,381 |
|
|
|
804 |
|
|
|
|
|
|
|
58.2 |
% |
Little Creek & Lazy Creek |
|
|
2,999 |
|
|
|
|
|
|
|
2,999 |
|
|
|
1.4 |
% |
|
|
42,149 |
|
|
|
1,502 |
|
|
|
|
|
|
|
83.2 |
% |
Martinville |
|
|
1,005 |
|
|
|
|
|
|
|
1,005 |
|
|
|
0.5 |
% |
|
|
8,193 |
|
|
|
877 |
|
|
|
|
|
|
|
77.6 |
% |
|
|
|
Total Tertiary Oil
Fields |
|
|
134,519 |
|
|
|
|
|
|
|
134,519 |
|
|
|
64.8 |
% |
|
|
2,286,477 |
|
|
|
24,343 |
|
|
|
|
|
|
|
79.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heidelberg |
|
|
14,079 |
|
|
|
54,964 |
|
|
|
23,240 |
|
|
|
11.2 |
% |
|
|
203,203 |
|
|
|
3,605 |
|
|
|
14,768 |
|
|
|
75.7 |
% |
Sharon |
|
|
16 |
|
|
|
24,512 |
|
|
|
4,101 |
|
|
|
2.0 |
% |
|
|
27,878 |
|
|
|
11 |
|
|
|
7,848 |
|
|
|
72.7 |
% |
Eucutta |
|
|
1,308 |
|
|
|
|
|
|
|
1,308 |
|
|
|
0.6 |
% |
|
|
24,546 |
|
|
|
309 |
|
|
|
|
|
|
|
41.6 |
% |
Summerland |
|
|
1,255 |
|
|
|
|
|
|
|
1,255 |
|
|
|
0.6 |
% |
|
|
14,780 |
|
|
|
316 |
|
|
|
|
|
|
|
74.4 |
% |
S. Cypress Creek |
|
|
910 |
|
|
|
61 |
|
|
|
920 |
|
|
|
0.4 |
% |
|
|
15,454 |
|
|
|
150 |
|
|
|
10 |
|
|
|
83.1 |
% |
Other Mississippi |
|
|
4,934 |
|
|
|
1,882 |
|
|
|
5,248 |
|
|
|
2.5 |
% |
|
|
85,733 |
|
|
|
1,591 |
|
|
|
1,108 |
|
|
|
16.8 |
% |
|
|
|
Total Mississippi |
|
|
22,502 |
|
|
|
81,419 |
|
|
|
36,072 |
|
|
|
17.3 |
% |
|
|
371,594 |
|
|
|
5,982 |
|
|
|
23,734 |
|
|
|
41.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conroe |
|
|
18,132 |
|
|
|
2,319 |
|
|
|
18,519 |
|
|
|
8.9 |
% |
|
|
210,163 |
|
|
|
117 |
|
|
|
123 |
|
|
|
80.4 |
% |
Hastings |
|
|
8,862 |
|
|
|
|
|
|
|
8,862 |
|
|
|
4.3 |
% |
|
|
119,336 |
|
|
|
1,954 |
|
|
|
9 |
|
|
|
79.1 |
% |
Other Texas |
|
|
224 |
|
|
|
746 |
|
|
|
348 |
|
|
|
0.2 |
% |
|
|
3,547 |
|
|
|
3,051 |
|
|
|
42,057 |
|
|
|
67.6 |
% |
|
|
|
Total Texas |
|
|
27,218 |
|
|
|
3,065 |
|
|
|
27,729 |
|
|
|
13.4 |
% |
|
|
333,046 |
|
|
|
5,122 |
|
|
|
42,189 |
|
|
|
65.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Citronelle |
|
|
8,074 |
|
|
|
|
|
|
|
8,074 |
|
|
|
3.9 |
% |
|
|
64,175 |
|
|
|
1,108 |
|
|
|
|
|
|
|
63.4 |
% |
Alabama and other |
|
|
115 |
|
|
|
87 |
|
|
|
130 |
|
|
|
0.1 |
% |
|
|
2,115 |
|
|
|
5 |
|
|
|
52 |
|
|
|
2.1 |
% |
|
|
|
Total Alabama and
Other |
|
|
8,189 |
|
|
|
87 |
|
|
|
8,204 |
|
|
|
4.0 |
% |
|
|
66,290 |
|
|
|
1,113 |
|
|
|
52 |
|
|
|
52.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Louisiana |
|
|
451 |
|
|
|
3,404 |
|
|
|
1,018 |
|
|
|
0.5 |
% |
|
|
18,052 |
|
|
|
391 |
|
|
|
2,111 |
|
|
|
29.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company Total |
|
|
192,879 |
|
|
|
87,975 |
|
|
|
207,542 |
|
|
|
100 |
% |
|
$ |
3,075,459 |
|
|
|
36,951 |
|
|
|
68,086 |
|
|
|
64.6 |
% |
|
|
|
|
|
|
(1) |
|
The reserves were prepared in accordance with the guidelines of FASC topic 932 Extractive
Industries Oil and Gas using the average first-day-of-the-month prices for each month during
2009 which for NYMEX oil was a price of $61.18 per barrel adjusted to prices received by field and
for natural gas was a Henry Hub cash price of $3.87 per MMBtu, also adjusted to prices received by
field. |
|
(2) |
|
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure of Discounted
Future Net Cash Flows (Standardized Measure) in that PV-10 Value is a pre-tax number and the
Standardized Measure is an after-tax number. The information used to calculate PV-10 Value is
derived directly from data determined in accordance with FASC topic 932. The Standardized Measure
was $2.5 billion at December 31, 2009. A comparison of PV-10 to the Standardized Measure is
included in the table on page 24 as well as further information regarding our use of this non-GAAP
measure. |
|
(3) |
|
Tinsley Field, which had initial tertiary oil production
response from
CO2
injections during the first quarter of 2008, had an average sales
price per unit of oil of $63.09 per barrel in 2009 and $96.36 per
barrel in 2008. Tinsley Field average production cost (excluding ad
valorem and severance taxes) was $18.93 per barrel in 2009 and $33.01
per barrel in 2008. |
17
Denbury Resources Inc.
Oil and Gas Acreage, Productive Wells, and Drilling Activity
In the data below, gross represents the total acres or wells in which we own a working
interest and net represents the gross acres or wells multiplied by Denburys working interest
percentage. For the wells that produce both oil and gas, the well is typically classified as an
oil or natural gas well based on the ratio of oil to gas production.
Oil and Gas Acreage
The following table sets forth Denburys acreage position at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
Undeveloped |
|
Total |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Mississippi |
|
|
153,691 |
|
|
|
110,200 |
|
|
|
248,814 |
|
|
|
33,371 |
|
|
|
402,505 |
|
|
|
143,571 |
|
Louisiana |
|
|
36,029 |
|
|
|
34,322 |
|
|
|
4,570 |
|
|
|
3,891 |
|
|
|
40,599 |
|
|
|
38,213 |
|
Texas |
|
|
41,227 |
|
|
|
38,853 |
|
|
|
5,964 |
|
|
|
2,553 |
|
|
|
47,191 |
|
|
|
41,406 |
|
Alabama |
|
|
19,893 |
|
|
|
15,397 |
|
|
|
69,206 |
|
|
|
12,351 |
|
|
|
89,099 |
|
|
|
27,748 |
|
Other |
|
|
6,853 |
|
|
|
816 |
|
|
|
16,543 |
|
|
|
3,036 |
|
|
|
23,396 |
|
|
|
3,852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
257,693 |
|
|
|
199,588 |
|
|
|
345,097 |
|
|
|
55,202 |
|
|
|
602,790 |
|
|
|
254,790 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denburys net undeveloped acreage that is subject to expiration over the next three years, if
not renewed, is approximately 10% in 2010, 54% in 2011 and 6% in 2012.
Productive Wells
The following table sets forth our gross and net productive oil and natural gas wells at
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Natural |
|
|
|
|
Producing Oil Wells |
|
Gas Wells |
|
Total |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Operated Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
689 |
|
|
|
664.4 |
|
|
|
216 |
|
|
|
197.8 |
|
|
|
905 |
|
|
|
862.2 |
|
Louisiana |
|
|
34 |
|
|
|
26.3 |
|
|
|
9 |
|
|
|
9.0 |
|
|
|
43 |
|
|
|
35.3 |
|
Texas |
|
|
248 |
|
|
|
231.2 |
|
|
|
38 |
|
|
|
34.5 |
|
|
|
286 |
|
|
|
265.7 |
|
Alabama |
|
|
170 |
|
|
|
135.9 |
|
|
|
5 |
|
|
|
3.1 |
|
|
|
175 |
|
|
|
139.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,141 |
|
|
|
1,057.8 |
|
|
|
268 |
|
|
|
244.4 |
|
|
|
1,409 |
|
|
|
1,302.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Operated Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
36 |
|
|
|
2.2 |
|
|
|
230 |
|
|
|
3.8 |
|
|
|
266 |
|
|
|
6.0 |
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
Texas |
|
|
6 |
|
|
|
6.0 |
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
6.0 |
|
Alabama |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
0.7 |
|
|
|
3 |
|
|
|
0.7 |
|
Other |
|
|
32 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
|
|
32 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
74 |
|
|
|
8.8 |
|
|
|
234 |
|
|
|
4.5 |
|
|
|
308 |
|
|
|
13.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
|
725 |
|
|
|
666.6 |
|
|
|
446 |
|
|
|
201.6 |
|
|
|
1,171 |
|
|
|
868.2 |
|
Louisiana |
|
|
34 |
|
|
|
26.3 |
|
|
|
10 |
|
|
|
9.0 |
|
|
|
44 |
|
|
|
35.3 |
|
Texas |
|
|
254 |
|
|
|
237.2 |
|
|
|
38 |
|
|
|
34.5 |
|
|
|
292 |
|
|
|
271.7 |
|
Alabama |
|
|
170 |
|
|
|
135.9 |
|
|
|
8 |
|
|
|
3.8 |
|
|
|
178 |
|
|
|
139.7 |
|
Other |
|
|
32 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
|
|
32 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,215 |
|
|
|
1,066.6 |
|
|
|
502 |
|
|
|
248.9 |
|
|
|
1,717 |
|
|
|
1,315.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
Denbury Resources Inc.
Drilling Activity
The following table sets forth the results of our drilling activities over the last three
years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2009 |
|
2008 |
|
2007 |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Exploratory Wells:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2) |
|
|
1 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
6.2 |
|
Non-productive(3) |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1.0 |
|
|
|
4 |
|
|
|
3.4 |
|
Development Wells:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(2) |
|
|
23 |
|
|
|
16.6 |
|
|
|
102 |
|
|
|
98.3 |
|
|
|
101 |
|
|
|
96.8 |
|
Non-productive(3)(4) |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
0.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
24 |
|
|
|
17.6 |
|
|
|
104 |
|
|
|
100.0 |
|
|
|
114 |
|
|
|
106.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
An exploratory well is a well drilled either in search of a new, as yet undiscovered, oil
and natural gas reservoir or to greatly extend the known limits of a previously discovered
reservoir. A development well is a well drilled within the presently proved productive area of an
oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the
objective of completing in that reservoir. |
|
(2) |
|
A productive well is an exploratory or development well found to be capable of producing either
oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. |
|
(3) |
|
A nonproductive well is an exploratory or development well that is not a producing well. |
|
(4) |
|
During 2009, 2008 and 2007 an additional 20, 33 and 23, wells, respectively, were drilled for
water or
CO2 injection purposes. |
Production and Unit Prices
Information regarding average production rates, unit sale prices and unit costs per BOE are
set forth under Managements Discussion and Analysis of Financial Condition and Results of
Operations Operating Results included herein.
Title to Properties
Customarily in the oil and natural gas industry, only a perfunctory title examination is
conducted at the time properties believed to be suitable for drilling operations are first
acquired. Prior to commencement of drilling operations, a thorough drill site title examination is
normally conducted, and curative work is performed with respect to significant defects. During
acquisitions, title reviews are performed on all properties; however, formal title opinions are
obtained on only the higher value properties. We believe that we have good title to our oil and
natural gas properties, some of which are subject to minor encumbrances, easements and
restrictions.
Geographic Segments
All of our operations are in the United States.
Significant Oil and Gas Purchasers and Product Marketing
Oil and gas sales are made on a day-to-day basis under short-term contracts at the current
area market price. The loss of any single purchaser would not be expected to have a material
adverse effect upon our operations; however, the loss of a large single purchaser could potentially
reduce the competition for our oil and natural gas production, which in turn could negatively
impact the prices we receive. For the year ended December 31, 2009, two purchasers accounted for
10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (52%) and Hunt
Crude Oil Supply Co. (21%). For the year ended December 31, 2008, we had three significant
purchasers that each
accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC
(49%), Hunt Crude Oil Supply Co. (20%) and Crosstex Energy Field Services Inc. (14%). For the year
ended December 31, 2007, three purchasers each accounted for 10% or more of our oil and natural gas
revenues: Marathon Petroleum Company LLC (43%), Hunt Crude Oil Supply Co. (19%) and Crosstex Energy
Field Services Inc. (16%).
19
Denbury Resources Inc.
Our ability to market oil and natural gas depends on many factors beyond our control,
including the extent of domestic production and imports of oil and gas, the proximity of our gas
production to pipelines, the available capacity in such pipelines, the demand for oil and natural
gas, the effects of weather, and the effects of state and federal regulation. Our production is
primarily from developed fields close to major pipelines or refineries and established
infrastructure. As a result, we have not experienced any difficulty to date in finding a market
for all of our production as it becomes available or in transporting our production to those
markets; however, there is no assurance that we will always be able to market all of our production
or obtain favorable prices.
Oil Marketing
The quality of our crude oil varies by area, thereby impacting the corresponding price
received. As an example, in Heidelberg Field, one of our larger fields, and our other Eastern
Mississippi non-tertiary properties, our oil production is primarily light to medium sour crude and
sells at a significant discount to the NYMEX prices. In Western Mississippi, the location of our
Phase 1 tertiary operations, our oil production is primarily light sweet crude, which typically
sells at near NYMEX prices, or often at a premium. For the year ended December 31, 2009, the
discount for our non-tertiary oil production from Heidelberg Field averaged $10.59 per Bbl and for
our Eastern Mississippi non-tertiary properties as a whole the discount averaged $9.26 per Bbl
relative to NYMEX oil prices. For our Phase 1 tertiary fields in Southwest Mississippi, we
averaged a premium of $1.21 per Bbl over NYMEX oil prices during 2009.
Natural Gas Marketing
Virtually all of our natural gas production is close to existing pipelines and consequently we
generally have a variety of options to market our natural gas. We sell the majority of our natural
gas on one-year contracts with prices fluctuating month-to-month based on published pipeline
indices with slight premiums or discounts to the index. We receive near NYMEX or Henry Hub prices
for most of our natural gas sales in Mississippi. For the year ended December 31, 2009, we
averaged $0.14 per Mcf below NYMEX prices for our Mississippi natural gas production. However, in
the Texas Gulf Coast region, due primarily to its location, the price we received averaged $0.01
per Mcf above NYMEX prices.
Competition and Markets
We face competition from other oil and natural gas companies in all aspects of our business,
including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and
obtaining goods, services and labor. Many of our competitors have substantially larger financial
and other resources. Factors that affect our ability to acquire producing properties include
available liquidity, available information about prospective properties and our standards
established for minimum projected return on investment. Gathering systems are the only practical
method for the intermediate transportation of natural gas. Therefore, competition for natural gas
delivery is presented by other pipelines and gas gathering systems. Competition is also presented
by alternative fuel sources, including heating oil and other fossil fuels. Because of the nature of
our core assets (our tertiary operations) and our ownership of a relatively uncommon significant
natural source of carbon dioxide, we believe that we are effective in competing in the market.
The demand for qualified and experienced field personnel to drill wells and conduct field
operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas
industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing
periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand
for rigs and equipment has increased along with the number of wells being drilled. These factors
also cause significant increases in costs for equipment, services and personnel. Higher oil and
natural gas prices generally stimulate increased demand and result in increased prices for drilling
rigs, crews and associated supplies, equipment and services. We cannot be certain when we will
experience these issues, and these types of shortages or price increases could significantly
decrease our profit margin, cash flow and operating results or restrict our ability to drill those
wells and conduct those operations that we currently have planned and budgeted.
Federal and State Regulations
Numerous federal and state laws and regulations govern the oil and gas industry. These laws
and regulations are often changed in response to changes in the political or economic environment.
Compliance with this evolving
20
Denbury Resources Inc.
regulatory burden is often difficult and costly, and substantial
penalties may be incurred for noncompliance. The following section describes some specific laws
and regulations that may affect us. We cannot predict the impact of these or future legislative or
regulatory initiatives.
Management believes that we are in substantial compliance with all laws and regulations
applicable to our operations and that continued compliance with existing requirements will not have
a material adverse impact on us. The future annual capital cost of complying with the regulations
applicable to our operations is uncertain and will be governed by several factors, including future
changes to regulatory requirements. However, management does not currently anticipate that future
compliance will have a materially adverse effect on our consolidated financial position or results
of operations.
Regulation of Natural Gas and Oil Exploration and Production
Our operations are subject to various types of regulation at the federal, state and local
levels. Such regulation includes requiring permits for drilling wells; maintaining bonding
requirements in order to drill or operate wells and regulating the location of wells; the method of
drilling and casing wells; the surface use and restoration of properties upon which wells are
drilled; the plugging and abandoning of wells; and the disposal of fluids used in connection with
operations. Our operations are also subject to various conservation laws and regulations. These
include regulation of the size of drilling, spacing or proration units and the density of wells
that may be drilled in those units, and the unitization or pooling of oil and gas properties. In
addition, state conservation laws which establish maximum rates of production from oil and gas
wells generally prohibit the venting or flaring of gas and impose certain requirements regarding
the ratability of production. The effect of these regulations may limit the amount of oil and gas
we can produce from our wells and may limit the number of wells or the locations at which we can
drill. The regulatory burden on the oil and gas industry increases our costs of doing business
and, consequently, affects our profitability.
Federal Regulation of Sales Prices and Transportation
The transportation and certain sales of natural gas in interstate commerce are heavily
regulated by agencies of the U.S. federal government and are affected by the availability, terms
and cost of transportation. In particular, the price and terms of access to pipeline
transportation are subject to extensive U.S. federal and state regulation. The Federal Energy
Regulatory Commission (FERC) is continually proposing and implementing new rules and regulations
affecting the natural gas industry. The stated purpose of many of these regulatory changes is to
promote competition among the various sectors of the natural gas industry. The ultimate impact of
the complex rules and regulations issued by FERC cannot be predicted. Some of FERCs proposals
may, however, adversely affect the availability and reliability of interruptible transportation
service on interstate pipelines. While our sales of crude oil, condensate and natural gas liquids
are not currently subject to FERC regulation, our ability to transport and sell such products is
dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC
regulation. Additional proposals and proceedings that might affect the natural gas industry are
considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot
predict when or if any such proposals might become effective and their effect, if any, on our
operations. Historically, the natural gas industry has been heavily regulated; therefore, there is
no assurance that the less stringent regulatory approach recently pursued by FERC, Congress and the
states will continue indefinitely into the future.
Federal Energy and Climate Change Legislation
In October 2008, as part of the Emergency Economic Stabilization Act, Congress included a new
tax credit for carbon capture and sequestration, including that achieved through enhanced oil
recovery, as further modified by the American Recovery and Reinvestment Act of 2009, passed in
February 2009. In future periods Congress may decide to revisit legislation introduced in prior
sessions to repeal existing incentives or impose new taxes on the exploration and production of
oil, gas and other minerals, and/or create new incentives for alternative energy sources. Congress
may also consider legislation to reduce emissions of carbon dioxide or other gases. If enacted,
such legislation could impose a tax or other economic penalty on the production of fossil fuels
that, when used, ultimately release CO2, and could reduce the demand for and uses of
oil, gas and other minerals and/or increase the costs incurred by the Company in its exploration
and production activities. At the same time, legislation to reduce
the emissions of carbon dioxide or other gases could also create economic incentives for
technologies and practices that reduce or avoid such emissions, including processes that sequester
CO2 in geologic formations such as oil and gas reservoirs.
21
Denbury Resources Inc.
Natural Gas Gathering Regulations
State regulation of natural gas gathering facilities generally includes various safety,
environmental and, in some circumstances, nondiscriminatory-take requirements. Although such
regulation has not generally been affirmatively applied by state agencies, natural gas gathering
may receive greater regulatory scrutiny in the future.
Federal, State or Indian Leases
Our operations on federal, state or Indian oil and gas leases are subject to numerous
restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to
certain on-site security regulations and other permits and authorizations issued by the Bureau of
Land Management, Minerals Management Service (MMS) and other agencies.
Environmental Regulations
Public interest in the protection of the environment has increased dramatically in recent
years. Our oil and natural gas production and saltwater disposal operations, and our processing,
handling and disposal of hazardous materials such as hydrocarbons and naturally occurring
radioactive materials are subject to stringent regulation. We could incur significant costs,
including cleanup costs resulting from a release of hazardous material, third-party claims for
property damage and personal injuries, fines and sanctions, as a result of any violations or
liabilities under environmental or other laws. Changes in or more stringent enforcement of
environmental laws could also result in additional operating costs and capital expenditures.
Various federal, state and local laws regulating the discharge of materials into the
environment, or otherwise relating to the protection of the environment, directly impact oil and
gas exploration, development and production operations, and consequently may impact the Companys
operations and costs. These regulations include, among others, (i) regulations by the EPA and
various state agencies regarding approved methods of disposal for certain hazardous and
nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability
Act, Federal Resource Conservation and Recovery Act and analogous state laws that regulate the
removal or remediation of previously disposed wastes (including wastes disposed of or released by
prior owners or operators), property contamination (including groundwater contamination), and
remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and
comparable state and local requirements, which may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from the operations of the Company or
could result in the imposition of economic penalties on the production of fossil fuels that, when
used, ultimately release CO2; (iv) the Oil Pollution Act of 1990, which contains
numerous requirements relating to the prevention of and response to oil spills into waters of the
United States; (v) the Resource Conservation and Recovery Act, which is the principal federal
statute governing the treatment, storage and disposal of hazardous wastes; and (vi) state
regulations and statutes governing the handling, treatment, storage and disposal of naturally
occurring radioactive material (NORM).
Management believes that we are in substantial compliance with applicable environmental laws
and regulations. Management does not currently anticipate that future compliance will have a
materially adverse effect on our consolidated financial position, results of operations or cash
flows.
Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated
Future Net Revenues
Internal Controls Over Reserve Estimates
We engage an independent petroleum engineering consulting firm to prepare our reserve
estimates and rely on their expertise to ensure that our reserve estimates are prepared in
compliance with SEC guidelines and with generally accepted petroleum engineering principles. The
person responsible for the preparation of the reserve report is a Senior Vice President at this
consulting firm; he is a Registered Professional Engineer in the State of Texas; he received a
Bachelor of Science degree in Petroleum Engineering at Texas A&M University in 1974; and he has in
excess of thirty-five years of experience in oil and gas reservoir studies and evaluations.
Denburys Vice
President Business Development is primarily responsible for overseeing the independent
petroleum engineering firm during the process. Our Vice President Business Development has a
Bachelor of Science degree in Petroleum Engineering and over 20 years of industry experience
working with petroleum reserve estimates. The Companys internal reserve engineering team consists
of qualified petroleum engineers who both provide data to the
22
Denbury Resources Inc.
independent petroleum engineer and
prepare interim reserve estimates. The internal reserve team reports directly to our Vice
President Business Development. In addition, the Companys Board of Directors Reserves
Committee, on behalf of the Board of Directors, oversees the qualifications, independence,
performance and hiring of the Companys independent petroleum engineering firm and reviews
the final report and subsequent reporting of the Companys oil and natural gas reserves. The
Chairman of the Reserves Committee is a Chartered Engineer of Great Britain and received his
Bachelor of Science degree in Chemical Engineering from the University of London in 1963.
Reserves Estimates
DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas, prepared
estimates of our net proved oil and natural gas reserves as of December 31, 2009, 2008 and 2007.
See the summary of DeGolyer and MacNaughtons report as of December 31, 2009 included as an exhibit
to this Form 10-K. Estimates of reserves as of year-end 2009 were prepared using an average price
equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month
within the 12-month period ended December 31, 2009, in accordance with revised guidelines of the
SEC, first applicable to reserves estimates prepared as of year-end 2009. Estimates of reserves as
of year-end 2007 and 2008 were prepared using constant prices and costs in accordance with previous
guidelines of the SEC, based on hydrocarbon prices received on a field-by-field basis as of
December 31st of each year. Reserve estimates do not include any value for probable or
possible reserves that may exist, nor do they include any value for undeveloped acreage. The
reserve estimates represent our net revenue interest in our properties. During 2009, we provided
oil and gas reserve estimates for 2008 to the United States Energy Information Agency, which was
substantially the same as the reserve estimates included in our Form 10-K for the year ended
December 31, 2008.
Our proved nonproducing reserves primarily relate to reserves that are to be recovered from
productive zones that are currently behind pipe. Since a majority of our properties are in areas
with multiple pay zones, these properties typically have both proved producing and proved
nonproducing reserves.
Proved undeveloped reserves associated with our CO2 tertiary operations
and our Heidelberg waterfloods account for virtually all of our proved undeveloped oil reserves.
We consider these reserves to be lower risk than other proved undeveloped reserves that require
drilling at locations offsetting existing production because all of these proved undeveloped
reserves are associated with secondary recovery or tertiary recovery operations in fields and
reservoirs that historically produced substantial volumes of oil under primary production. The
main reason these reserves are classified as undeveloped is because they require significant
additional capital associated with drilling/re-entering wells or additional facilities in order to
produce the reserves and/or are waiting for a production response to the water or CO2
injections. Virtually all of our proved undeveloped natural gas reserves are located in
our Selma Chalk play at Heidelberg and Sharon Fields at December 31, 2009. Our current plans
include drilling five additional wells in the Selma Chalk play during 2010, one at Heidelberg and
four at Sharon. Our proved undeveloped reserves decreased from December 31, 2008 to December 31,
2009 primarily due to the sale of our Barnett Shale natural gas assets during 2009.
23
Denbury Resources Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2009 |
|
2008 |
|
2007 |
|
Estimated Proved Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
192,879 |
|
|
|
179,126 |
|
|
|
134,978 |
|
Natural gas (MMcf) |
|
|
87,975 |
|
|
|
427,955 |
|
|
|
358,608 |
|
Oil equivalent (MBOE) |
|
|
207,542 |
|
|
|
250,452 |
|
|
|
194,746 |
|
Reserve Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed producing: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
93,833 |
|
|
|
73,347 |
|
|
|
73,457 |
|
Natural gas (MMcf) |
|
|
67,952 |
|
|
|
270,824 |
|
|
|
216,455 |
|
Oil equivalent (MBOE) |
|
|
105,158 |
|
|
|
118,484 |
|
|
|
109,533 |
|
Proved developed non-producing: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
22,359 |
|
|
|
23,399 |
|
|
|
23,549 |
|
Natural gas (MMcf) |
|
|
1,561 |
|
|
|
27,290 |
|
|
|
9,816 |
|
Oil equivalent (MBOE) |
|
|
22,619 |
|
|
|
27,947 |
|
|
|
25,185 |
|
Proved undeveloped: (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
76,687 |
|
|
|
82,380 |
|
|
|
37,972 |
|
Natural gas (MMcf) |
|
|
18,462 |
|
|
|
129,841 |
|
|
|
132,337 |
|
Oil equivalent (MBOE) |
|
|
79,764 |
|
|
|
104,020 |
|
|
|
60,028 |
|
Percentage of Total MBOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved producing |
|
|
51 |
% |
|
|
47 |
% |
|
|
56 |
% |
Proved non-producing |
|
|
11 |
% |
|
|
11 |
% |
|
|
13 |
% |
Proved undeveloped |
|
|
38 |
% |
|
|
42 |
% |
|
|
31 |
% |
Representative Oil and Natural Gas Prices:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil NYMEX |
|
$ |
61.18 |
|
|
$ |
44.60 |
|
|
$ |
95.98 |
|
Natural gas Henry Hub |
|
|
3.87 |
|
|
|
5.71 |
|
|
|
6.80 |
|
Present Values (thousands):(3) |
|
|
|
|
|
|
|
|
|
|
|
|
Discounted estimated future net cash flow before
income taxes (PV-10 Value)(4) |
|
$ |
3,075,459 |
|
|
$ |
1,926,855 |
|
|
$ |
5,385,123 |
|
Standardized measure of discounted estimated
future net cash flow after income taxes |
|
|
2,457,385 |
|
|
|
1,415,498 |
|
|
|
3,539,617 |
|
|
|
|
(1) |
|
Certain of our proved undeveloped reserves related to our tertiary properties have a
development period that extends beyond 5 years. In each of these tertiary properties, the majority
of the spending on facilities has been completed and a response to
CO2 injections has occurred.
Therefore, these tertiary oil reserves have been included as proved undeveloped, and will be
further classified as proved developed as the remaining field
development is completed. In addition, at December 31, 2009 a total of approximately 3.6
MMBOE of tertiary reserves at Brookhaven Field and McComb Field have been held as proved undeveloped for a period greater
than five years. It is expected that these reserves will become proved developed reserves during the next several years as the
remaining tertiary development at these two fields is completed.
|
|
(2) |
|
The reference prices for 2009 were based on the average first-day-of-the-month prices for each
month during 2009. The reference prices for 2008 and 2007 were based on respective year-end prices.
For all the periods presented, these representative prices were adjusted for differentials by field
to arrive at the appropriate net price Denbury receives. |
|
(3) |
|
Determined based on the average first day of the month prices for each month during 2009 and
year-end unescalated prices for 2008 and 2007, in all cases adjusted to prices received by field in
accordance with the guidelines of the FASC. |
|
(4) |
|
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10
Value is a pre-tax number and the Standardized Measure is an after-tax number. The information used
to calculate PV-10 Value is derived directly from data determined in accordance with FASC topic
932. The difference between these two amounts, the discounted estimated future income tax (in
thousands) was $618,074 at December 31, 2009, $511,357 at December 31, 2008 and $1,845,506 at
December 31, 2007. We believe that PV-10 Value is a useful supplemental disclosure to the
Standardized Measure because the Standardized Measure can be impacted by a companys unique tax
situation, and it is not practical to calculate the Standardized Measure on a property by property
basis. Because of this, PV-10 Value is a widely used measure within the industry and is commonly
used by securities analysts, banks and credit rating agencies to evaluate the estimated future net
cash flows from proved reserves on a comparative basis across companies or specific properties.
PV-10 Value is commonly used by us and others in our industry to evaluate properties that are
bought and sold and to assess the potential return on investment in our oil and gas properties.
PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be
considered in isolation or as a substitute for
the Standardized Measure. Our PV-10 Value and the Standardized Measure do not purport to represent
the fair value of our oil and natural gas reserves. See Note 16 to our Consolidated Financial
Statements for additional disclosures about the Standardized Measure. |
24
Denbury Resources Inc.
There are numerous uncertainties inherent in estimating quantities of proved oil and
natural gas reserves and their values, including many factors beyond
our control. See Item 1A. Risk
Factors Estimating our reserves, production and future net cash flow is difficult to do with any
certainty. See also Note 16, Supplemental Oil and Natural Gas Disclosures, to the Consolidated
Financial Statements.
Item 1A. Risk Factors
Risks Related To Our Business
Our level of indebtedness may adversely affect operations and limit our growth.
General
If we are unable to generate sufficient cash flow or otherwise obtain funds necessary to make
required payments on our indebtedness or if we otherwise fail to comply with the various covenants
in such indebtedness, including covenants in our senior secured credit facilities, we would be in
default under our debt instruments. This default would permit the holders of such indebtedness to accelerate the maturity of
such indebtedness and could cause defaults under other indebtedness or result in our bankruptcy.
Our ability to meet our obligations will depend upon our future performance, which will be subject
to prevailing economic conditions, commodity prices, and to financial, business and other factors,
including factors beyond our control.
Denbury Stand-Alone
As of February 15, 2010, we had outstanding $525 million (principal amount) of 7.5%
subordinated notes, $426.4 million (principal amount) of 9.75% Senior Subordinated Notes, $1.0
billion of 8.25% Senior Subordinated Notes (held in escrow pending
completion of the Merger and tender of Encore notes), and $125 million of bank debt. At that time, we had
approximately $625 million available on our bank credit line. We currently have a bank borrowing
base of $900 million, with a commitment amount of $750 million. The borrowing base represents the
amount that can be borrowed from a credit standpoint, while the commitment amount is the amount the
banks have committed to fund pursuant to the terms of the credit agreement. The next semi-annual
redetermination of the borrowing base for our bank credit facility will be on April 1, 2010,
assuming the Merger is not completed. Our bank borrowing base is adjusted at the banks discretion
and is based in part upon external factors, such as commodity prices, over which we have no
control. If our then redetermined borrowing base is less than our outstanding borrowings under the
facility, we will be required to repay the deficit over a period of six months.
We
may incur additional indebtedness in the future under our bank credit
facility (which we anticipate being a $1.6 billion facility if the
Encore Merger closes), in
connection with our acquisition, development, exploitation and exploration of oil and natural gas
producing properties. Our projected 2010 capital expenditures, excluding acquisitions and capital
expenditures related to the Encore acquisition, are expected to be
between $150 million and $250
million higher than our projected 2010 cash flow from operations. Further, our cash flow from
operations is highly dependent on the prices that we receive for oil and natural gas. If oil and
natural gas prices again decrease, and remain at depressed levels for an extended period of time,
our degree of leverage could increase substantially. The level of our indebtedness could have
important consequences, including but not limited to the following:
|
|
|
a substantial portion of our cash flows from operations may be dedicated to
servicing our indebtedness and would not be available for other purposes; |
|
|
|
|
as a result of the discretionary nature of the setting of our bank borrowing base
and its being highly dependent on current commodity prices, if commodity prices were to
substantially decrease, our banks could reduce our borrowing base so that we could not borrow
additional funds or to a level below our outstanding debt that would require us to
repay any deficit (between the borrowing base and the outstanding
bank debt) over a four
month period; |
|
|
|
|
our business may not generate sufficient cash flow from operations to enable us to
continue to meet our obligations under our indebtedness; |
|
|
|
|
our level of indebtedness may impair our ability to obtain additional financing in
the future for working capital, capital expenditures, acquisitions or general corporate
and other purposes; |
25
Denbury Resources Inc.
|
|
|
our interest expense may increase in the event of increases in interest rates,
because certain of our borrowings are at variable rates of interest; |
|
|
|
|
our vulnerability to general adverse economic and industry conditions may be greater
as a result of our level of indebtedness, and increases in interest rates thereon,
potentially restricting us from making acquisitions, introducing new technologies or
exploiting business opportunities; |
|
|
|
|
our ability to borrow additional funds, dispose of assets, pay dividends and make
certain investments may be limited by the covenants contained in the agreements
governing our outstanding indebtedness limit; and |
|
|
|
|
our debt covenants may also affect our flexibility in planning for, and reacting to,
changes in the economy and in our industry. Our failure to comply with such covenants
could result in an event of default under such debt instruments which, if not cured or
waived, could have a material adverse effect on us. |
Combined Company Post Denbury/Encore Merger
Denbury will be more leveraged after the merger than it has been historically. Upon closing of
the merger and the revolving credit facility contemplated by the merger agreement, we will have
$1.975 billion of revolving credit facilities. Borrowings under the newly committed credit facility
combined with Denburys existing debt, including the $1 billion of 8.25% Senior Subordinated Notes
due 2020 issued in February 2010, are expected to be
approximately $3.6 billion of total pro forma
combined long-term debt after the completion of the merger. This level of indebtedness could result
in Denbury having difficulty accessing capital markets or raising capital on favorable terms and
Denburys financial results could be negatively affected by its inability to raise capital or
because of the cost of such capital.
Our substantial debt following the merger and the related financing could have important
consequences for us. For example, it could:
|
|
|
increase our vulnerability to general adverse economic and industry conditions; |
|
|
|
|
limit our ability to fund future working capital and capital expenditures, to engage
in future acquisitions or development activities, or to otherwise realize the value of
our assets and opportunities fully because of the need to dedicate a substantial
portion of our cash flow from operations to payments on our debt or to comply with any
restrictive terms of our debt; |
|
|
|
|
limit our flexibility in planning for, or reacting to, changes in the industry in
which we operate; or |
|
|
|
|
place us at a competitive disadvantage as compared to our competitors that have less
debt. |
Realization of any of these factors could adversely affect our financial condition. In
addition, although we and Encore both have hedges in place for 2010 and 2011, these hedges have
varying floors and ceilings and will only partially protect the combined companys cash flow. A
decline in commodity prices may require that we reduce our planned capital expenditures, which may
have a corresponding negative effect on our anticipated production growth.
Our production will decline if our access to sufficient amounts of carbon dioxide is limited.
Our long-term growth strategy is focused on our CO2 tertiary recovery operations.
The crude oil production from our tertiary recovery projects depends on having access to sufficient
amounts of carbon dioxide. Our ability to produce this oil would be hindered if our supply of
carbon dioxide were limited due to problems with our current CO2 producing wells and
facilities, including compression equipment, or catastrophic pipeline failure. Our anticipated
future crude oil production is also dependent on our ability to increase the production volumes of
CO2 and inject adequate amounts of CO2 into the proper formation and area
within each oil field. The production of crude oil from tertiary operations is highly dependent on
the timing, volumes and location of the CO2 injections. If our crude oil production
were to decline, it could have a material adverse effect on our financial condition, results of
operations and cash flows. Additionally, the production of crude oil from our planned expansion of
tertiary operations into the Rocky Mountain region depends on having access to sufficient amounts
of CO2 in this region.
The ability to produce this oil and execute this growth strategy would be hindered if we were
unable to obtain necessary CO2 volumes in the Rocky Mountain region at a cost that is
economically viable.
26
Denbury Resources Inc.
Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices
could adversely affect our financial results.
Our future financial condition, results of operations and the carrying value of our oil and
natural gas properties depend primarily upon the prices we receive for our oil and natural gas
production. Oil and natural gas prices historically have been volatile, have been particularly
volatile over the last 18 months, and may continue to be volatile in the future, especially given
current world geopolitical conditions. As a result of the low oil and natural gas prices at
December 31, 2008, we recorded a $226.0 million full cost ceiling test write-down. Subsequent to
December 31, 2008, oil and natural gas prices have continued their volatility, with NYMEX oil
prices per barrel increasing 78% between year-end 2008 and year-end 2009, and NYMEX natural gas
prices per MMBtu decreasing by 3% during the year. Future decreases in commodity prices could
require us to record additional full cost ceiling test write-downs. The amount of any future
write-down is difficult to predict and will depend upon the oil and natural gas prices at the end
of each period, the incremental proved reserves that might be added during each period and
additional capital spent.
Our cash flow from operations is highly dependent on the prices that we receive for oil and
natural gas. This price volatility also affects the amount of our cash flow available for capital
expenditures and our ability to borrow money or raise additional capital. The amount we can borrow
or have outstanding under our bank credit facility is subject to semi-annual redeterminations. Oil
prices are likely to affect us more than natural gas prices because approximately 93% of our
December 31, 2009 proved reserves are oil, prior to closing the pending Encore acquisition, with
oil being an even larger percentage of our future potential reserves and projects due to our focus
on tertiary operations.
As part of the planned Encore acquisition (see Item 1 Business Definitive Merger
Agreement to Acquire Encore Acquisition Company), we have announced plans to sell a portion of the
acquired assets in order to reduce indebtedness incurred to finance the acquisition. If commodity
prices were to decrease from price levels that existed at the time we entered into the merger
agreement with Encore, such assets may be sold for amounts less than we effectively paid for those
assets and possibly for less than we believe are the long-term value of the properties. However,
if we choose to reduce the number of assets we sell to avoid asset sales for amounts below our
valuations, or if we are unable to obtain a reasonable price for these assets, we would remain more
highly leveraged than our historical leverage levels, increasing the risk of adverse financial
consequences because of our higher debt levels.
The prices for oil and natural gas are subject to a variety of additional factors that are
beyond our control. These factors include:
|
|
|
the level of consumer demand for oil and natural gas; |
|
|
|
|
the domestic and foreign supply of oil and natural gas; |
|
|
|
|
the ability of the members of the Organization of Petroleum Exporting Countries
(OPEC) to agree to and maintain oil price and production controls; |
|
|
|
|
the price of foreign oil and natural gas; |
|
|
|
|
domestic governmental regulations and taxes; |
|
|
|
|
the price and availability of alternative fuel sources; |
|
|
|
|
weather conditions, including hurricanes and tropical storms in and around the Gulf
of Mexico; |
|
|
|
|
market uncertainty; |
|
|
|
|
political conditions in oil and natural gas producing regions, including the Middle
East; and |
|
|
|
|
worldwide economic conditions. |
These factors and the volatility of the energy markets generally make it extremely difficult
to predict future oil and natural gas price movements. Also, oil and natural gas prices do not
necessarily move in tandem. Declines in oil and natural gas prices would not only reduce revenue,
but could reduce the amount of oil and natural gas that we can produce economically and, as a
result, could have a material adverse effect upon our financial condition, results of operations,
oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the
oil and
27
Denbury Resources Inc.
natural gas industry experiences significant price declines, we may, among other things, be
unable to meet our financial obligations or make planned expenditures.
Since the end of 1998, oil prices have gone from near historic low prices to historic highs.
At the end of 1998, NYMEX oil prices were at historic lows of approximately $12.00 per Bbl, but
have generally increased since that time, albeit with fluctuations. For 2008, NYMEX
oil prices increases throughout the first six months, averaging approximately $111.03 per Bbl for
the first six months of 2008. During the last half of 2008, oil prices declined substantially,
ending the year at a NYMEX price of $44.60 per Bbl. Oil prices again increased through 2009, ending
the year at a NYMEX price of $79.36 per barrel. We have oil commodity derivative contracts in
place covering approximately 30,000 Bbls/d during 2010 and 25,000 Bbls/d during 2011 (please refer
to Note 10 to the Consolidated Financial Statements for further details regarding our commodity
derivative contracts). We currently do not have any oil or natural gas commodity derivative
contracts in place for subsequent years, and therefore oil prices could decline to a level that
makes our tertiary projects uneconomic. If that were to happen, we may decide to suspend future
expansion projects, and if prices were to drop below the cash break-even point for an extended
period of time, we may decide to shut-in existing production, either of which would have a material
adverse effect on our operations. Since operating costs do not decrease as quickly as
commodity prices, it is difficult to determine a precise break-even point for our tertiary
projects. Based on prior history, we estimate our economic break-even
(before corporate overhead
and expenses on these projects at current oil prices) occurs at per
barrel dollar costs in the range of the
mid-thirties, depending on the specific field and area.
The prices we receive for our crude oil do not always correlate with NYMEX prices. Our NYMEX
differentials over the last few years have ranged from a low of approximately $1.50 per Bbl to a
high of almost $10.00 per Bbl. These variances have been due to various factors and are difficult
to forecast or anticipate but have a direct impact on the net oil price we receive.
Natural gas prices have also experienced volatility during the last few years. During 1999,
natural gas prices averaged approximately $2.35 per Mcf and, like
crude oil prices, have generally trended
upward since that time, although with significant fluctuations along the way. NYMEX natural gas
prices averaged $7.09 per MMBtu during 2007, $8.89 per MMBtu during 2008, $4.16 per MMBtu during
2009, and ended 2009 at $5.57 per MMBtu.
The recent financial crisis may have lasting effects on our liquidity, business and financial
condition that we cannot predict.
Liquidity is essential to our business. Our liquidity could be substantially negatively
affected by an inability to obtain capital in the long-term or short-term debt capital markets or
equity capital markets or an inability to access bank financing. A prolonged credit crisis and
related turmoil in the global financial system would likely materially affect our liquidity,
business and our financial condition. The economic situation could also adversely affect the
collectability of our trade receivables or performance by our suppliers and cause our commodity
hedging arrangements to be ineffective if our counterparties are unable to perform their
obligations or seek bankruptcy protection. Additionally, the recent economic situation and current
economic condition could lead to reduced demand for oil and gas, or lower prices for oil and gas,
or both, which could have a negative impact on our revenues.
Product price derivative contracts may expose us to potential financial loss.
To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently and
may in the future enter into derivative contracts in order to economically hedge a portion of our
oil and natural gas production. Derivative contracts expose us to risk of financial loss in some
circumstances, including when:
|
|
|
production is less than expected; |
|
|
|
|
the counter-party to the derivative contract defaults on its contract obligations;
or |
|
|
|
|
there is a change in the expected differential between the underlying price in the
hedging agreement and actual prices received. |
In addition, these derivative contracts may limit the benefit we would receive from increases
in the prices for oil and natural gas. Information as to these activities is set forth under
Managements Discussion and Analysis of
28
Denbury Resources Inc.
Financial Condition and Results of Operations Market Risk Management, and in Note 10,
Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements.
Our future performance depends upon our ability to find or acquire additional oil and natural gas
reserves that are economically recoverable.
Unless we can successfully replace the reserves that we produce, our reserves will decline,
resulting eventually in a decrease in oil and natural gas production and lower revenues and cash
flows from operations. We have historically replaced reserves through both acquisitions and
internal organic growth activities. In the future, we may not be able to continue to replace
reserves at acceptable costs. The business of exploring for, developing or acquiring reserves is
capital intensive. We may not be able to make the necessary capital investment to maintain or
expand our oil and natural gas reserves if our cash flows from operations are reduced, due to lower
oil or natural gas prices or otherwise, or if external sources of capital become limited or
unavailable. Further, the process of using CO2 for tertiary recovery and the related
infrastructure requires significant capital investment, up to four or five years prior to any
resulting production and cash flows from these projects, heightening potential capital constraints.
If we do not continue to make significant capital expenditures, or if outside capital resources
become limited, we may not be able to maintain our growth rate or meet expectations. In addition,
certain of our operating activities are subject to numerous risks, including the risk that no
commercially productive oil or natural gas reserves will be produced.
During the last few years, we have acquired several fields at a significant cost because we
believe that they have significant additional potential through tertiary flooding and we paid a
premium price for these properties based on that assumption. In addition, we plan to continue
acquiring other old oil fields that we believe are tertiary flood candidates, likely at a premium
price. We are investing significant amounts of capital as part of this strategy. If we are unable
to successfully develop the potential oil in these acquired fields, it would negatively affect the
return on our investment on these acquisitions and could severely reduce our ability to obtain
additional capital for the future, fund future acquisitions, and negatively affect our financial
results to a significant degree.
We face competition from other oil and natural gas companies in all aspects of our business,
including acquisition of producing properties and oil and gas leases. Many of our competitors have
substantially larger financial and other resources. Other factors that affect our ability to
acquire producing properties include available funds, available information about prospective
properties and our standards established for minimum projected return on investment.
Oil and natural gas drilling and producing operations involve various risks.
Drilling activities are subject to many risks, including the risk that no commercially
productive reservoirs will be discovered. There can be no assurance that new wells drilled by us
will be productive or that we will recover all or any portion of our investment in such wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also
from wells that are productive but do not produce sufficient net reserves to return a profit after
deducting drilling, operating and other costs. The seismic data and other technologies used by us
do not provide conclusive knowledge, prior to drilling a well, that oil or natural gas is present
or may be produced economically. The cost of drilling, completing and operating a well is often
uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling
operations may be curtailed, delayed or canceled as a result of numerous factors, including:
|
|
|
unexpected drilling conditions; |
|
|
|
|
title problems; |
|
|
|
|
pressure or irregularities in formations; |
|
|
|
|
equipment failures or accidents; |
|
|
|
|
adverse weather conditions, including hurricanes and tropical storms in and around
the Gulf of Mexico that can damage oil and natural gas facilities and delivering
systems and disrupt operations; |
|
|
|
|
compliance with environmental and other governmental requirements; and |
29
Denbury Resources Inc.
|
|
|
cost of, or shortages or delays in the availability of, drilling rigs, equipment and
services. |
Our operations are subject to all the risks normally incident to the operation and development
of oil and natural gas properties and the drilling of oil and natural gas wells, including
encountering well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal
pressures, uncontrollable flows of oil, natural gas, brine or well fluids, release of contaminants
into the environment and other environmental hazards and risks.
The nature of these risks is such that some liabilities could exceed our insurance policy
limits, or, as in the case of environmental fines and penalties, cannot be insured. We could incur
significant costs, related to these risks that could have a material adverse effect on our results
of operations, financial condition and cash flows.
Our CO2 tertiary recovery projects require a significant amount of electricity to
operate the facilities. If these costs were to increase significantly, it could have an adverse
effect upon the profitability of these operations.
We depend on our key personnel.
We believe our continued success depends on the collective abilities and efforts of our senior
management. The loss of one or more key personnel could have a material adverse effect on our
results of operations. We do not have any employment agreements and do not maintain any key man
life insurance policies. Additionally, if we are unable to find, hire and retain needed key
personnel in the future, our results of operations could be materially and adversely affected.
Upon consummation of the planned Encore acquisition (see Item 1 Business Definitive
Merger Agreement to Acquire Encore Acquisition Company), we will require more personnel to
properly manage the acquired assets. While we hope to retain existing Encore personnel in
sufficient numbers to meet these needs, there is no assurance that they will agree to continued
employment by a new company or be willing to relocate in order to accommodate such an employment
change. In that situation, if we are unable to attract personnel in the open marketplace to meet
these needs, the lack of personnel could have a material adverse impact on our operations and
financial results. Further, without a proper integration of the two companies, we may not operate
at our highest levels of efficiency, which also could materially adversely affect our operations
and financial results.
Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and
adversely affect results of operations.
The demand for qualified and experienced field personnel to drill wells and conduct field
operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas
industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing
periodic shortages. During periods of high oil and gas prices, we have experienced shortages of
equipment used in our tertiary facilities, drilling rigs and other equipment, as demand for rigs
and equipment has increased along with higher commodity prices. Higher oil and natural gas prices
generally stimulate increased demand and result in increased prices for drilling rigs, crews and
associated supplies, oilfield equipment and services and personnel in our exploration and
production operations. These types of shortages or price increases could significantly decrease
our profit margin, cash flow and operating results and/or restrict or delay our ability to drill
those wells and conduct those operations that we currently have planned and budgeted, causing us to
miss our forecasts and projections.
The loss of more than one of our large oil and natural gas purchasers could have a material adverse
effect on our operations.
For the year ended December 31, 2009, two purchasers each accounted for more than 10% of our
oil and natural gas revenues and in the aggregate, for 73% of these revenues. We would not expect
the loss of any single purchaser to have a material adverse effect upon our operations. However,
the loss of a large single purchaser could potentially reduce the competition for our oil and
natural gas production, which in turn could negatively impact the prices we receive.
30
Denbury Resources Inc.
Estimating our reserves, production and future net cash flows is difficult to do with any
certainty.
Estimating quantities of proved oil and natural gas reserves is a complex process. It
requires interpretations of available technical data and various assumptions, including assumptions
relating to economic factors, such as future commodity prices, production costs, severance and
excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of
governmental regulation. There are numerous uncertainties about when a property may have proved
reserves as compared to potential or probable reserves, particularly relating to our tertiary
recovery operations. Forecasting the amount of oil reserves recoverable from tertiary operations
and the production rates anticipated there from requires estimates, one of the most significant
being the oil recovery factor. Actual results most likely will vary from our estimates. Also, the
use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily
represent the most appropriate discount factor, given actual interest rates and risks to which our
business or the oil and natural gas industry in general are subject. Any significant inaccuracies
in these interpretations or assumptions or changes of conditions could result in a reduction of the
quantities and net present value of our reserves.
Quantities of proved reserves are estimated based on economic conditions, including oil and
natural gas prices in existence at the date of assessment. Our reserves and future cash flows may
be subject to revisions based upon changes in economic conditions, including oil and natural gas
prices, as well as due to production results, results of future development, operating and
development costs and other factors. Downward revisions of our reserves could have an adverse
effect on our financial condition, operating results and cash flows.
The reserve data included in documents incorporated by reference represent only estimates.
Estimates of reserves as of year-end 2009 were prepared using an average price equal to the
unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first
day of each month within the 12-month period ended December 31, 2009, in accordance with revised
guidelines of the Securities and Exchange Commission applicable to reserves estimates as of
year-end 2009. Estimates of reserves as of year-end 2007 and 2008 were prepared using constant
prices and costs in accordance with previous guidelines of the Securities and Exchange Commission
based on hydrocarbon prices received on a field-by-field basis as of December 31st of
each year. Reserve estimates do not include any value for probable or possible reserves that may
exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our
net revenue interest in our properties. Actual future prices and costs may be materially higher or
lower than the prices and cost as of the date of the estimate.
As of December 31, 2009, approximately 38% of our estimated proved reserves were undeveloped.
Recovery of undeveloped reserves requires significant capital expenditures and may require
successful drilling operations. The reserve data assumes that we can and will make these
expenditures and conduct these operations successfully, but these assumptions may not be accurate,
and this may not occur.
We are subject to complex federal, state and local laws and regulations, including environmental
laws, which could adversely affect our business.
Exploration for and development, exploitation, production and sale of oil and natural gas in
the United States are subject to extensive federal, state and local laws and regulations, including
complex tax laws and environmental laws and regulations. Existing laws or regulations, as
currently interpreted or reinterpreted in the future, or future laws, regulations or incremental
taxes and fees, could harm our business, results of operations and financial condition. We may be
required to make large expenditures to comply with environmental and other governmental
regulations.
It is possible that new taxes on our industry could be implemented and/or tax benefits could
be eliminated or reduced, reducing our profitability and available cash flow. In addition to the
short-term negative impact on our financial results, such additional burdens, if enacted, would
reduce our funds available for reinvestment and thus ultimately reduce our growth and future oil
and natural gas production.
Matters subject to regulation include oil and gas production and saltwater disposal operations
and our processing, handling and disposal of hazardous materials, such as hydrocarbons and
naturally occurring radioactive materials, discharge permits for drilling operations, spacing of
wells, environmental protection and taxation. We could incur significant costs as a result of
violations of or liabilities under environmental or other laws, including third-party claims for
personal injuries and property damage, reclamation costs, remediation and clean-up costs resulting
from oil spills and discharges of hazardous materials, fines and sanctions, and other environmental
damages.
31
Denbury Resources Inc.
Enactment
of legislative or regulatory proposals under consideration could
negatively affect our business.
Numerous
legislative and regulatory proposals affecting the oil and gas
industry have been proposed or are under consideration by the current
federal administration, Congress and various federal agencies. Among
these proposals are: (1) climate change legislation introduced in
Congress, Environmental Protection Agency regulations, carbon
emission cap-and-trade regimens, and related proposals,
none of which have been adopted in final form; (2) proposals
contained in the Presidents budget, along with legislation
introduced in Congress, none of which have been enacted by both
houses of Congress, to repeal various tax deductions available to oil
and gas producers, such as the current tax deduction for intangible
drilling and development costs and the current deduction for qualified
tertiary injectant expenses, which if eliminated could raise the cost
of energy production, reduce energy investment and affect the
economics of oil and gas exploration and production activities; and
(3) legislation being considered by Congress that would subject the
process of hydraulic fracturing to federal regulation under the Safe
Drinking Water Act, which could affect Company operations, their
effectiveness, and the costs thereof. Generally, any such future laws
and regulations could result in increased costs or additional
operating restrictions, and could have an effect on demand for oil
and gas or prices at which it can be sold. Until any such
legislation or regulations are enacted or adopted, it is not
possible to gauge their impact on our future operations or our
results of operations and financial condition.
Risks Relating to the Merger
Business uncertainties and contractual restrictions while the merger is pending may have an adverse
effect on Encore or Denbury.
Uncertainty about the effect of the merger on employees, suppliers, partners, regulators and
customers may have an adverse effect on Encore. These uncertainties may impair Encores ability to
attract, retain and motivate key personnel until the merger is consummated and could cause
suppliers, customers and others that deal with Encore to defer purchases or other decisions
concerning Encore or seek to change existing business relationships with Encore.
Failure to complete the merger or delays in completing the merger could negatively affect our stock
prices and future business and operations.
If the merger is not completed for any reason, we may be subject to a number of risks,
including the following:
|
|
|
we will not realize the benefits expected from the merger, including a potentially
enhanced financial and competitive position; |
|
|
|
|
the current market price of our common stock may reflect a market assumption that
the merger will occur and a failure to complete the merger could result in a negative
perception by the stock market generally and a resulting decline in the market price of
our common stock; |
|
|
|
|
certain costs relating to the merger, including certain investment banking,
financing, legal and accounting fees and expenses, must be paid even if the merger is
not completed, and we may be required to pay substantial fees to the other if the
merger agreement is terminated under specified circumstances; |
|
|
|
|
there may be substantial disruption to our business and distraction of our
management and employees from day-to-day operations because matters related to the
merger (including integration planning) may require substantial commitments of time and
resources, which could otherwise have been devoted to other opportunities that could
have been beneficial to us; and |
|
|
|
|
delays in completing the merger could exacerbate uncertainties concerning the effect
of the merger, which may have an adverse effect on the business following the merger
and could defer or detract from the realization of the benefits expected to result from
the merger. |
We are subject to financial risks if we fail to complete the merger under certain circumstances.
If we terminate the merger agreement because Denbury stockholders do not adopt the merger
agreement, we will be required to pay Encore $60 million, and in certain cases $120 million. If we
terminate the merger agreement because we are unable to obtain the financing necessary to
consummate the merger, we will be required to pay to Encore a $300 million termination fee.
Further, there is a limited exception that would allow our board of directors to withdraw or change
its recommendation to holders of our common stock that they vote in favor of the adoption of the
merger agreement. Although our board of directors is permitted to take these actions if it
determines in good faith that these actions are likely to be required to comply with its fiduciary
duties, doing so in specified situations could entitle Encore to terminate the merger agreement and
to be paid a termination fee of $120 million.
Risks relating to the combined company after the merger
The combined company may experience an impairment of its goodwill.
We expect a significant increase to our existing goodwill in connection with consummation of
the merger and the allocation of the purchase price thereto. We test goodwill for impairment
annually during the fourth quarter, or between annual tests if an event occurs or circumstances
change that may indicate the fair value of a reporting unit is less than the carrying amount. The
need to test for impairment can be based on several indicators, including but not limited to a
significant reduction in the price of oil or natural gas, a full cost ceiling write-down of oil and
natural gas properties, unfavorable revisions to oil and natural gas reserves and significant
changes in the expected timing of production, or changes in the regulatory environment.
Fair value calculated for the purpose of testing for impairment of our goodwill is estimated
using the expected present value of future cash flows method and comparative market prices when
appropriate. A significant amount of judgment is involved in performing these fair value estimates
for goodwill since the results are based on estimated
32
Denbury Resources Inc.
future cash flows and assumptions related thereto. Significant assumptions include estimates
of future oil and natural gas prices, projections of estimated quantities of oil and natural gas
reserves, estimates of future rates of production, timing and amount of future development and
operating costs, estimated availability and cost of CO2, projected recovery factors of
reserves and risk-adjusted discount rates. We base our fair value estimates on projected financial
information which we believe to be reasonable. However, actual results may differ from those
projections.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
See Item 1. Business Oil and Natural Gas Operations. We also have various operating
leases for rental of office space, office and field equipment, and vehicles. See Off-Balance
Sheet Agreements Commitments and Obligations in Managements Discussion and Analysis of
Financial Condition and Results of Operations, and Note 12, Commitments and Contingencies, to
the Consolidated Financial Statements for the future minimum rental payments. Such information is
incorporated herein by reference.
Item 3. Legal Proceedings
In connection with our proposed acquisition of Encore (the Merger), three shareholder
lawsuits styled as class actions have been filed against Encore and its board of directors. The
lawsuits are entitled Sanjay Israni, Individually and On Behalf of All Others Similarly Situated
vs. Encore Acquisition Company et al. (filed November 4, 2009 in the District Court of Tarrant
County, Texas), Teamsters Allied Benefit Funds, Individually and On Behalf of All Others Similarly
Situated vs. Encore Acquisition Company et al. (filed November 5, 2009 in the Court of Chancery in
the State of Delaware) and Thomas W. Scott, Jr., individually and on behalf of all others similarly
situated v. Encore Acquisition Company et al. (filed November 6, 2009 in the District Court of
Tarrant County, Texas). The Teamsters and Scott lawsuits also name Denbury as a defendant. The
complaints generally allege that (1) Encores directors breached their fiduciary duties in
negotiating and approving the Merger and by administering a sale process that failed to maximize
shareholder value and (2) Encore, and, in the case of the Teamsters and Scott complaints, Denbury
aided and abetted Encores directors in breaching their fiduciary duties. The Teamsters complaint
also alleges that Encores directors and executives stand to receive substantial financial benefits
if the transaction is consummated on its current terms. The plaintiffs in these lawsuits seek,
among other things, to enjoin the Merger and to rescind the Merger Agreement. Encore and Denbury
have entered into a Memorandum of Understanding with the plaintiffs in these lawsuits agreeing in
principle to the settlement of the lawsuits based upon inclusion in our joint proxy
statement/prospectus dated February 5, 2010, mailed to
shareholders of Denbury and Encore in connection with their
respective shareholder meetings to approve the Merger, of additional disclosures requested by the plaintiffs,
and agreeing that the parties to the lawsuits will use best efforts to enter into a definitive
settlement agreement, which has not yet occurred pending completion
of limited discovery, and to seek court approval for the settlement which would be binding on all
Encore shareholders who do not opt-out of the settlement.
A shareholder suit regarding a compensation matter brought as a derivative action on behalf of
Denbury against Denburys board of directors, entitled Harbor Police Retirement System v. Gareth
Roberts, et al, in the District Court of Dallas County, Texas, was amended during January 2010 to
generally allege breach of the Denbury directors fiduciary duties based upon the further
allegation that the directors approved an unreasonably high purchase
price in the Merger. At a hearing held on March 1, 2010, the Court
granted plaintiffs motion for leave to amend its petition to
add putative class action claims, including disclosure claims related
to the joint proxy statement/prospectus. The plaintiff seeks monetary
damages and equitable relief, which in the latter case includes
enjoining the Denbury shareholders meeting. The Court, however,
abated these merger and disclosure claims in favor of the
Israni and Scott complaints in Tarrant County, Texas
(referenced above), and in light of such abatement the Court denied
as moot plaintiffs motion to enjoin the Denbury shareholders
meeting. Denbury
believes that its directors have a valid defense to all claims against them, and that the other
allegations in this suit are without merit. Denbury and its directors intend to defend this
litigation vigorously.
33
Denbury Resources Inc.
We are involved in various other lawsuits, claims and regulatory proceedings incidental to our
businesses. While we currently believe that the ultimate outcome of these proceedings,
individually and in the aggregate, will not have a material adverse effect on our financial
position or overall trends in results of operations or cash flows, litigation is subject to
inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a
material adverse impact on our net income in the period in which the ruling occurs. We provide
accruals for litigation and claims if we determine that we may have a range of legal exposure that
would require accrual.
Item 4.
Reserved
34
Denbury Resources Inc.
PART II
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
Common Stock Trading Summary
The following table summarizes the high and low reported sales prices on days in which there
were trades of Denburys common stock on the New York Stock Exchange (NYSE), for each quarterly
period for the last two fiscal years. As of February 3, 2010, based on information from the
Companys transfer agent, American Stock Transfer and Trust Company, the number of holders of
record of Denburys common stock was 1,341. On February 26, 2010, the last reported sale price of
Denburys common stock, as reported on the NYSE, was $14.08 per share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
High |
|
Low |
|
High |
|
Low |
First Quarter |
|
$ |
17.520 |
|
|
$ |
9.610 |
|
|
$ |
33.640 |
|
|
$ |
21.760 |
|
Second Quarter |
|
|
18.840 |
|
|
|
13.390 |
|
|
|
40.320 |
|
|
|
27.280 |
|
Third Quarter |
|
|
17.780 |
|
|
|
12.450 |
|
|
|
37.240 |
|
|
|
16.110 |
|
Fourth Quarter |
|
|
17.390 |
|
|
|
12.510 |
|
|
|
18.860 |
|
|
|
5.590 |
|
We have never paid any dividends on our common stock, and we currently do not anticipate
paying any dividends in the foreseeable future. Also, we are restricted from declaring or paying
any cash dividends on our common stock under our bank loan agreement. On December 18, 2009, we
issued 11,620,000 shares of Denbury common stock as part of the consideration to a Houston based
privately-owned company, to purchase oil and gas assets in the Conroe Field. Under a registration
rights agreement signed at the closing of this acquisition, Denbury provided the designees with
resale registration rights covering the shares issued in the transaction. The designees have
agreed, with limited exceptions, not to sell any of these securities until the earlier of the
closing of the acquisition of Encore, the termination of the merger agreement to acquire Encore, or
in certain cases June 28, 2010. No other unregistered securities were sold by the Company during
2009.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(d) Maximum |
|
|
|
|
|
|
|
|
|
|
(c) Total Number of |
|
Number |
|
|
(a) Total |
|
|
|
|
|
Shares Purchased |
|
of Shares that May |
|
|
Number of |
|
(b) Average |
|
as Part of Publicly |
|
Yet Be Purchased |
|
|
Shares |
|
Price Paid |
|
Announced Plans or |
|
Under the Plan Or |
Period |
|
Purchased |
|
per Share |
|
Programs |
|
Programs |
October 1 through
31, 2009 |
|
|
3,475 |
|
|
$ |
13.95 |
|
|
|
|
|
|
|
|
|
November 1 through
30, 2009 |
|
|
218 |
|
|
|
14.60 |
|
|
|
|
|
|
|
|
|
December 1 through
31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3,693 |
|
|
|
13.99 |
|
|
|
|
|
|
|
|
|
These shares were purchased from employees of Denbury who delivered shares to the company to
satisfy their minimum tax withholding requirements related to the vesting of restricted shares.
35
Denbury Resources Inc.
Share Performance Graph
The following Performance Graph and related information shall not be deemed soliciting
material or to be filed with the Securities and Exchange Commission, nor shall such information
be incorporated by reference into any future filings under the Securities Act of 1933 or Securities
Exchange Act of 1934, each as amended, except to the extent that the Company specifically
incorporates it by reference into such filing.
The following graph illustrates changes over the five-year period ended December 31, 2009, in
cumulative total stockholder return on our common stock as measured against the cumulative total
return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index. The results
assume $100 was invested on December 31, 2004, and that dividends were reinvested.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2004 |
|
2005 |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
Denbury Resources Inc. |
|
|
100.00 |
|
|
|
165.97 |
|
|
|
202.48 |
|
|
|
433.52 |
|
|
|
159.13 |
|
|
|
215.66 |
|
|
S&P 500 |
|
|
100.00 |
|
|
|
104.91 |
|
|
|
121.48 |
|
|
|
128.16 |
|
|
|
80.74 |
|
|
|
102.11 |
|
|
Dow Jones US Exploration & Production |
|
|
100.00 |
|
|
|
165.32 |
|
|
|
174.20 |
|
|
|
250.27 |
|
|
|
149.86 |
|
|
|
210.65 |
|
36
Denbury Resources Inc.
Item 6. Selected Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
In thousands, unless otherwise noted |
|
2009 |
|
2008 |
|
2007 |
|
2006 (1) |
|
2005 |
Consolidated Statements of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
882,493 |
|
|
$ |
1,365,702 |
|
|
$ |
973,060 |
|
|
$ |
731,536 |
|
|
$ |
560,392 |
|
Net income (loss)(2) |
|
|
(75,156 |
) |
|
|
388,396 |
|
|
|
253,147 |
|
|
|
202,457 |
|
|
|
166,471 |
|
Net income (loss) per common share:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
(0.30 |
) |
|
|
1.59 |
|
|
|
1.05 |
|
|
|
0.87 |
|
|
|
0.74 |
|
Diluted |
|
|
(0.30 |
) |
|
|
1.54 |
|
|
|
1.00 |
|
|
|
0.82 |
|
|
|
0.70 |
|
Weighted average number of common shares
outstanding:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
246,917 |
|
|
|
243,935 |
|
|
|
240,065 |
|
|
|
233,101 |
|
|
|
223,485 |
|
Diluted |
|
|
246,917 |
|
|
|
252,530 |
|
|
|
252,101 |
|
|
|
247,547 |
|
|
|
239,267 |
|
Consolidated Statements of Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used by): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
530,599 |
|
|
$ |
774,519 |
|
|
$ |
570,214 |
|
|
$ |
461,810 |
|
|
$ |
360,960 |
|
Investing activities(4) |
|
|
(969,714 |
) |
|
|
(994,659 |
) |
|
|
(762,513 |
) |
|
|
(856,627 |
) |
|
|
(383,687 |
) |
Financing activities(5) |
|
|
442,637 |
|
|
|
177,102 |
|
|
|
198,533 |
|
|
|
283,601 |
|
|
|
154,777 |
|
Production (daily): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
36,951 |
|
|
|
31,436 |
|
|
|
27,925 |
|
|
|
22,936 |
|
|
|
20,013 |
|
Natural gas (Mcf) |
|
|
68,086 |
|
|
|
89,442 |
|
|
|
97,141 |
|
|
|
83,075 |
|
|
|
58,696 |
|
BOE (6:1) |
|
|
48,299 |
|
|
|
46,343 |
|
|
|
44,115 |
|
|
|
36,782 |
|
|
|
29,795 |
|
Unit Sales Price
(excluding impact of derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
57.75 |
|
|
$ |
92.73 |
|
|
$ |
69.80 |
|
|
$ |
59.87 |
|
|
$ |
50.30 |
|
Natural gas (per Mcf) |
|
|
3.54 |
|
|
|
8.56 |
|
|
|
6.81 |
|
|
|
7.10 |
|
|
|
8.48 |
|
Unit Sales Price
(including impact of derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
68.63 |
|
|
$ |
90.04 |
|
|
$ |
68.84 |
|
|
$ |
59.23 |
|
|
$ |
50.30 |
|
Natural gas (per Mcf) |
|
|
3.54 |
|
|
|
7.74 |
|
|
|
7.66 |
|
|
|
7.10 |
|
|
|
7.70 |
|
Costs per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
18.50 |
|
|
$ |
18.13 |
|
|
$ |
14.34 |
|
|
$ |
12.46 |
|
|
$ |
9.98 |
|
Production taxes and marketing expenses |
|
|
2.41 |
|
|
|
3.76 |
|
|
|
3.05 |
|
|
|
2.71 |
|
|
|
2.54 |
|
General and administrative(6) |
|
|
6.59 |
|
|
|
3.56 |
|
|
|
3.04 |
|
|
|
3.20 |
|
|
|
2.62 |
|
Depletion, depreciation and amortization |
|
|
13.52 |
|
|
|
13.08 |
|
|
|
12.17 |
|
|
|
11.11 |
|
|
|
9.09 |
|
Proved Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
192,879 |
|
|
|
179,126 |
|
|
|
134,978 |
|
|
|
126,185 |
|
|
|
106,173 |
|
Natural gas (MMcf)(7) |
|
|
87,975 |
|
|
|
427,955 |
|
|
|
358,608 |
|
|
|
288,826 |
|
|
|
278,367 |
|
MBOE (6:1) |
|
|
207,542 |
|
|
|
250,452 |
|
|
|
194,746 |
|
|
|
174,322 |
|
|
|
152,568 |
|
Carbon dioxide (MMcf)(8) |
|
|
6,302,836 |
|
|
|
5,612,167 |
|
|
|
5,641,054 |
|
|
|
5,525,948 |
|
|
|
4,645,702 |
|
Consolidated Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
4,269,978 |
|
|
$ |
3,589,674 |
|
|
$ |
2,771,077 |
|
|
$ |
2,139,837 |
|
|
$ |
1,505,069 |
|
Total long-term liabilities |
|
|
1,903,951 |
|
|
|
1,363,539 |
|
|
|
1,102,066 |
|
|
|
833,380 |
|
|
|
617,343 |
|
Stockholders equity(9) |
|
|
1,972,237 |
|
|
|
1,840,068 |
|
|
|
1,404,378 |
|
|
|
1,106,059 |
|
|
|
733,662 |
|
|
|
|
(1) |
|
Effective January 1, 2006, Denbury adopted new guidance issued by the Financial Accounting
Standard Board (FASB) in the Compensation-Stock Compensation topic of the FASB Accounting
Standards
CodificationTM (FASC) which prospectively required Denbury to record compensation
expense for stock incentive awards. |
|
(2) |
|
In 2008, we had a full cost ceiling test write-down of $226 million ($140.1 million net of tax)
and pretax expense of $30.6 million associated with a cancelled acquisition. These charges were
partially offset by pretax income of $200.1 million on our commodity derivative contracts. In 2009,
we had a pretax charge of $236.2 million associated with our commodity derivative contracts. |
|
(3) |
|
On December 5, 2007, and October 31, 2005, we split our common stock on a 2-for-1 basis.
Information relating to all prior years shares and earnings per share has been retroactively
restated to reflect the stock splits. |
|
(4) |
|
During February 2009, we closed our $201 million purchase of Hastings Field, and in December
2009, we closed our $430.7 million purchase |
37
Denbury Resources Inc.
|
|
|
|
|
of Conroe Field (for $269.8 million in cash and the
issuance of 11,620,000 shares of common stock). We sold our Barnett Shale natural gas assets in 2009. |
|
(5) |
|
In February 2009, we issued $420 million of 9.75% Senior Subordinated Notes due 2016. |
|
(6) |
|
In June 2009, we recorded $10.0 million of expense related to a Founders Retirement Agreement.
During 2009, we recorded $14.2 million related to incentive compensation awards for the management
of Genesis. During the fourth quarter of 2009, we recorded $8.7 million in acquisition-related
expenses in conjunction with the Encore Merger Agreement. |
|
(7) |
|
In December 2007 and February 2008, we sold our Louisiana natural gas assets, and during 2009
we sold our Barnett Shale natural gas assets. |
|
(8) |
|
Based on a gross working interests basis and includes reserves dedicated to volumetric
production payments of 127.1 Bcf at December 31, 2009, 153.8 Bcf at December 31, 2008, 182.3 Bcf at
December 31, 2007, 210.5 Bcf at December 31, 2006, and 237.1 Bcf at December 31, 2005. (See Note 16
to the Consolidated Financial Statements). |
|
(9) |
|
We have never paid any dividends on our common stock. |
38
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations
The following discussion and analysis should be read in conjunction with our Consolidated
Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary
Data. Our discussion and analysis includes forward looking information that involves risks and
uncertainties and should be read in conjunction with Risk Factors under Item 1A of this report,
along with Forward Looking Information at the end of this section for information on the risks
and uncertainties that could cause our actual results to be materially different than our forward
looking statements. The following discussion and analysis does not include information regarding
results of operations and financial condition of Encore, which is contained in Encores Form 10-K
for the year ended December 31, 2009, filed by Encore with the
SEC on February 25, 2010.
Overview
We are a growing independent oil and natural gas company engaged in acquisition, development
and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas
producer in Mississippi, own the largest carbon dioxide (CO2) reserves east
of the Mississippi River used for tertiary oil recovery, and hold significant operating acreage in
properties onshore in Louisiana, Alabama and Southeast Texas. Our goal is to increase the value of
acquired properties through a combination of exploitation, drilling, and proven engineering
extraction processes, with our most significant emphasis relating to tertiary recovery operations.
Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have four primary field
offices located in Laurel, Mississippi; Jackson, Mississippi; Little Creek, Mississippi; and Alvin,
Texas.
During 2009, we entered into several strategic transactions to expand our primary business of
CO2 tertiary operations, as follows:
|
|
|
purchased Hastings Field in southeast Texas in February; |
|
|
|
|
purchased Conroe Field in the same area in December; |
|
|
|
|
on October 31st agreed to acquire Encore Acquisition Company, subject to
approval of each companys shareholders on March 9, 2010; |
|
|
|
|
divested non-strategic operations in the Barnett Shale; and |
|
|
|
|
entered into an agreement to sell our interests in the General
Partner of Genesis Energy, L.P. and subsequently closed this transaction in February
2010. |
Each of these transactions, which are further discussed below, supports our strategic emphasis
on further developing and expanding our CO2 tertiary operations and should
provide future growth in our CO2 tertiary operations for many years to come.
In addition, during 2009 we invested approximately $538 million in our Green Pipeline, which when
finished will transport
CO2
from the end of our NEJD Pipeline, in
Louisiana, to our tertiary floods in southeast Texas.
2009 Operating Highlights. We recognized a net loss of $75.2 million during 2009, or ($0.30)
per common share, compared to net income of $388.4 million, or $1.59 per common share earned during
2008. The reduction in net income between the two years is primarily due to lower oil and natural
gas commodity prices and non-cash expense of $383.0 million ($237.4 million after tax) in 2009 due
to the changes in fair value of our commodity derivative contracts. In 2008, we recorded a
non-cash gain of $257.6 million ($159.7 million after tax) on the fair value changes in our
commodity derivative contracts, which was primarily offset by a $226.0 million ($140.1 million
after tax) full cost ceiling test write-down at December 31, 2008.
Oil and natural gas prices continued to be volatile during 2009, but generally trended upward
during the year, as compared to the latter part of 2008 when oil and natural gas prices dropped
significantly from their highs in mid-2008. Our average revenue per BOE, excluding the impact of
oil and natural gas derivative contracts, was $49.16 per BOE in 2009, as compared to $79.42 per BOE
in 2008, a 38% decrease between the two periods. Although our production increased between 2008 and
2009, the significant drop in commodity prices resulted in a 36% decrease in our oil and natural
gas revenues during 2009 as compared to 2008.
During 2009, our oil and natural gas production averaged 48,299 BOE/d, a 4% increase over the
average production for 2008; however, our continuing production excluding the production from our
Barnett Shale
39
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
properties that were sold in 2009 increased 15%. Our largest production increases were
attributable to our tertiary oil production and Hastings Field, which we acquired in February 2009,
partially offset by (a) the sale of our Barnett Shale natural gas properties; and (b) expected
declines in our Mississippi non-tertiary production primarily due to lower Selma Chalk natural gas
production as a result of limited drilling activity in 2009, and to a lesser extent due to lower
non-tertiary Heidelberg oil production as additional areas of that field were shut-in in order to
expand the tertiary flooding to those areas. See Results of Operations Operating Results
Production for more information.
Tertiary oil production averaged 24,343 BOE/d during 2009, representing a 26% increase over
our tertiary oil production during 2008. We had strong production increases during 2009 from
several of our existing tertiary oil fields, and had initial production response from
CO2 injections at Heidelberg Field during the second quarter of 2009 and at
Cranfield Field during the first quarter of 2009. See Results of Operations CO2 Operations for
more information.
Cash settlements received on our commodity derivative contracts during 2009 were $146.7
million, compared to payments of $57.5 million made during 2008. During 2009, we had a non-cash
fair value charge on our derivative contracts of $383.0 million, compared to a non-cash fair value
gain of $257.6 million in 2008. Coupled together, our total adjustments on derivative contracts
resulted in a net change between 2008 and 2009 of $436.3 million of additional expense in 2009.
Our lease operating expenses increased 6% between 2008 and 2009, primarily due to our
increasing emphasis on tertiary operations, increasing utility and electrical costs to operate our
fields, and increasing lease payments for certain equipment in our tertiary operating facilities.
General and administrative expenses increased significantly from 2008 levels due to increased
compensation and personnel related costs, incentive compensation awards for certain members of
management of Genesis, $10.0 million paid under a Founders Retirement Agreement, and acquisition
related expenses associated with the Encore merger agreement. Interest expense also increased
during 2009, due primarily to the February issuance of $420 million of 9.75% Senior Subordinated
Notes due 2016 and the pipeline dropdown transactions with Genesis, which were completed mid-2008,
offset in part by increasing interest capitalization related to our CO2
pipelines under construction.
Definitive Merger Agreement to Acquire Encore Acquisition Company. On November 1, 2009,
Denbury and Encore announced that we had entered into a definitive merger agreement providing for
Encore to merge with and into Denbury, in a stock and cash transaction valued at approximately $4.5
billion at that time, including the assumption of debt and the value
of the general partner units and limited partner units held by Encore in
Encore MLP. The combined company will continue to be known as Denbury Resources Inc. and will be
headquartered in Plano, Texas.
The Merger Agreement was unanimously approved by the boards of directors of both Denbury and
Encore. The Merger Agreement contemplates a merger whereby Denbury and Encore have agreed to
combine their businesses such that Encore will be merged with and into Denbury, with Denbury
surviving the Merger. The Merger is subject to the stockholders of each of Denbury and Encore
approving the Merger, including approval by Denburys stockholders of the issuance of Denbury
common stock to be used as Merger consideration. Each company has scheduled a special stockholder
meeting on March 9, 2010, for stockholders to vote on the merger.
Under the agreement, Encore stockholders will receive $50.00 per share for each share of
Encore common stock, comprised of $15.00 in cash and $35.00 in Denbury common stock, subject to
both an election feature and a collar mechanism on the stock portion of the consideration as set
forth in more detail below.
Merger Agreement
In calculating the exchange ratio range for the collar mechanism, the Denbury common stock was
initially valued at $15.10 per share. The collar mechanism is limited to a 12% upward or downward
movement in the Denbury share price. The final number of Denbury shares to be issued will be
adjusted based on the volume weighted average price of Denbury common stock on the NYSE for the
20-day trading period ending on the second day prior to closing. Based on this mechanism, if
Denbury stock trades between $13.29 and $16.91, the Encore stockholders will receive between 2.0698
and 2.6336 shares of Denbury common stock for each of their shares of Encore common stock, but not
higher or lower than these share amounts if Denbury common stock trades outside this range. If
Denbury common stock trades outside of this range, the value of the shares of Denbury received will
40
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
represent either more or less than $35 per share. Based on the number of shares of Encore
common stock outstanding as of February 3, 2010, we would issue to Encore stockholders between 115
million and 146 million shares of our common stock in the Merger, which will represent an increase
in our aggregate shares outstanding of between 44% and 56%.
The Merger Agreement contains customary covenants by each party to the Merger Agreement and
consummation of the Merger is subject to customary conditions. The Merger Agreement also contains
certain termination rights for both us and Encore, including, among others, if the Merger has not
occurred on or before May 31, 2010 with termination fees in varying amounts payable by us or by
Encore based upon specified reasons for termination. See Business-Definitive Merger Agreement to
Acquire Encore Acquisition Company.
Financing of the Merger
We received a financing commitment from J.P. Morgan, subject to customary conditions, to
underwrite a new $1.6 billion senior secured revolving credit facility. We have been advised by
the co-arrangers of this new senior secured revolving credit facility, J.P. Morgan and Bank of
America, N.A. that the syndication phase is complete, and documentation for this facility is being
prepared. Subject to final documentation and satisfaction of closing conditions, we anticipate
finalizing this facility prior to the Denbury and Encore stockholder meetings. The newly committed
financing, coupled with the funds from our recent subordinated debt offering (see next paragraph),
will be used to fund the cash portion of the merger consideration (inclusive of payments due to
Encore stock option holders), repay amounts outstanding under our existing $750 million revolving
credit facility, which had $125 million outstanding as of February 15, 2010, potentially retire and
replace a portion of up to $825 million of Encores senior subordinated notes that are outstanding,
all of which have a change of control put option at 101% of par value, repay amounts outstanding
under Encores existing revolving credit facility which had $155 million outstanding as of February
15, 2010, pay Encores severance costs, pay transaction fees and expenses and provide additional
liquidity. The aggregate commitment of the senior secured lenders is a $1.6 billion facility with a
term of four years. The new facility is expected to be on substantially the same terms as our
existing facility, conformed to current market conditions.
We also received a financing commitment from J.P. Morgan for a $1.25 billion unsecured bridge
loan facility; however, this bridge loan facility has been terminated and will not be utilized to
fund the Merger as we have instead issued $1 billion of 8.25%
Senior Subordinated Notes due 2020.
On February 10, 2010, we sold $1 billion of 8.25% Senior Subordinated Notes due 2020 at 100% of par
in a public offering. The net proceeds from the notes offering were placed in escrow pending the
closing of the Merger, subject to mandatory redemption of the notes if the Merger does not close,
and partial redemption of the notes to the extent that three series of Encore outstanding senior
subordinated notes are not repurchased. Upon the closing of the Merger, $400 million of the
escrowed proceeds will be released to us to finance a portion of the Merger consideration, and the
remaining escrowed proceeds will be
used to fund repurchases of up to $600
million principal amount of three series of Encores outstanding
senior subordinated notes (or newly issued 8.25% senior notes to the
extent not issued to repurchase Encore notes). On
February 8, 2010, we initiated a tender offer for these Encore subordinated notes, the closing of
which is subject to the closing of the Merger.
Sale of Interests in General Partner of Genesis Energy, L.P. On February 5, 2010, Denbury and
one of its subsidiaries sold all of the subsidiarys interests in Genesis Energy, LLC, the general
partner of Genesis Energy, L.P., or Genesis, to an affiliate of
Quintana Capital Group L.P., for net
proceeds of approximately $82 million (including amounts related to Genesis management incentive
compensation and other selling costs). This sale gives the buyer control of Genesis general
partner. The sale of Denburys interest in the general partner does not include the sale of its
approximate 10% ownership of Genesis outstanding common units, which Denbury currently still owns
and for which a resale registration statement was filed in January 2010.
Conroe Field Acquisition. On December 18, 2009, we purchased from Wapiti Energy, LLC, Wapiti
Operating, LLC and Wapiti Gathering, LLC (collectively, Wapiti), a Houston based privately-owned
company, oil
and natural gas assets in the Conroe Field for total consideration of $422.9 million (after
preliminary purchase price adjustments), consisting of $254.2 million in cash and 11,620,000 shares
of Denbury common stock, which for the purpose of estimated fair value under FASC Business
Combinations topic, we utilized the closing stock price on that date of $14.52 per share resulting
in a total value of $168.7 million. We also exchanged cash for approximately $15.6 million of
escrow account deposits reserved for plugging and abandonment. We have internally estimated
41
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
that
the Conroe Field interests have significant estimated net reserve potential from
CO2 tertiary recovery, the largest EOR potential of our Gulf Coast oil fields.
The acquired Conroe Field interests have estimated proved conventional reserves of approximately
18.5 MMBbls at December 31, 2009, nearly all of which are proved developed. The Conroe Field
assets are currently producing around 2,500 BOE/d net to our acquired interest.
We have recorded the acquisition of Conroe Field in accordance with the Financial Accounting
Standards Board (FASB) Accounting Standards CodificationTM (FASC) Business
Combinations topic, which became effective for acquisitions after December 31, 2008. Based on
these new rules, we have allocated $304.3 million of the $438.5 million adjusted purchase price
(includes escrow deposits) to proved properties, $93.6 million to unevaluated properties,
approximately $15.6 million to other assets, $5.7 million to asset retirement obligations and the
net remaining $30.7 million to goodwill. See further discussion on this acquisition in Note 2 to
the Consolidated Financial Statements.
Sale of Barnett Shale Natural Gas Assets. In May 2009, we entered into an agreement to sell
60% of our Barnett Shale assets to Talon Oil and Gas LLC (Talon), a privately held company, for
$270 million (before closing adjustments). On June 30, 2009, we completed approximately
three-quarters of the sale, and closed the remaining portion of the sale on July 15, 2009. Net
proceeds were $259.8 million (after closing adjustments, and net of $8.1 million paid to Talon for
natural gas swaps transferred in the sale). We did not record a gain or loss on the sale in
accordance with the full cost method of accounting.
On December 30, 2009, we sold our remaining 40% interest in our Barnett Shale natural gas
assets to Talon for $210 million in cash, subject to closing adjustments. The proceeds of the sale
were used to reduce outstanding bank debt. The sale was structured as a deferred like-kind exchange
in conjunction with Denburys purchase of Conroe Field that closed on December 18, 2009.
Mid-Year Management Changes. On June 30, 2009, under a management succession plan adopted by
our Board of Directors and announced on February 5, 2009, Gareth Roberts, the Companys founder,
relinquished his position as President and CEO and became Co-Chairman of the Board of Directors and
assumed a non-officer role as the Companys Chief Strategist. Phil Rykhoek, previously Senior Vice
President and Chief Financial Officer, became Chief Executive Officer; Tracy Evans, previously
Senior Vice President Reservoir Engineering, became President and Chief Operating Officer; and
Mark Allen, previously Vice President and Chief Accounting Officer, became Senior Vice President
and Chief Financial Officer.
In connection with Mr. Roberts retirement as CEO and President of the Company, Mr. Roberts
and the Company entered into a Founders Retirement Agreement (the Agreement). Under this
Agreement, Mr. Roberts received $3.65 million in cash and the Company issued to him $6.35 million
of the Companys 9.75% Senior Subordinated Notes due 2016. As part of the Agreement, there are
restrictions that prohibit Mr. Roberts from trading these notes for two years, and he has entered
into a non-compete arrangement with the Company through 2013. Mr. Roberts will continue to provide
services to the Company as Co-Chairman of the Board of Directors and in a non-officer role as Chief
Strategist.
Purchase of Hastings Field. On February 2, 2009, we closed the acquisition of Hastings Field
located near Houston, Texas, for approximately $201 million in cash. Hastings Field is a
significant potential tertiary oil flood that we plan to flood with CO2
delivered from Jackson Dome using our Green Pipeline, which is currently under construction.
We originally entered into an agreement in November 2006 with a subsidiary of Venoco, Inc., that
gave us the option to purchase its interest in the Hastings Field. As consideration for the
purchase option, we made total payments of $50 million which makes our aggregate purchase price
$251 million. The seller retained a 2% override and reversionary interest of approximately 25%
following payout, as defined in the purchase agreement. We plan to commence flooding the field with
CO2 beginning in 2011, after completion of our Green Pipeline and construction
of field recycling facilities. Under the purchase agreement, we are required to make net capital
expenditures in this field totaling $179 million over the next five years, including our first
obligation of $26.8
million during 2010, and are committed to begin CO2 injections averaging
50 MMcf/d by the fourth quarter of 2012. Production from this field averaged 1,956 BOE/d during
2009, all of which was non-tertiary production. At December 31, 2009, the Hastings Field had proved
reserves of 8.9 MMBbls.
We have recorded the acquisition of Hastings Field in accordance with FASC Business
Combinations topic, which became effective for acquisitions after December 31, 2008. Based on
these new rules, we have allocated
42
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
$107.6 million of the $246.8 million adjusted purchase price to
proved properties, approximately $2.4 million to land, oilfield equipment and other related assets,
$2.0 million to asset retirement obligations and the net remaining $138.8 million to goodwill. See
further discussion regarding this acquisition in Note 2 to the Consolidated Financial Statements.
February 2009 Subordinated Debt Issuance. On February 13, 2009, we issued $420 million of
9.75% Senior Subordinated Notes due 2016 (the Notes). The Notes were sold to the public at
92.816% of par, plus accrued interest from February 13, 2009, which equates to an effective yield
to maturity of approximately 11.25% (before offering expenses). Interest on the Notes will be paid
on March 1 and September 1 of each year. The Notes will mature on
March 1, 2016. We used the net proceeds from the offering of approximately $381.4 million to repay
most of the then outstanding debt on our bank credit facility. We issued an additional $6.35
million of Notes to Mr. Roberts on June 30, 2009 (see Mid-Year Management Changes above).
Capital Resources and Liquidity
General
During 2009, we took several steps to ensure that we had adequate capital resources and
liquidity in order to fund our capital expenditure program and to complete two strategic
acquisitions, the Hastings Field and the Conroe Field. Those steps included the issuance of $420
million of 9.75% Senior Subordinated Notes in February 2009, the sale of 60% of our Barnett Shale
assets in mid-2009, and the sale of the remaining 40% of our Barnett Shale assets during December
2009. We used the $381.4 million net proceeds from the February 2009 Notes issuance to repay the
majority of our then-outstanding bank debt, and we did the same with the proceeds from our December
2009 Barnett Shale sale, freeing up our credit line for future capital needs.
Denbury Stand-Alone
We currently estimate our 2010 capital spending will be approximately $650 million, excluding
capitalized interest and net of equipment leases, and any expenditures related to the Encore
acquisition. Our current 2010 capital budget includes approximately $74 million to be spent in the
Jackson Dome area, $159 million to be spent on our CO2 pipelines and approximately $365
million allocated for tertiary oil field expenditures. This estimate also assumes that we fund
approximately $50 million of budgeted equipment purchases with operating leases, which is dependent
upon securing acceptable financing. If we do not enter into a total of $50 million of operating
leases during 2010, our net capital expenditures would increase accordingly, and we would
anticipate funding those additional capital expenditures under our bank credit line. We did not
enter into as many operating leases during 2009 as we had anticipated, leasing approximately $49
million of equipment out of a projected total of $100 million, which resulted in a corresponding
net increase in capital expenditures and bank debt. Potentially, during 2010 we could lease all or
a portion of this equipment.
Based on oil and natural gas commodity futures prices as of late February 2010 and our current
2010 production forecasts, our stand-alone 2010 capital budget is expected to be $150 million to
$250 million greater than our anticipated cash flow from
operations on a stand-alone basis. We
plan to fund this shortfall with cash generated from the sale of our general partnership interest
in Genesis (see Sale of Interests in General Partner of Genesis Energy, L.P.
above), the anticipated sale of our limited partnership units in Genesis Energy, L.P., and the
remainder from borrowings under our bank facility. As of February 15, 2010, we had $125 million of
bank debt outstanding on our $750 million committed bank facility, leaving us significant
incremental borrowing capacity to fund any shortfall.
Combined Company Post Denbury/Encore Merger
Assuming the successful completion of the Encore acquisition in early March 2010, our
currently planned 2010 capital expenditure budget for the combined companies would increase to $1 billion.
Currently, this incremental $350 million of capital expenditures is budgeted to be spent as
follows: (1) approximately $142 million to drill or participate in drilling or refracing of 55 to
75 wells in the Bakken area of North Dakota; (2) approximately $99 million to drill and complete 6
to 8 operated wells and participate in 20 to 25 non-operated wells in the Haynesville and other
East Texas fields; (3) approximately $35 million on Encores Rocky Mountain legacy oil fields; and
(4) approximately $74 million on drilling and completion activities in Encores Permian Basin and
Mid-Continent region. Based on oil and gas commodity prices as of
late February 2010 and our current estimated production forecasts on a
combined basis for all of 2010, and before any asset sales, our 2010
combined capital budget is expected to be $150 million to $250
million greater than our anticipated combined cash flow from
operations, assuming a full year of operations.
43
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
As discussed above in Overview Definitive Merger Agreement to Acquire Encore Acquisition
Company, the primary source of cash for the proposed acquisition of Encore would be a new $1.6
billion bank credit facility, which would replace our existing facility, and $1 billion of recently
issued 8.25% Senior Subordinated Notes due 2020. We structured the financing of the acquisition to
provide $600 million to $700 million of availability on our new $1.6 billion bank credit facility
upon closing the transaction; this would provide a level of liquidity similar to that available to
us prior to the transaction, and a portion of those funds would be available for the expanded
capital expenditures discussed above. In addition, during 2010 we plan to sell between $500
million and $1 billion of oil and gas properties to cover capital expenditures in excess of cash
flow from operations during 2010, to reduce debt levels, and to provide additional liquidity.
During 2009, we also entered into oil and natural gas commodity derivative contracts through 2011
in order to protect our future cash flows. See Note 10 to the Consolidated Financial
Statements for further details regarding pricing and volumes for these commodity derivative
contracts.
We continually monitor our capital spending and anticipated cash flows and believe that we can
adjust our capital spending up or down depending on cash flows; however, any such reduction in
capital spending could reduce our anticipated production levels in future years. For 2010, we have
contracted for certain capital expenditures, including construction of most of the Green Pipeline
already in progress and two drilling rigs, and therefore we cannot eliminate all of our capital
commitments without penalties (refer to Off-Balance Sheet Arrangements Commitments and
Obligations for further information regarding these commitments).
As part of our semi-annual bank review, on October 1, 2009, our bank borrowing base and
commitment amounts were left unchanged at $900 million and $750 million, respectively. The
borrowing base represents the amount that can be borrowed from a credit standpoint while the
commitment amount is the amount the banks have committed to fund pursuant to the terms of the
credit agreement. As a result of the sale of our remaining Barnett Shale properties in December
2009, the banks performed another redetermination of our borrowing base and left the commitment
amount unchanged at $750 million. If for some reason the Merger is not completed, we anticipate
this credit line will be sufficient for our 2010 plans, and do not expect our bank credit line to
be reduced by our banks unless commodity prices were to decrease significantly from current levels.
However, assuming the closing of the Merger, this credit facility will be replaced with the newly
committed $1.6 billion four-year revolving credit facility discussed above in Overview
Definitive Merger Agreement to Acquire Encore Acquisition Company.
Capital Expenditure Summary. The following table of capital expenditures includes
accrued capital for each period. Our cash expenditures were $76.0 million higher in the 2009
period, $59.2 million lower in the 2008 period and $0.4 million higher in the 2007 period than the
amounts listed below due to the increase (decrease) in our capital accruals in those periods. For
the 2009 period, oil and natural gas property acquisitions include $168.7 million of Denbury common
stock issued in the purchase of Conroe Field, representing 11,620,000 common shares valued at the
closing stock price of $14.52 per share on the date of acquisition, and approximately $169.5
million of the combined acquisition cost of Hastings Field and Conroe Field which was assigned to
goodwill as determined under the FASC Business Combinations topic.
44
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Capital expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas exploration and development: |
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
$ |
45,403 |
|
|
$ |
244,841 |
|
|
$ |
313,258 |
|
Geological, geophysical and acreage |
|
|
15,004 |
|
|
|
18,183 |
|
|
|
22,829 |
|
Facilities |
|
|
154,772 |
|
|
|
170,263 |
|
|
|
118,003 |
|
Recompletions |
|
|
73,968 |
|
|
|
140,451 |
|
|
|
141,264 |
|
Capitalized interest |
|
|
14,350 |
|
|
|
17,627 |
|
|
|
18,305 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas exploration and
development expenditures |
|
|
303,497 |
|
|
|
591,365 |
|
|
|
613,659 |
|
Oil and natural gas property acquisitions |
|
|
621,517 |
|
|
|
31,367 |
|
|
|
49,077 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas capital expenditures |
|
|
925,014 |
|
|
|
622,732 |
|
|
|
662,736 |
|
|
|
|
|
|
|
|
|
|
|
CO2 capital expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
CO2 pipelines |
|
|
542,654 |
|
|
|
343,043 |
|
|
|
103,401 |
|
CO2 producing fields |
|
|
33,302 |
|
|
|
108,312 |
|
|
|
65,701 |
|
Capitalized interest |
|
|
54,246 |
|
|
|
11,534 |
|
|
|
2,080 |
|
|
|
|
|
|
|
|
|
|
|
Total CO2 capital expenditures |
|
|
630,202 |
|
|
|
462,889 |
|
|
|
171,182 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,555,216 |
|
|
$ |
1,085,621 |
|
|
$ |
833,918 |
|
|
|
|
|
|
|
|
|
|
|
Our
2009 capital expenditures, including the $169.5 million of goodwill incurred in 2009 and the $76.0
million reduction in accrued capital expenditures, were funded with $530.6 million of cash flow
from operations, $516.8 million in net proceeds from the sale of oil and natural gas properties,
$381.4 million in net proceeds from the February issuance of senior subordinated debt, $168.7
million from the issuance of 11,620,000 shares of Denbury common stock in the acquisition of Conroe
Field and $50.0 million in net bank borrowings.
Our 2008 capital expenditures were funded with $774.5 million of cash flow from operations,
$225 million from the drop-down of CO2 pipelines to Genesis, and $51.7 million from
property sales proceeds.
Our 2007 capital expenditures were funded with $570.2 million of cash flow from operations,
$150.0 million from the April 2007 issuance of subordinated debt, $135.8 million from property
sales proceeds, and $16.0 million of net bank borrowings.
Off-Balance Sheet Arrangements Commitments and Obligations. At December 31, 2009,
our dollar denominated payment obligations that are not on our balance sheet include our operating
leases, which at year-end 2009 totaled $162.2 million (including $147.8 million of original
equipment costs) relating primarily to the lease financing of certain equipment for
CO2 recycling facilities at our tertiary oil fields. We also have several
leases relating to office space and other minor equipment leases. At December 31, 2009, we had a
total of $10.5 million of letters of credit outstanding under our bank credit agreement.
Additionally, we have dollar denominated obligations that are not currently recorded on our balance
sheet relating to various obligations for development and exploratory expenditures that arise from
our normal capital expenditure program or from other transactions common to our industry. In
addition, in order to recover our undeveloped proved reserves, we must also fund the associated
future development costs forecasted in our proved reserve reports. For a further discussion of our
future development costs and proved reserves, see the table of our contractual obligations below.
On February 2, 2009, we closed our $201 million purchase of Hastings Field. Under the
agreement, we are required to make aggregate cumulative capital expenditures in this field of
approximately $179 million over the next five years cumulating as follows: $26.8 million by
December 31, 2010, $71.5 million by December 31, 2011, $107.2 million by December 31, 2012, $142.9
million by December 31, 2013, and $178.7 million by December 31, 2014. If we fail to spend the
required amounts by the due dates, we are required to make a cash payment equal to 10% of the
cumulative shortfall at each applicable date. During 2009, we made capital expenditures related to
CO2
45
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
flood development at Hastings totaling $1.7 million. Further, we are committed to injecting at
least an average of 50 MMcf/d of CO2 (total of purchased and recycled) in the
West Hastings Unit for the 90-day period prior to January 1, 2013. If such injections do not occur,
we must either (1) relinquish our rights to initiate (or continue) tertiary operations and reassign
to Venoco all assets previously purchased for the value of such assets at that time based upon the
discounted value of the fields proved reserves using a 20% discount rate, or (2) make an
additional payment of $20 million in January 2013, less any payments made for failure to meet the
capital spending requirements as of December 31, 2012, and a $30 million payment for each
subsequent year (less amounts paid for capital expenditure shortfalls) until the
CO2 injection rate in the Hastings Field equals or exceeds the minimum required
injection rate. We currently anticipate that we will be able to meet the requirements under this
agreement.
We currently have long-term commitments to purchase CO2 from eight
proposed gasification plants; four are in the Gulf Coast region and four are in the Midwest region
(Illinois, Indiana and Kentucky). The Midwest plants are not only conditioned on the specific
plants being constructed, but also upon Denbury contracting additional volumes of CO2
for purchase in the general area of the proposed plants that would provide an acceptable
economic rate-of-return on the CO2 pipeline. If all of these
plants were to be built, these CO2 sources are currently anticipated to provide
us with aggregate CO2 volumes of 1.2 Bcf/d to 1.9 Bcf/d. Due to the current
economic conditions, the earliest we would expect any plant to be completed and providing
CO2 would be 2014, and there is some doubt as to whether they will be
constructed at all. Several of these plants are seeking funds from government sources, which if
achieved, could increase the probability that the plants are ultimately constructed. The base
price of CO2 per Mcf from these CO2 sources varies by plant
and location, but is generally higher than our most recent all-in cost of CO2
from our natural source (Jackson Dome) using current oil prices. Prices for CO2
delivered from these projects are expected to be competitive with the cost of our natural
CO2 after adjusting for our estimates of future prices for our share of
potential carbon emissions reduction credits. If all eight plants are built, the aggregate purchase
obligation for this CO2 would be around $280 million per year, assuming a $70
per barrel oil price, before any potential savings from our share of carbon emissions reduction
credits. All of the contracts have price adjustments that fluctuate based on the price of oil.
Construction has not yet commenced on any of these plants, and their construction is contingent on
the satisfactory resolution of various issues, including financing. While it is likely that not
every plant currently under contract will be constructed, there are several other plants under
consideration that could provide CO2 to us that would either supplement or
replace some of the CO2 volumes from the eight proposed plants for which we
currently have CO2 purchase contracts. We are having ongoing discussions with several
of these other potential sources.
As discussed above under Overview Definitive Merger Agreement to Acquire Encore
Acquisition Company, the Encore Merger Agreement contains certain termination rights for both
Denbury and Encore, including, among others, if the Merger is not completed by May 31, 2010. In the
event of a termination of the Merger Agreement under certain circumstances, Encore may be required
to pay Denbury a termination fee of either $60 million or $120 million, or Denbury may be required
to pay Encore a termination fee of either $60 million, $120 million or $300 million, in each case
depending on the circumstances of the termination. In addition, fee letters executed in connection
with the financing commitment from JP Morgan require Denbury to pay up to approximately $48 million
in fees if the Merger is not consummated and the loans do not close.
A summary of our obligations at December 31, 2009, is presented in the following table.
Contingent termination fees in connection with the Merger are discussed above. This table does not
include the $1 billion of 8.25% Senior Subordinated Notes due 2020 issued in February 2010, the
$1.6 billion newly committed bank revolving credit agreement, or any contractual obligations of
Encore.
46
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
In thousands |
|
Total |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
2014 |
|
Thereafter |
|
Contractual Obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated debt(a) |
|
$ |
951,350 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
225,000 |
|
|
$ |
|
|
|
$ |
726,350 |
|
Senior Bank Loan(a) |
|
|
125,000 |
|
|
|
|
|
|
|
125,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated interest payments
on subordinated debt and
Senior Bank Loan(a) |
|
|
451,156 |
|
|
|
84,632 |
|
|
|
83,540 |
|
|
|
80,944 |
|
|
|
68,230 |
|
|
|
64,069 |
|
|
|
69,741 |
|
Commitment, transaction, and advisory fees
related to financing of the Encore
merger(b) |
|
|
47,892 |
|
|
|
47,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline financing lease obligations(c) |
|
|
559,056 |
|
|
|
31,759 |
|
|
|
33,205 |
|
|
|
33,438 |
|
|
|
33,518 |
|
|
|
33,513 |
|
|
|
393,623 |
|
Operating lease obligations |
|
|
162,161 |
|
|
|
27,566 |
|
|
|
26,621 |
|
|
|
23,248 |
|
|
|
20,544 |
|
|
|
17,145 |
|
|
|
47,037 |
|
Capital lease obligations(d) |
|
|
7,314 |
|
|
|
1,974 |
|
|
|
1,974 |
|
|
|
1,272 |
|
|
|
700 |
|
|
|
673 |
|
|
|
721 |
|
Capital expenditure obligations(e) |
|
|
229,548 |
|
|
|
78,006 |
|
|
|
44,337 |
|
|
|
35,735 |
|
|
|
35,735 |
|
|
|
35,735 |
|
|
|
|
|
Derivative contracts payment(f) |
|
|
88,006 |
|
|
|
86,986 |
|
|
|
1,020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Cash Commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future development costs on proved oil and
gas reserves, net of capital
obligations(g) |
|
|
754,469 |
|
|
|
197,640 |
|
|
|
208,603 |
|
|
|
128,380 |
|
|
|
91,381 |
|
|
|
36,823 |
|
|
|
91,642 |
|
Future development cost on proved CO2
reserves, net of capital obligations(h) |
|
|
121,467 |
|
|
|
12,467 |
|
|
|
11,000 |
|
|
|
|
|
|
|
|
|
|
|
11,000 |
|
|
|
87,000 |
|
Asset retirement obligations(i) |
|
|
134,486 |
|
|
|
1,585 |
|
|
|
1,316 |
|
|
|
740 |
|
|
|
983 |
|
|
|
174 |
|
|
|
129,688 |
|
|
Total |
|
$ |
3,631,905 |
|
|
$ |
570,507 |
|
|
$ |
536,616 |
|
|
$ |
303,757 |
|
|
$ |
476,091 |
|
|
$ |
199,132 |
|
|
$ |
1,545,802 |
|
|
|
|
|
(a) |
|
These long-term borrowings and related interest payments are
further discussed in Note 6 to the Consolidated Financial
Statements. This table assumes that our long-term debt is held
until maturity. |
|
(b) |
|
Represents the minimum estimated fees payable to JP Morgan for
financing commitments related to the proposed acquisition of
Encore if the Encore Merger does not close. If the Merger closes,
these fees would be increased to approximately $95 million. |
|
(c) |
|
Represents estimated future cash payments under a long-term
transportation service agreement for the Free State Pipeline, and
future minimum cash payments in a 20-year financing lease for the
NEJD pipeline system. Both transactions with Genesis were entered
into in 2008 and are being accounted for as financing leases. The
payment required for the Free State Pipeline is variable based
upon the amount of the CO2 we ship through the pipeline and the
commitment amounts disclosed above for that financing lease are computed
based upon our internal forecasts. Approximately $308 million of
these payments represent interest. See Note 3 to the Consolidated
Financial Statements. |
|
(d) |
|
Represents future minimum cash commitments of $4.7 million to
Genesis under capital leases in place at December 31, 2009,
primarily for transportation of crude oil and CO2, and $2.6
million for office space and rental equipment. Approximately $1.4
million of these payments represents interest. |
|
(e) |
|
Represents future cash commitments under contracts in place as of
December 31, 2009, primarily for pipe, pipeline construction
contracts, drilling rig services and well related costs. As is
common in our industry, we commit to make certain expenditures on
a regular basis as part of our ongoing development and exploration
program. These commitments generally relate to projects that occur
during the subsequent several months and are usually part of our
normal operating expenses or part of our capital budget, which for
2010 is currently set at $650 million, exclusive of acquisitions
and capitalized interest. In certain cases we have the ability to
terminate contracts for equipment in which case we would only be
liable for the cost incurred by the vendor up to that point;
however, as we currently do not anticipate cancelling those
contracts these amounts include our estimated payments under those
contracts. We also have recurring expenditures for such things as
accounting, engineering and legal fees, software maintenance,
subscriptions, and other overhead type items. Normally these
expenditures do not change materially on an aggregate basis from
year to year and are part of our general and administrative
expenses. We have not attempted to estimate the amounts of these
types of recurring expenditures in this table as most could be
quickly cancelled with regard to any specific vendor, even though
the expense itself may be required for ongoing normal operations
of the Company. |
|
(f) |
|
Represents the estimated future payments under our oil and natural
gas derivative contracts based on the futures market prices as of
December 31, 2009. These amounts will change as oil and natural
gas commodity prices change. The estimated fair market value of
our oil and natural gas commodity derivatives at December 31, 2009
was a $128.7 million net liability. See further discussion of our
derivative contracts and their market price sensitivities in
Market Risk Management below in this Managements Discussion and
Analysis of Financial Condition and Results of Operations, and in
Note 10 to the Consolidated Financial Statements. |
|
(g) |
|
Represents projected capital costs as scheduled in our December
31, 2009 proved reserve report that are necessary in order to
recover our proved oil and natural gas reserves. These are not
contractual commitments and are net of any other capital
obligations shown under Contractual Obligations in the table
above. |
|
(h) |
|
Represents projected capital costs as scheduled in our December
31, 2009 proved reserve report that are necessary in order to
recover our proved CO2 reserves from our CO2 source wells used to
produce CO2 for our tertiary operations. These are not contractual
commitments and are net of any other capital obligations shown
above. |
|
(i) |
|
Represents the estimated future asset retirement obligations on an
undiscounted basis. The present discounted asset retirement
obligation is $54.3 million, as determined under the Asset
Retirement and Environmental Obligations topic of the FASC, and
is further discussed in Note 4 to the Consolidated Financial
Statements. |
Long-term contracts require us to deliver CO2 to our industrial
CO2 customers at various contracted prices, plus we have a
CO2 delivery obligation to Genesis pursuant to three volumetric production
payments (VPPs) (see Note 3 to the Consolidated Financial Statements). Based upon the maximum
amounts deliverable as stated in the industrial contracts and the volumetric production payments,
we estimate that we may be obligated to deliver up to 433 Bcf of CO2 to these
customers over the next 18 years; however, since the group as a whole has historically taken
less CO2 than the maximum allowed in their contracts, based on the current
level of deliveries, we project that our commitment would likely be reduced to approximately 165
Bcf. The maximum volume required in any given year
47
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
is approximately 136 MMcf/d, although based on
our current level of deliveries this would likely be reduced to approximately 66 MMcf/d. Given the
size of our proved CO2 reserves at December 31, 2009 (approximately 6.3 Tcf
before deducting approximately 127.1 Bcf for the three VPPs), our current production capabilities
and our projected levels of CO2 usage for our own tertiary flooding program, we
believe that we will be able to meet these delivery obligations.
Results of Operations
CO2 Operations
Overview. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999,
we have gradually increased our emphasis on these types of operations. During this time, we have
learned a considerable amount about tertiary operations and working with carbon dioxide. Our
tertiary operations have grown to the point that approximately 65% of our December 31, 2009 proved
reserves are proved tertiary oil reserves, almost 65% of our forecasted 2010 production is expected
to come from tertiary oil operations (on a BOE basis), and almost all of our 2010 capital
expenditures are related to our current or future tertiary operations. We particularly like this
play as (i) it has a lower risk as we are working with oil fields that have significant historical
production and data, (ii) it provides a reasonable rate of return at relatively low oil prices (we
estimate our economic break-even before corporate overhead and expenses on these projects at
current oil prices is in the range of the mid-thirties, depending on the specific field and area),
and (iii) we have virtually no competition for this type of activity in our geographic area.
Generally, from East Texas to Florida, there are no known significant natural sources of
CO2 in the Gulf Coast area except our own, and these large volumes of
CO2 that we own drive the play. In addition, we are pursuing anthropogenic
(man-made) sources of CO2 to use in our tertiary operations, which we believe
will not only help us recover additional oil, but will provide an economical way to sequester
CO2. We have acquired several old oil fields in our areas of operations with
potential for tertiary recovery and plan to acquire additional fields, and we are continuing to
expand our CO2 pipeline infrastructure to transport CO2.
We talk about our tertiary operations by labeling operating areas or groups of fields as
Phases. Phase 1 is in Southwest Mississippi and includes several fields along our 183-mile NEJD
CO2 Pipeline that we acquired in 2001. The current tertiary fields in this
area are Little Creek, Mallalieu, McComb, Brookhaven and Lockhart Crossing. Phase 2, which began
with the early 2006 completion of the Free State CO2 Pipeline to East
Mississippi, includes Eucutta, Soso, Martinville and Heidelberg Fields. Tinsley Field, which is
located northwest of Jackson, Mississippi, and was acquired in January 2006, is our Phase 3 and is
serviced by that portion of the Delta CO2 Pipeline completed in January 2008.
Phase 4 includes Cranfield and Lake St. John Fields, two fields near the Mississippi/Louisiana
border located west of the Phase I fields, and Phase 5 is Delhi Field, a Louisiana field we
acquired in 2006, located southwest of Tinsley Field. Flooding in Phase 5 began in November 2009
upon completion of the Delta CO2 Pipeline from Tinsley to Delhi. Our first
tertiary oil response from Delhi Field is expected near mid-2010. Citronelle Field in Southwest
Alabama, another field acquired in 2006, is our Phase 6, which will require an extension to the
Free State CO2 Pipeline or another pipeline depending on the ultimate
CO2 source for this field, the timing of which is uncertain at this time. Our
last three currently existing phases will require completion of our proposed Green Pipeline, a
320-mile CO2 pipeline that will run from Southern Louisiana to near Houston,
Texas, and is scheduled for completion in 2010. Hastings Field, a field we purchased in February
2009 (see Commitments and Contingencies), is our Phase 7, the Seabreeze Complex, acquired in
2007, will be our Phase 8 and Conroe Field, a field we purchased in December 2009 (see Overview
Conroe Field Acquisition) will be our Phase 9. We anticipate initiating CO2
injections at Oyster Bayou Field (Phase 8) mid-2010 and at Hastings Field (Phase 7) late 2010 or
early 2011.
CO2 Resources. Since we acquired the Jackson Dome CO2
source field located near Jackson, Mississippi, in 2001, we have continued to develop the field and
have increased the proven CO2 reserves from approximately 800 Bcf at the time
of the acquisition to approximately 6.3 Tcf as of December 31, 2009. During 2009, we drilled one
additional CO2 source well, and we increased our CO2
reserves by approximately 1 Tcf, more than offsetting the 249 Bcf of CO2
produced during the year. The estimate of 6.3 Tcf of proved CO2 reserves is
based on 100% ownership
of the CO2 reserves, of which Denburys net revenue interest ownership is
approximately 5.0 Tcf. Both reserve estimates are included in the evaluation of proven
CO2 reserves prepared by DeGolyer and MacNaughton. In
48
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
discussing the available
CO2 reserves, we make reference to the gross amount of proved reserves, as this
is the amount that is available for Denburys tertiary recovery programs, industrial users, and
volumetric production payments with Genesis, as Denbury is responsible for distributing the entire
CO2 production stream for all of these uses. We currently estimate that it
will take approximately 2.2 Tcf of CO2 to develop and produce the proved
tertiary recovery reserves we have recorded at December 31, 2009, in Phases 1-4.
Today, we own every known producing CO2 well in the region, providing us a
significant strategic advantage in the acquisition of other properties in Mississippi, Louisiana
and Texas that could be further exploited through tertiary recovery. As of February 22, 2010, we
estimate that we are capable of producing approximately 1 Bcf/d of CO2,
approximately 9 times the rate that we were capable of producing at the time of our initial
acquisition in 2001. We continue to drill additional CO2 wells, with three
more wells planned for 2010 in order to further increase our proved CO2
reserves and production capacity. Our drilling activity at Jackson Dome will continue beyond 2010
as our current forecasts for the existing nine phases suggest that we will need approximately 1.4
Bcf/d of CO2 production by 2017.
In addition to using CO2 for our tertiary operations, we sell
CO2 to third party industrial users under long-term contracts. Most of these
industrial contracts have been sold to Genesis along with the sale of volumetric production
payments for the CO2. Our average daily CO2 production
during 2007, 2008 and 2009 was approximately 493 MMcf/d, 637 MMcf/d and 683 MMcf/d, respectively,
of which approximately 81% in 2007, 86% in 2008 and 87% in 2009 was used in our tertiary recovery
operations, with the balance delivered to Genesis under the volumetric production payments or sold
to third party industrial users. During February 2010, our CO2 production
averaged 800 MMcf/d.
We spent approximately $0.17 per Mcf in operating expenses to produce our CO2
during 2009, less than our 2008 average of $0.22 per Mcf and our 2007 average of $0.21 per Mcf,
with the decrease due primarily to decreased CO2 royalty expense as a result of
lower oil prices. Our CO2 costs peaked at $0.27 per Mcf in the second quarter of 2008,
corresponding to the peak in oil prices, but decreased during the fourth quarter of 2008 to an
average of approximately $0.15 per Mcf as a result of the decline in oil prices. Our estimated
total cost per thousand cubic feet of CO2 during 2009 was approximately $0.25 per Mcf,
after inclusion of depreciation and amortization expense related to the CO2 production,
as compared to approximately $0.30 per Mcf during 2008 and $0.29 per Mcf during 2007.
During 2009, we announced that we had initiated a comprehensive feasibility study of a
possible long-term CO2 pipeline project that would connect proposed gasification plants
in the Midwest to the Companys existing CO2 pipeline infrastructure in Mississippi or
Louisiana. Two of the proposed plants are in the term-sheet negotiation phase of a U.S. Department
of Energy Loan Guarantee Program (see Off-Balance Sheet Obligations Commitments and
Obligations) which still require successful finalization of negotiations with the Department of
Energy (DOE) to receive such guarantees. The Illinois Department of Commerce and Economic
Opportunity provided financial assistance for the feasibility study for the Illinois portion of the
pipeline. The feasibility study was undertaken to determine the most likely pipeline route, the
estimated costs of constructing such a pipeline, and review regulatory, legal and permitting
requirements. Our current preliminary estimates suggest this would be a 500- to 700-mile pipeline
system with a preliminary cost estimate of approximately $1.0 billion, based on the cost of other
pipelines we have recently built or have under construction. We have completed the initial
feasibility study of this Midwest pipeline, and are evaluating market conditions, potential
financing opportunities and construction of the proposed gasification projects. It is currently
uncertain whether or not we will build such a pipeline, but this future decision will be highly
dependent upon whether or not the proposed gasification plants will be constructed and the economic
feasibility of the overall project.
A third proposed gasification plant to be built along the Gulf Coast of Mississippi, for which
Denbury has a CO2 purchase contract, was also selected by the loan guarantee program.
The Company plans to commence a pipeline study for this proposed plant, which would likely be a
110-mile pipeline that connects to the existing Free State Pipeline.
In addition to our natural source of CO2 and the proposed gasification
plants discussed above (see Off-Balance Sheet Arrangements Commitments and Obligations), we
continue to have ongoing discussions with owners of existing plants of various types that emit
CO2 which we may be able to purchase. In order to capture such volumes,
49
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
we (or the plant owner) would need to install additional equipment, which includes at a
minimum, compression and dehydration facilities. Most of these existing plants emit relatively
small volumes of CO2, generally less than the proposed gasification plants, but
such volumes may still be attractive if the source is located near our Green Pipeline. The capture
of CO2 could also be influenced by potential federal legislation, which could
impose economic penalties for the emission of CO2. We believe that we are a
likely purchaser of CO2 produced in our area of operations because of the scale
of our tertiary operations, our CO2 pipeline infrastructure, and our large
natural source of CO2 (Jackson Dome), which can act as a swing
CO2 source to balance CO2 supply and demand.
Overview of Tertiary Economics. When we began our tertiary operations several years ago, they
were generally economic at oil prices below $20 per Bbl, although the economics varied by field.
Our costs have escalated during the last few years due to general cost inflation in the industry
and higher oil prices, and we estimate that our current break-even, before corporate overhead and
interest, is in the mid-thirties per barrel if oil prices remain at their current level
(approximately $70 per barrel). Our inception-to-date finding and development costs (including
future development and abandonment costs but excluding expenditures on fields without proven
reserves) for our tertiary oil fields through December 31, 2009, are approximately $12.68 per BOE.
Currently, we forecast that most of these costs will average less than $10 per BOE over the life of
each field, depending on the state of a particular field at the time we begin operations, the
amount of potential oil, the proximity to a pipeline or other facilities, and other factors. The
finding and development costs to date do not include additional probable reserves in fields with
current proved reserves. Our operating costs for tertiary operations are highly dependent on
commodity prices and could range from $15 per BOE to $25 per BOE over the life of each field, again
depending on the field itself.
While these economic factors have wide ranges, our rate of return from these operations has
generally been better than our rate of return on traditional oil and gas operations, and thus our
tertiary operations have become our single most important focus area. While it is extremely
difficult to accurately forecast future production, we do believe that our tertiary recovery
operations provide significant long-term production growth potential at reasonable rates of return,
with relatively low risk, and thus will be the backbone of our Companys growth for the foreseeable
future. Although we believe that our plans and projections are reasonable and achievable, there
could be delays or unforeseen problems in the future that could delay or affect the economics of
our overall tertiary development program. We believe that such delays or price effects, if any,
should only be temporary.
Financial Statement Impact of CO2 Operations. Our increasing
emphasis on CO2 tertiary recovery projects has significantly impacted, and will
continue to impact, our financial results and certain operating statistics. First, there is a
significant delay between the initial capital expenditures on these fields and the resulting
production increases, as we must build facilities, and often a CO2 pipeline to
the field before CO2 flooding can commence, and it usually takes six to 12
months before the field responds to the injection of CO2 (i.e., oil production
commences). Further, we may spend significant amounts of capital before we can recognize any
proven reserves from fields we flood (see Analysis of CO2 Tertiary Recovery
Operating Activities below). Even after a field has proven reserves, there will usually be
significant amounts of additional capital required to fully develop the field.
Second, tertiary projects may be more expensive to operate than other oil fields because of
the cost of injecting and recycling the CO2 (primarily due to the significant
energy requirements to re-compress the CO2 back into a near-liquid state for
re-injection purposes). Since a significant portion of our operating costs vary along with
commodity and electrical prices, these costs are highly variable and will increase in a high
commodity price environment and decrease in a low price environment. As an example (as discussed
above), during 2009 the cost of our CO2 varied from $0.13 per Mcf to $0.21 per
Mcf. Most of our CO2 operating costs are allocated to our tertiary oil fields
and recorded as lease operating expenses (following the commencement of tertiary oil production) at
the time the CO2 is injected, and these costs have historically represented
over 25% of the total operating costs for a tertiary operation. Since we expense all of the
operating costs to produce and inject our CO2 (following the commencement of
tertiary oil production), the operating costs per barrel will be higher at the inception of
CO2 injection projects because of minimal related oil production at that time.
Analysis of CO2 Tertiary Recovery Operating Activities. We currently have
tertiary operations ongoing at all Phase 1 fields, at Soso, Martinville, Eucutta and Heidelberg
Fields in Phase 2, Tinsley Field in Phase 3, Cranfield Field in Phase 4 and Delhi Field in Phase 5. We
project that our oil production from our CO2 operations will increase
substantially over the next several years as we continue to expand this program by adding
additional projects and
50
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
phases. As of December 31, 2009, we had approximately 134.5 MMBbls of
proved oil reserves related to tertiary operations (45.2 MMBbls in Phase 1, 44.6 MMBbls in Phase 2,
33.9 MMBbls in Phase 3 and 10.8 MMBbls in
Phase 4) representing about 65% of our total corporate proved reserves, and have identified
and estimate significant additional oil potential in other fields that we own in this region.
We
added 17.6 MMBbls of tertiary-related proved oil reserves during 2009, primarily initial
proven tertiary oil reserves at Cranfield Field in Phase 4, plus additional reserves at Tinsley,
Heidelberg and Eucutta Fields. In order to recognize proved tertiary oil reserves, we must either
have an oil production response to the CO2 injections or the field must be
analogous to an existing tertiary flood. The magnitude of proven reserves that we can book in any
given year will depend on our progress with new floods and the timing of the production response.
Our average annual oil production from our CO2 tertiary recovery
activities has increased during the last few years, from 3,970 Bbls/d in 2002 to 24,343 Bbls/d
during 2009 (26,307 Bbls/d during the fourth quarter of 2009). Tertiary oil production represented
approximately 66% of our total corporate oil production during 2009 and approximately 50% of our
total corporate production of both oil and natural gas during the same period on a BOE basis. We
expect that this tertiary related oil production will continue to increase, although the increases
are not always predictable or consistent. While we may have temporary fluctuation in oil
production related to tertiary operations, this usually does not indicate any issue with the proved
and potential oil reserves recoverable with CO2, because the historical
correlation between oil production and CO2 injections remains high. A detailed
discussion of each of our tertiary oil fields and the development of
each is included on pages 11-14
under Our Tertiary Oil Fields with Proved Tertiary Reserves. Following is a chart with our
tertiary oil production by field for 2007, 2008 and 2009, and by quarter for 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Year Ended December 31, |
Tertiary Oil Field |
|
2009 |
|
2009 |
|
2009 |
|
2009 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
Phase 1: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
3,451 |
|
|
|
3,466 |
|
|
|
3,397 |
|
|
|
3,350 |
|
|
|
|
3,416 |
|
|
|
2,826 |
|
|
|
2,048 |
|
Little Creek area |
|
|
1,619 |
|
|
|
1,560 |
|
|
|
1,356 |
|
|
|
1,479 |
|
|
|
|
1,502 |
|
|
|
1,683 |
|
|
|
2,014 |
|
Mallalieu area |
|
|
4,490 |
|
|
|
4,264 |
|
|
|
3,679 |
|
|
|
4,005 |
|
|
|
|
4,107 |
|
|
|
5,686 |
|
|
|
5,852 |
|
McComb area |
|
|
2,246 |
|
|
|
2,429 |
|
|
|
2,473 |
|
|
|
2,412 |
|
|
|
|
2,391 |
|
|
|
1,901 |
|
|
|
1,912 |
|
Lockhart Crossing |
|
|
607 |
|
|
|
698 |
|
|
|
882 |
|
|
|
1,025 |
|
|
|
|
804 |
|
|
|
186 |
|
|
|
|
|
Phase 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eucutta |
|
|
3,813 |
|
|
|
4,145 |
|
|
|
4,068 |
|
|
|
3,912 |
|
|
|
|
3,985 |
|
|
|
3,109 |
|
|
|
1,646 |
|
Heidelberg |
|
|
|
|
|
|
250 |
|
|
|
829 |
|
|
|
1,506 |
|
|
|
|
651 |
|
|
|
|
|
|
|
|
|
Martinville |
|
|
1,118 |
|
|
|
951 |
|
|
|
720 |
|
|
|
724 |
|
|
|
|
877 |
|
|
|
865 |
|
|
|
709 |
|
Soso |
|
|
2,705 |
|
|
|
2,589 |
|
|
|
2,813 |
|
|
|
3,224 |
|
|
|
|
2,834 |
|
|
|
2,111 |
|
|
|
586 |
|
Phase 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tinsley |
|
|
2,390 |
|
|
|
3,402 |
|
|
|
3,558 |
|
|
|
3,942 |
|
|
|
|
3,328 |
|
|
|
1,010 |
|
|
|
|
|
Phase 4: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cranfield |
|
|
144 |
|
|
|
338 |
|
|
|
572 |
|
|
|
728 |
|
|
|
|
448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
22,583 |
|
|
|
24,092 |
|
|
|
24,347 |
|
|
|
26,307 |
|
|
|
|
24,343 |
|
|
|
19,377 |
|
|
|
14,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tertiary operating expense per Bbl |
|
$ |
20.48 |
|
|
$ |
20.86 |
|
|
$ |
23.14 |
|
|
$ |
22.03 |
|
|
|
$ |
21.67 |
|
|
$ |
23.57 |
|
|
$ |
19.77 |
|
|
|
|
|
|
|
Oil production from our tertiary operations increased to an average of 24,343 Bbls/d
during 2009, a 26% increase over our 2008 tertiary production level of 19,377 Bbls/d. Tertiary oil
production during the fourth quarter of 2009 averaged 26,307 Bbls/d, a 20% increase over the fourth
quarter 2008 levels, and an 8% sequential increase from third quarter 2009 levels. These
year-over-year increases are the result of production growth in response to continued expansion of
the tertiary floods in our Tinsley, Soso, Eucutta and Brookhaven Fields, and to initial
51
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
production
response from Cranfield and Heidelberg Fields. We had our first production response from Cranfield
Field during the first quarter of 2009 and our first response from Heidelberg Field in the second
quarter of 2009, a little earlier than anticipated. Tinsley field has been one of our top
performing tertiary oil fields, and production there is expected to increase as we continue to
expand the flood. The declines at Mallalieu Field during the second
and third quarters of 2009 were partially due to CO2 recycle volumes
exceeding the plant capacity, which limited production volumes. We have expanded the capacity of
the facility, which expansion capacity became operational early in the fourth quarter of 2009.
Although we received an initial increase in production following completion of the facility, we
anticipate that production at Mallalieu Field will begin to decline again in the near future. The
Delhi pipeline is complete, and we initiated CO2 injections at Delhi Field
(Phase 5) during November 2009. We currently anticipate tertiary production response at Delhi Field
around mid-year 2010.
During 2009, operating costs for our tertiary properties averaged $21.67 per Bbl, lower than
the prior years average of $23.57 per Bbl. During the fourth quarter of 2009, the operating costs
on our tertiary properties averaged $22.03 per Bbl as compared to $21.86 per Bbl in the fourth
quarter of 2008 and $23.14 per Bbl during the third quarter of 2009. Our per barrel costs in 2009
are lower than in 2008 due primarily to the reduced cost of CO2 in the current
year period. On a per barrel basis, our cost of CO2 decreased by $1.99 per
Bbl, from $5.95 per Bbl in 2008 to $3.96 per Bbl in 2009, primarily due to the reduction in oil
prices to which our CO2 costs are partially tied. Our single highest cost for
our tertiary operations is our cost for fuel and utilities, which averaged $5.76 per Bbl in 2009,
$5.39 per Bbl in 2008 and $4.71 per Bbl in 2007, which has increased on a per barrel basis due to
continued expansion of our tertiary floods. For any specific field, we expect our tertiary lease
operating expense per BOE to be high initially, then decrease as production increases, ultimately
leveling off until production begins to decline in the latter life of the field, when lease
operating expense per BOE will again increase.
Through December 31, 2009, we have invested a total of $1.8 billion in tertiary fields
(including allocated acquisition costs and amounts assigned to Goodwill) and have only $225.7
million in unrecovered net cash flow (revenue less operating expenses and capital expenditures).
Of this total invested amount, approximately $487.4 million (27%) was spent on fields which have
yet to have appreciable proved reserves at December 31, 2009 (i.e., fields for which significant
incremental proved reserves are anticipated during 2010 and beyond). The proved oil reserves in
our CO2 fields have a PV-10 Value of $2.3 billion, using the calendar 2009
first-day-of-the-month 12-month unweighted average NYMEX pricing of $61.18 per Bbl. These amounts
do not include the capital costs or related depreciation and amortization of our
CO2 producing properties, but do include CO2 source field
lease operating costs and transportation costs.
CO2 Source Field and Tertiary Oil Field Related Capital Budget for 2010.
Our current capital spending plans for 2010 include approximately $74 million to be spent in the
Jackson Dome area with the intent to add CO2 reserves and deliverability for
future operations, approximately $365 million to be spent in development of our tertiary floods,
and approximately $159 million to be spent for our CO2 pipelines, making our combined
CO2
related expenditures over 90% of our $650 million 2010 capital budget.
Operating Results
As summarized in the Overview section above, and discussed in further detail below, our
operating results increased from 2007 to 2008, but decreased from 2008 to 2009. The primary factors
impacting our operating results were fluctuating commodity prices, changes in the fair value of our
oil and natural gas derivative contracts, and increases and decreases in production, which are all
explained in more detail below.
Certain of our operating results and statistics for each of the last three years are included
in the following table.
52
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands, except per share and unit data |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Operating results |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(75,156 |
) |
|
$ |
388,396 |
|
|
$ |
253,147 |
|
Net income (loss) per common share basic |
|
|
(0.30 |
) |
|
|
1.59 |
|
|
|
1.05 |
|
Net income (loss) per common share diluted |
|
|
(0.30 |
) |
|
|
1.54 |
|
|
|
1.00 |
|
Cash flow from operations |
|
|
530,599 |
|
|
|
774,519 |
|
|
|
570,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
36,951 |
|
|
|
31,436 |
|
|
|
27,925 |
|
Mcf/d |
|
|
68,086 |
|
|
|
89,442 |
|
|
|
97,141 |
|
BOE/d(1) |
|
|
48,299 |
|
|
|
46,343 |
|
|
|
44,115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
778,836 |
|
|
$ |
1,066,917 |
|
|
$ |
711,457 |
|
Natural gas sales |
|
|
87,873 |
|
|
|
280,093 |
|
|
|
241,331 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
866,709 |
|
|
$ |
1,347,010 |
|
|
$ |
952,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlement of derivative contracts |
|
$ |
146,734 |
|
|
$ |
(57,553 |
) |
|
$ |
20,480 |
|
Non-cash fair value adjustment income (expense) |
|
|
(382,960 |
) |
|
|
257,606 |
|
|
|
(39,077 |
) |
|
|
|
|
|
|
|
|
|
|
Total income (expense) from oil and natural gas
derivative contracts |
|
$ |
(236,226 |
) |
|
$ |
200,053 |
|
|
$ |
(18,597 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
326,132 |
|
|
$ |
307,550 |
|
|
$ |
230,932 |
|
Production taxes and marketing expenses (3) |
|
|
42,484 |
|
|
|
63,752 |
|
|
|
49,091 |
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
368,616 |
|
|
$ |
371,302 |
|
|
$ |
280,023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
13,422 |
|
|
$ |
13,858 |
|
|
$ |
13,630 |
|
CO2 operating expenses |
|
|
(4,649 |
) |
|
|
(4,216 |
) |
|
|
(4,214 |
) |
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
8,773 |
|
|
$ |
9,642 |
|
|
$ |
9,416 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices including impact of derivative settlements(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
68.63 |
|
|
$ |
90.04 |
|
|
$ |
68.84 |
|
Natural gas price per Mcf |
|
|
3.54 |
|
|
|
7.74 |
|
|
|
7.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices excluding impact of derivative settlements(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
57.75 |
|
|
$ |
92.73 |
|
|
$ |
69.80 |
|
Natural gas price per Mcf |
|
|
3.54 |
|
|
|
8.56 |
|
|
|
6.81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating revenues and expenses per BOE(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
49.16 |
|
|
$ |
79.42 |
|
|
$ |
59.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas lease operating expenses |
|
$ |
18.50 |
|
|
$ |
18.13 |
|
|
$ |
14.34 |
|
Oil and natural gas production taxes and marketing expense |
|
|
2.41 |
|
|
|
3.76 |
|
|
|
3.05 |
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
20.91 |
|
|
$ |
21.89 |
|
|
$ |
17.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (BOE). |
|
(2) |
|
See also Market Risk Management below for information concerning the Companys derivative transactions. |
|
(3) |
|
For 2009, 2008 and 2007, includes transportation expenses paid to Genesis of $7.9 million, $8.0 million and $6.0 million, respectively. |
|
(4) |
|
For 2009, 2008 and 2007, includes deferred revenue of $4.2 million, $4.5 million, and $4.4 million, respectively, associated with volumetric production
payments and transportation income of $5.5 million, $5.5 million and $5.2 million, respectively, both from Genesis. |
53
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production: Average daily production by area for 2009, 2008 and 2007, and each of the
quarters of 2009 is listed in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Year Ended December 31, |
Operating Area |
|
2009 |
|
2009 |
|
2009 |
|
2009 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
Tertiary oil fields |
|
|
22,583 |
|
|
|
24,092 |
|
|
|
24,347 |
|
|
|
26,307 |
|
|
|
|
24,343 |
|
|
|
19,377 |
|
|
|
14,767 |
|
Mississippi non-CO2 floods |
|
|
11,904 |
|
|
|
10,043 |
|
|
|
8,931 |
|
|
|
8,914 |
|
|
|
|
9,937 |
|
|
|
11,897 |
|
|
|
12,479 |
|
Texas |
|
|
17,063 |
|
|
|
16,088 |
|
|
|
7,579 |
|
|
|
8,035 |
|
|
|
|
12,154 |
|
|
|
13,214 |
|
|
|
10,074 |
|
Onshore Louisiana |
|
|
708 |
|
|
|
885 |
|
|
|
699 |
|
|
|
679 |
|
|
|
|
743 |
|
|
|
624 |
|
|
|
5,542 |
|
Alabama and other |
|
|
1,150 |
|
|
|
1,161 |
|
|
|
1,103 |
|
|
|
1,077 |
|
|
|
|
1,122 |
|
|
|
1,231 |
|
|
|
1,253 |
|
|
|
|
|
|
|
Total Company |
|
|
53,408 |
|
|
|
52,269 |
|
|
|
42,659 |
|
|
|
45,012 |
|
|
|
|
48,299 |
|
|
|
46,343 |
|
|
|
44,115 |
|
|
|
|
|
|
|
As outlined in the above table, production increased 1,956 BOE/d (4%) between 2008 and
2009, and 2,228 BOE/d (5%) between 2007 and 2008. The increase from 2008 to 2009 is due primarily
to a 26% increase in tertiary oil production and to the acquisition of Hastings Field, partially
offset by the sale of our Barnett Shale properties and to decreases in our Mississippi
non-CO2 floods. Excluding production from the Barnett Shale properties sold
during 2009, production would have averaged 38,760 BOE/d during 2009 and 33,643 BOE/d during 2008,
a 15% increase year-to-year. Our production increase between 2007 and 2008 was due to a 31%
increase in tertiary oil production and production increases in the Barnett Shale, partially offset
by the sale of our Louisiana natural gas properties and declines in our Mississippi
non-CO2 floods. The increase in our tertiary oil production is discussed above
under Results of Operations CO2 Operations.
The acquisition of Hastings Field in February 2009 added 1,956 BOE/d during 2009 to our Texas
area production. As discussed previously, we sold 60% of our interests in the Barnett Shale during
June and July 2009, and sold our remaining 40% interest in these properties during December 2009.
Production in the Mississippi non-tertiary operations decreased each of the last two years.
Production in this area decreased 5% from 2007 to 2008, and further decreased 16% from 2008 to
2009. Most of this decrease is due to the expected gradual decline in Heidelberg Field due to
depletion, although to a greater extent in 2009 due to the development of the Heidelberg
CO2 flood, which resulted in production being shut-in while portions of the
field were converted to tertiary operations. When production commences from these
CO2 floods, these volumes are reported as tertiary production for Heidelberg
Field. Also, production is lower in 2009 due to no drilling activity in the Selma Chalk. Our
drilling activity in Sharon Field (natural gas) in the latter part of 2008 helped offset the
declines in the first quarter of 2009, but production there has declined each of the last three
quarters of 2009, as we did not drill any additional wells in 2009.
Our production during 2009 was 77% oil as compared to 68% during 2008 and 63% during 2007.
This increase is due to the sale of our Louisiana natural gas assets during December 2007 and
February 2008, the sale of our Barnett Shale properties during 2009, the acquisition of Hastings
Field during February 2009, and to the increase in our tertiary operations each year. Pro forma
for the sale of the Barnett assets and the Conroe acquisition, fourth quarter 2009 production would
have been 91% oil.
Oil and Natural Gas Revenues: Fluctuating commodity prices resulted in an increase in
our oil and natural gas revenues between 2007 and 2008, but a decline between 2008 and 2009. Our
increasing production added to the revenue increase between 2007 and 2008, and partially offset the
revenue decrease from commodity prices between 2008 and 2009. These changes in revenues, excluding
any impact of our derivative contracts, are reflected in the following table.
54
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
|
|
2009 vs. 2008 |
|
|
2008 vs. 2007 |
|
|
|
|
|
|
|
Percentage |
|
|
|
|
|
|
Percentage |
|
|
|
Increase |
|
|
Increase |
|
|
Increase |
|
|
Increase |
|
|
|
(Decrease) in |
|
|
(Decrease) in |
|
|
(Decrease) in |
|
|
(Decrease) in |
|
In thousands |
|
Revenues |
|
|
Revenues |
|
|
Revenues |
|
|
Revenues |
|
Change in revenues due to: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in production |
|
$ |
53,051 |
|
|
|
4 |
% |
|
$ |
50,845 |
|
|
|
5 |
% |
Increase (decrease) in commodity
prices |
|
|
(533,352 |
) |
|
|
(40 |
%) |
|
|
343,377 |
|
|
|
36 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total increase
(decrease) in
revenues |
|
$ |
(480,301 |
) |
|
|
(36 |
%) |
|
$ |
394,222 |
|
|
|
41 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding any impact of our derivative contracts, our net realized commodity prices and NYMEX
differentials were as follows during 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Net
Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
57.75 |
|
|
$ |
92.73 |
|
|
$ |
69.80 |
|
Natural gas price per Mcf |
|
|
3.54 |
|
|
|
8.56 |
|
|
|
6.81 |
|
Price per BOE |
|
|
49.16 |
|
|
|
79.42 |
|
|
|
59.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX
Differentials: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(4.21 |
) |
|
$ |
(7.02 |
) |
|
$ |
(2.65 |
) |
Natural gas per Mcf |
|
|
(0.63 |
) |
|
|
(0.33 |
) |
|
|
(0.28 |
) |
|
|
|
|
|
|
|
|
|
|
Our Company-wide oil NYMEX differential improved during 2009 over our differential in 2008
primarily due to the overall decrease in oil prices during 2009. Likewise, our oil NYMEX
differential widened during 2008 as compared to 2007, due to the overall increase in oil prices,
with a peak in our differential during the second quarter of 2008, corresponding with the peak in
oil prices. Our oil NYMEX differential was also positively impacted during 2009 due to reduced
natural gas liquids production as a result of the sale of our Barnett Shale properties, which
historically have a significantly higher differential to NYMEX
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas
prices during the month, as most of our natural gas is sold on an index price that is set near the
first of each month. While the percentage change in NYMEX natural gas differentials can be quite
large, these differentials are very seldom more than a dollar above or below NYMEX prices.
Oil and Natural Gas Derivative Contracts: The following table summarizes the impact our
oil and natural gas derivative contracts had on our operating results for 2009, 2008 and 2007.
55
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Cash Fair Value |
|
|
Cash Settlements |
|
|
|
Gain/(Loss) |
|
|
Receipt/(Payment) |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Crude oil derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
(95,861 |
) |
|
$ |
2,638 |
|
|
$ |
(2,802 |
) |
|
$ |
85,836 |
|
|
$ |
(7,392 |
) |
|
$ |
126 |
|
Second quarter |
|
|
(189,318 |
) |
|
|
(7,557 |
) |
|
|
(905 |
) |
|
|
42,002 |
|
|
|
(12,131 |
) |
|
|
(1,108 |
) |
Third quarter |
|
|
(20,850 |
) |
|
|
22,652 |
|
|
|
(2,481 |
) |
|
|
18,527 |
|
|
|
(11,186 |
) |
|
|
(3,018 |
) |
Fourth quarter |
|
|
(69,721 |
) |
|
|
242,156 |
|
|
|
(8,289 |
) |
|
|
369 |
|
|
|
(260 |
) |
|
|
(5,834 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
year-to-date |
|
$ |
(375,750 |
) |
|
$ |
259,889 |
|
|
$ |
(14,477 |
) |
|
$ |
146,734 |
|
|
$ |
(30,969 |
) |
|
$ |
(9,834 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
(10,490 |
) |
|
$ |
(41,371 |
) |
|
$ |
(32,356 |
) |
|
$ |
|
|
|
$ |
(656 |
) |
|
$ |
8,125 |
|
Second quarter |
|
|
(5,473 |
) |
|
|
(22,666 |
) |
|
|
14,235 |
|
|
|
|
|
|
|
(16,463 |
) |
|
|
2,827 |
|
Third quarter |
|
|
(1,434 |
) |
|
|
63,427 |
|
|
|
(2,960 |
) |
|
|
|
|
|
|
(12,886 |
) |
|
|
12,432 |
|
Fourth quarter |
|
|
10,187 |
|
|
|
(1,673 |
) |
|
|
(3,519 |
) |
|
|
|
|
|
|
3,421 |
|
|
|
6,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
year-to-date |
|
$ |
(7,210 |
) |
|
$ |
(2,283 |
) |
|
$ |
(24,600 |
) |
|
$ |
|
|
|
$ |
(26,584 |
) |
|
$ |
30,314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
(106,351 |
) |
|
$ |
(38,733 |
) |
|
$ |
(35,158 |
) |
|
$ |
85,836 |
|
|
$ |
(8,048 |
) |
|
$ |
8,251 |
|
Second quarter |
|
|
(194,791 |
) |
|
|
(30,223 |
) |
|
|
13,330 |
|
|
|
42,002 |
|
|
|
(28,594 |
) |
|
|
1,719 |
|
Third quarter |
|
|
(22,284 |
) |
|
|
86,079 |
|
|
|
(5,441 |
) |
|
|
18,527 |
|
|
|
(24,072 |
) |
|
|
9,414 |
|
Fourth quarter |
|
|
(59,534 |
) |
|
|
240,483 |
|
|
|
(11,808 |
) |
|
|
369 |
|
|
|
3,161 |
|
|
|
1,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
year-to-date |
|
$ |
(382,960 |
) |
|
$ |
257,606 |
|
|
$ |
(39,077 |
) |
|
$ |
146,734 |
|
|
$ |
(57,553 |
) |
|
$ |
20,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in commodity prices and the expiration of contracts cause fluctuations in the
estimated fair value of our oil and natural gas derivative contracts. Because we do not utilize
hedge accounting for our commodity derivative contracts, the changes in fair value of these
contracts, as outlined above, are recognized currently in our income statement.
Production Expenses: Our lease operating expenses have increased each year on both a
per BOE basis and in absolute dollars primarily as a result of (i) our increasing emphasis on
tertiary operations and additional tertiary fields moving into the productive phase (see discussion
of those expenses under CO2 Operations above), (ii) the acquisition of Hastings Field in February
2009, which has a higher operating cost per BOE than most of our other properties, (iii) increased
personnel and related costs, (iv) higher electrical costs to operate our properties due primarily
to the expansion of our tertiary operations, (v) increasing lease payments due to incremental
leasing of certain equipment in our tertiary operating facilities, and (vi) on a per BOE basis for
2009, the mid-year sale of our Barnett Shale natural gas properties, as these properties had a
lower per unit operating cost.
Company-wide lease operating expense per BOE averaged $18.50 per BOE, $18.13 per BOE and
$14.34 per BOE during 2009, 2008 and 2007, respectively. On a pro forma basis, after adjusting our
operating results to remove the Barnett Shale production and operating expenses, Company-wide lease
operating expenses would have been $21.94 per BOE during 2009, $23.02 per BOE during 2008 and
$17.07 per BOE during 2007. Our tertiary operating costs, which have historically been higher than
our company-wide operating costs, averaged $21.67 per BOE during 2009, $23.57 per BOE during 2008
and $19.77 per BOE during 2007 (see Results of Operations CO2 Operations
for a more detailed discussion). As our tertiary operations become a larger percentage of our
total operations, we expect that our operating costs on a per BOE basis will become closer to our
tertiary operating costs, or higher as much of our conventional oil production, which is in
decline, is at a higher per barrel cost than our tertiary operations. Costs of electricity and
utilities to operate our properties have increased due primarily to the expansion of our tertiary
operations. We expect our tertiary operating costs to partially correlate with oil prices, as the
price we pay for CO2 is partially tied to oil prices.
56
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production taxes and marketing expenses generally change in proportion to commodity prices and
production volumes, and as such, decreased 33% between 2008 and 2009, correlating with the 36%
decrease in total revenues between the two years and increased between 2007 and 2008 as a result of
higher commodity prices. Transportation and plant processing fees were approximately $3.6 million
lower in 2009 than 2008 primarily due to the sale of Barnett Shale properties in mid-2009, and were
$8.4 million higher in 2008 than 2007 due to incremental Barnett Shale production and plant
processing fees in 2008.
General and Administrative Expenses
During the last three years, general and administrative (G&A) expenses have increased on
both a gross basis and on a per BOE basis as outlined in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands, except per BOE data and employees |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Gross cash G&A expense |
|
$ |
143,886 |
|
|
$ |
121,209 |
|
|
$ |
103,334 |
|
Employee stock-based compensation |
|
|
24,322 |
|
|
|
16,243 |
|
|
|
12,185 |
|
Founders retirement |
|
|
10,000 |
|
|
|
|
|
|
|
|
|
Incentive compensation for Genesis management |
|
|
14,212 |
|
|
|
|
|
|
|
|
|
Acquisition expenses |
|
|
8,921 |
|
|
|
527 |
|
|
|
|
|
State franchise taxes |
|
|
4,703 |
|
|
|
3,415 |
|
|
|
2,915 |
|
Operator labor and overhead recovery charges |
|
|
(76,044 |
) |
|
|
(68,556 |
) |
|
|
(59,145 |
) |
Capitalized exploration and development costs |
|
|
(13,905 |
) |
|
|
(12,464 |
) |
|
|
(10,317 |
) |
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
116,095 |
|
|
$ |
60,374 |
|
|
$ |
48,972 |
|
|
|
|
|
|
|
|
|
|
|
G&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash G&A expense |
|
$ |
3.27 |
|
|
$ |
2.58 |
|
|
$ |
2.30 |
|
Net stock-based compensation |
|
|
1.16 |
|
|
|
0.75 |
|
|
|
0.56 |
|
Founders retirement |
|
|
0.57 |
|
|
|
|
|
|
|
|
|
Incentive compensation for Genesis management |
|
|
0.81 |
|
|
|
|
|
|
|
|
|
Acquisition expenses |
|
|
0.51 |
|
|
|
0.03 |
|
|
|
|
|
State franchise tax |
|
|
0.27 |
|
|
|
0.20 |
|
|
|
0.18 |
|
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
6.59 |
|
|
$ |
3.56 |
|
|
$ |
3.04 |
|
|
|
|
|
|
|
|
|
|
|
Employees as of December 31 |
|
|
830 |
|
|
|
797 |
|
|
|
686 |
|
|
|
|
|
|
|
|
|
|
|
Gross cash G&A expenses increased $22.7 million, or 19% between 2008 and 2009, and $17.9
million, or 17%, between 2007 and 2008. The increases are primarily due to higher compensation and
personnel related costs caused by an increase in the number of employees and higher wages, which we
consider necessary in order to remain competitive in our industry. During 2008, we increased our
employee count by 16%, and we further increased our employee count 4% during 2009, although our
employee count was higher for part of 2009 before the sale of a portion of our Barnett Shale
properties in mid-2009. Stock compensation expense reflected in gross G&A was $24.3 million during
2009, $16.2 million during 2008 and $12.2 million during 2007, due primarily to the
increase in employees and changes in the mix of compensation awarded to employees. As discussed
above in Overview Mid-Year Management Changes, we also expensed $10.0 million in the second
quarter of 2009 related to a Founders Retirement Agreement for Gareth Roberts, as he retired as
CEO and President of the Company on June 30, 2009.
Also adding to the increase in net G&A expense for 2009 was a charge relating to incentive
compensation awards for the management of Genesis of $14.2 million. As incentive compensation for
Genesis management, our former subsidiary which is the general partner of Genesis Energy, LP,
awarded management the right to earn an interest in the incentive distributions we receive. These
awards were subject to vesting over four years and achieving future levels of cash available before
reserves on a per unit basis, among other conditions. As discussed above under Overview Sale of
Interests in General Partner of Genesis Energy, L.P., Denbury sold its
interest in the general partner of Genesis on February 5, 2010. As such, the change in
57
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
control provision of each members compensation agreement was triggered and the awards were
settled for $14.9 million in cash in February 2010. See also Note 15, Subsequent Events to the
Consolidated Financial Statements for further information regarding these incentive compensation
awards and the sale of our interest in the Genesis general partner.
In addition to the increased compensation and other personnel related costs discussed above,
an $8.4 million increase in acquisition related expenses also contributed to the increase in net
G&A expense between 2008 and 2009. FASC Business Combinations topic requires that all transaction
related costs (legal, accounting, due diligence, etc.) be expensed as incurred. As such, Denbury
has recognized a total of $8.9 million of G&A expense in 2009 related primarily to transaction
costs associated with the Encore acquisition.
The increase in gross G&A expense in each of the last three years was offset in part by an
increase in operator overhead recovery charges. Our well operating agreements allow us, when we
are the operator, to charge a well with a specified overhead rate during the drilling phase and
also to charge a monthly fixed overhead rate for each producing well. As a result of additional
operated wells from acquisitions, additional tertiary operations, drilling activity during the past
year, and increased compensation expense, the amount we recovered as operator labor and overhead
charges increased by 11% between 2008 and 2009, and 16% between 2007 and 2008. Capitalized
exploration and development costs also increased each year, primarily due to additional personnel
and increased compensation costs.
The net effect of the increases in gross G&A expenses, operator overhead recoveries and
capitalized exploration costs was a 92% increase in net G&A expense between 2008 and 2009, and a
23% increase in net G&A expense between 2007 and 2008. On a per BOE basis, net G&A expense also
increased each year, but at a lower percentage rate due to increased production, with an 85%
increase in G&A per BOE in 2009 as compared 2008, and a 17% increase in 2008 as compared to 2007.
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands, except per BOE data and interest rates |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Cash interest expense |
|
$ |
108,629 |
|
|
$ |
59,955 |
|
|
$ |
49,205 |
|
Non-cash interest expense |
|
|
7,397 |
|
|
|
1,802 |
|
|
|
2,010 |
|
Less: Capitalized interest |
|
|
(68,596 |
) |
|
|
(29,161 |
) |
|
|
(20,385 |
) |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
47,430 |
|
|
$ |
32,596 |
|
|
$ |
30,830 |
|
|
|
|
|
|
|
|
|
|
|
Interest income and other |
|
$ |
2,362 |
|
|
$ |
4,834 |
|
|
$ |
6,642 |
|
Net cash interest expense and other income per BOE (1) |
|
$ |
2.14 |
|
|
$ |
1.59 |
|
|
$ |
1.43 |
|
Average debt outstanding |
|
$ |
1,265,142 |
|
|
$ |
735,288 |
|
|
$ |
672,376 |
|
Average interest rate (2) |
|
|
8.6 |
% |
|
|
8.2 |
% |
|
|
7.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Cash interest expense less capitalized interest less interest and other income on BOE basis. |
|
(2) |
|
Includes commitment fees but excludes debt issue costs and amortization of discount and premium. |
Interest expense increased $14.8 million, or 46%, between 2009 and 2008 and $1.8 million,
or 6%, between 2007 and 2008. The increase in interest expense between 2008 and 2009 is due
primarily to the February 2009 issuance of $420 million of 9.75% Senior Subordinated Notes due
2016, and to a full year of interest expense recognized during 2009 on the pipeline dropdown
transactions with Genesis, as compared to only seven months of interest recognized on the dropdowns
during 2008. This increase in interest expense between 2008 and 2009 was largely offset by a $39.4
million increase in capitalized interest, primarily relating to interest capitalized on our Green
Pipeline currently under construction. The increase in interest expense
between 2007 and 2008 was due primarily to the pipeline dropdown transactions with Genesis
mid-2008, which were recorded as capital leases.
The increase in our average debt outstanding in 2009 as compared to 2008 is due the issuance
of $420 million Senior Subordinated Notes due 2016, the pipeline dropdown transactions with
Genesis, and to increased bank borrowings, primarily to fund our acquisitions.
58
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation and Amortization (DD&A) and Full Cost Ceiling Test Write-down
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands, except per BOE data |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Depletion and depreciation of oil and natural gas properties |
|
$ |
203,719 |
|
|
$ |
192,791 |
|
|
$ |
174,356 |
|
Depletion and depreciation of CO2 assets |
|
|
18,052 |
|
|
|
15,644 |
|
|
|
11,609 |
|
Asset retirement obligations |
|
|
3,280 |
|
|
|
3,048 |
|
|
|
2,977 |
|
Depreciation of other fixed assets |
|
|
13,272 |
|
|
|
10,309 |
|
|
|
6,958 |
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
238,323 |
|
|
$ |
221,792 |
|
|
$ |
195,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
11.74 |
|
|
$ |
11.55 |
|
|
$ |
11.02 |
|
CO2 assets and other fixed assets |
|
|
1.78 |
|
|
|
1.53 |
|
|
|
1.15 |
|
|
|
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
13.52 |
|
|
$ |
13.08 |
|
|
$ |
12.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Full cost ceiling test write-down |
|
$ |
|
|
|
$ |
226,000 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
We adjust our DD&A rate each quarter for significant changes in our estimates of oil and
natural gas reserves and costs, and thus our DD&A rate could change significantly in the future.
Our DD&A rate for oil and natural gas properties on a per BOE basis increased slightly between 2008
and 2009 and increased approximately 5% between 2007 and 2008, due primarily to capital spending
and increasing costs. Our proved reserves increased from 194.7 MMBOE as of December 31, 2007, to
250.5 MMBOE as of December 31, 2008, and decreased to 207.5 MMBOE as of December 31, 2009, due
primarily to the sale of our Barnett Shale properties during 2009.
During 2009, we added approximately 48.8 MMBOE of proved reserves (before netting out 2009
production and property sales). The most significant additions were
approximately 17.6 MMBOE
related to our tertiary operations, 18.4 MMBOE related to the acquisition of Conroe Field, and 9.6
MMBOE related to the acquisition of Hastings Field. In the second quarter of 2009, we booked
approximately 10.9 million barrels of incremental oil reserves related to our tertiary operations
at Cranfield Field, as a result of the oil production response to the CO2
injections in that field. Correspondingly, we moved approximately $82.4 million from unevaluated
properties to the full cost pool relating to Cranfield Field, representing the acquisition costs
and development expenditures incurred on the field prior to recognizing proved reserves
Our DD&A rate for our CO2 and other fixed assets increased approximately
16% between 2008 and 2009, as a result of the Heidelberg CO2 pipeline being
placed into service during 2008, expansion of our corporate offices during 2008, and field office
expansion during 2009. At December 31, 2009, we had $779.1 million of costs related to
CO2 pipelines under construction. These costs were not being depreciated at
December 31, 2009. Depreciation of these pipelines will commence as each segment of pipeline is
placed into service. Our DD&A rate for our CO2 and other fixed assets
increased in 2008 as compared to 2007, due primarily to the Heidelberg CO2
pipeline being placed into service during 2008, drilling costs for additional
CO2 wells, and the expansion of our corporate office space in 2008.
As part of the requirements of the FASB guidance under the Accounting for Asset Retirement
Obligations topic of the FASC, the fair value of a liability for an asset retirement obligation is
recorded in the period in which it is incurred, discounted to its present value using our credit
adjusted risk-free interest rate, with a corresponding capitalized amount. The liability is
accreted each period, and the capitalized cost is depreciated over the useful life of the related
asset. On an undiscounted basis, we estimated our retirement obligations at December 31, 2007 to
be $100.6 million ($41.3 million present value), with an estimated salvage value of $67.3 million,
and as of December 31, 2008, we estimated our retirement obligations to be $106.4 million ($45.1
million present value), with an estimated salvage value of $76.4 million, the increase related to
2008 activity and higher cost estimates due to the inflation in our industry, partially offset by a
decrease in our obligation of approximately $9.5 million, ($9.3 million present value) related to
the sale of most of our Louisiana natural gas properties in late 2007 and early 2008. As of
December 31, 2009, we estimated our retirement obligations to be
$134.5 million ($54.3 million
present value), with
59
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
an estimated salvage value of $81.4 million. The increase in our asset retirement obligations
during 2009 was due to the acquisition of the Hastings and Conroe Fields, partially offset by the
disposition of our Barnett Shale assets. DD&A is calculated on the increase in retirement
obligations recorded as incremental oil and natural gas and CO2 properties, net of its
estimated salvage value. We also include the accretion of discount on the asset retirement
obligation in our DD&A expense.
Under full cost accounting rules, we are required each quarter to perform a ceiling test
calculation. As a result of depressed oil and natural gas prices at December 31, 2008, we recorded
our first full cost ceiling test write-down in a decade, resulting in expense of $226.0 million or
$13.32 per BOE at December 31, 2008. The SEC adopted major revisions to its rules governing oil and
gas company reporting requirements which were effective for us beginning on December 31, 2009.
Under these new rules, the full cost ceiling value will be calculated using a 12-month average
price based on the first day of every month during the period. We did not have a ceiling test
write-down December 31, 2009. However, if oil prices were to decrease significantly in subsequent
periods, we may be required to record additional write-downs under the full cost pool ceiling test
in the future. The possibility and amount of any future write-down is difficult to predict, and
will depend upon oil and natural gas prices, the incremental proved reserves that may be added each
period, revisions to previous estimates of reserves and future capital expenditures, and
additional capital spent.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Amounts in thousands, except per BOE amounts and tax rates |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Current income tax expense |
|
$ |
4,611 |
|
|
$ |
40,812 |
|
|
$ |
30,074 |
|
Deferred income tax expense (benefit) |
|
|
(51,644 |
) |
|
|
195,020 |
|
|
|
110,193 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit) |
|
$ |
(47,033 |
) |
|
$ |
235,832 |
|
|
$ |
140,267 |
|
|
|
|
|
|
|
|
|
|
|
Average income tax expense (benefit) per BOE |
|
$ |
(2.67 |
) |
|
$ |
13.90 |
|
|
$ |
8.71 |
|
Effective tax rate |
|
|
38.5 |
% |
|
|
37.8 |
% |
|
|
35.7 |
% |
Total net deferred tax liability |
|
$ |
(469,195 |
) |
|
$ |
(522,234 |
) |
|
$ |
(334,662 |
) |
|
|
|
|
|
|
|
|
|
|
Our income tax provision for each of the last three years has been based on an estimated
statutory rate of approximately 38%. Our effective tax rate has generally been slightly lower than
our estimated statutory rate due to the impact of certain items such as our domestic production
activities deduction, offset in part by compensation arising from certain equity compensation that
cannot be deducted for tax purposes in the same manner as book expense. Our 2009 effective tax
rate was slightly higher, however, as compared to our statutory rate due to the recognition of net
tax benefits related to the sale of our Barnett Shale assets. During 2009, 2008 and 2007, the
current income tax expense represents our anticipated alternative minimum cash taxes that we cannot
offset with enhanced oil recovery credits. As of December 31, 2009, we had an estimated $39
million of enhanced oil recovery credits to carry forward that can be utilized to reduce our
current income taxes during 2010 or future years. These enhanced oil recovery credits do not begin
to expire until 2024. Since the ability to earn additional enhanced oil recovery credits is based
upon the level of oil prices, we would not currently expect to earn additional enhanced oil
recovery credits unless oil prices were to decrease significantly from current levels.
In
the second quarter of 2008, we obtained approval from the Internal Revenue Service (IRS)
to change our method of tax accounting for certain assets used in our tertiary oilfield recovery
operations. Although the overall effects of this accounting change are under audit, we expect to
receive tax refunds of approximately $10.6 million for tax years through 2007, along with other
deferred tax benefits, and in the second quarter of 2008 we reduced our current income tax expense
by approximately $19 million to adjust for the impact of this change through the first six months
of 2008. The reduction in current income tax expense has been offset by a corresponding increase
in deferred income tax expense of approximately the same amount. Although this change is not
expected to have a significant impact on the Companys overall tax rate, it is anticipated that it
could defer the amount of cash taxes the Company might otherwise pay over the next several years.
The current administration in Washington D.C. is attempting to remove many tax incentives for the
oil and gas industry. Those items that would have the most significant impact on us would include
the loss of the domestic manufacturing deduction as well as the repeal of the
60
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
immediate expensing of intangible drilling costs and tertiary injectant costs. It is
uncertain whether or not the current administration will be successful in changing the laws, but if
they were successful, it would likely increase the amount of cash taxes that we pay.
Per BOE Data
The following table summarizes our cash flow, DD&A and results of operations on a per BOE
basis for the comparative periods. Each of the individual components is discussed above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Per BOE data |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Oil and natural gas revenues |
|
$ |
49.16 |
|
|
$ |
79.42 |
|
|
$ |
59.17 |
|
Gain (loss) on settlements of derivative contracts |
|
|
8.32 |
|
|
|
(3.40 |
) |
|
|
1.27 |
|
Lease operating expenses |
|
|
(18.50 |
) |
|
|
(18.13 |
) |
|
|
(14.34 |
) |
Production taxes and marketing expenses |
|
|
(2.41 |
) |
|
|
(3.76 |
) |
|
|
(3.05 |
) |
|
|
|
|
|
|
|
|
|
|
Production netback |
|
|
36.57 |
|
|
|
54.13 |
|
|
|
43.05 |
|
Non-tertiary CO2 operating margin |
|
|
0.50 |
|
|
|
0.57 |
|
|
|
0.58 |
|
General and administrative expenses |
|
|
(6.59 |
) |
|
|
(3.56 |
) |
|
|
(3.04 |
) |
Net cash interest expense and other income |
|
|
(2.14 |
) |
|
|
(1.59 |
) |
|
|
(1.43 |
) |
Abandoned acquisition costs |
|
|
|
|
|
|
(1.80 |
) |
|
|
|
|
Current income taxes and other |
|
|
2.30 |
|
|
|
(1.78 |
) |
|
|
(1.37 |
) |
Changes in assets and liabilities relating to operations |
|
|
(0.54 |
) |
|
|
(0.31 |
) |
|
|
(2.38 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flow from operations |
|
|
30.10 |
|
|
|
45.66 |
|
|
|
35.41 |
|
DD&A |
|
|
(13.52 |
) |
|
|
(13.08 |
) |
|
|
(12.17 |
) |
Write-down of oil and natural gas properties |
|
|
|
|
|
|
(13.32 |
) |
|
|
|
|
Deferred income taxes |
|
|
2.93 |
|
|
|
(11.50 |
) |
|
|
(6.84 |
) |
Non-cash commodity derivative adjustments |
|
|
(21.72 |
) |
|
|
15.19 |
|
|
|
(2.43 |
) |
Changes in assets and liabilities and other non-cash items |
|
|
(2.05 |
) |
|
|
(0.05 |
) |
|
|
1.75 |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(4.26 |
) |
|
$ |
22.90 |
|
|
$ |
15.72 |
|
|
|
|
|
|
|
|
|
|
|
Market Risk Management
Debt
We finance some of our acquisitions and other expenditures with fixed and variable rate debt.
These debt agreements expose us to market risk related to changes in interest rates. We had $125
million of bank debt outstanding as of December 31, 2009. The carrying value of our bank debt is
approximately fair value based on the fact that it is subject to short-term floating interest rates
that approximate the rates available to us for those periods. We adjusted the estimated fair value
measurements of our bank debt at December 31, 2009, for estimated nonperformance risk. This
estimated nonperformance risk totaled approximately $2.5 million and was determined utilizing
industry credit default swaps. None of our existing debt has any triggers or covenants regarding
our debt ratings with rating agencies, although under the NEJD financing lease with Genesis (see
Note 3, Related Party Transactions Genesis to our Consolidated Balance Sheets) in the event of
significant downgrades of our corporate credit rating by the rating agencies, Genesis can require
certain credit enhancements from us, and possibly other remedies under the lease. The fair value
of the subordinated debt is based on quoted market prices. The following table presents the
carrying and fair values of our debt, along with average interest rates at December 31, 2009.
61
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
|
Carrying |
|
|
Fair |
|
In thousands |
|
2011 |
|
|
2013 |
|
|
2015 |
|
|
2016 |
|
|
Value |
|
|
Value |
|
|
|
|
|
|
|
|
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt (weighted average
interest rate of 1.49% at December 31,
2009) |
|
$ |
125,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
125,000 |
|
|
$ |
122,500 |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due 2013 |
|
|
|
|
|
|
225,000 |
|
|
|
|
|
|
|
|
|
|
|
224,369 |
|
|
|
226,125 |
|
(fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due 2015 |
|
|
|
|
|
|
|
|
|
|
300,000 |
|
|
|
|
|
|
|
300,513 |
|
|
|
299,250 |
|
(fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.75% subordinated debt due 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
426,350 |
|
|
|
399,926 |
|
|
|
455,129 |
|
(fixed rate of 9.75%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Derivative Contracts
From time to time, we enter into various oil and natural gas derivative contracts to provide
an economic hedge of our exposure to commodity price risk associated with anticipated future oil
and natural gas production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have consisted of price floors, collars and fixed price swaps. The
production that we hedge has varied from year to year depending on our levels of debt and financial
strength and expectation of future commodity prices. In early 2009, we began to employ a strategy
to hedge a portion of our production looking out 12 to 15 months from each quarter, as we believe
it is important to protect our future cash flow to provide a level of assurance for our capital
spending in those future periods in light of current worldwide economic uncertainties. However, as
a result of our plan to acquire Encore and the potentially higher debt levels necessary to finance
that merger, we entered into costless collars in early November 2009, to hedge a significant
portion of our production through 2011. See Note 10 to the Consolidated Financial Statements for
details regarding our derivative contracts.
All of the mark-to-market valuations used for our oil and natural gas derivatives are provided
by external sources and are based on prices that are actively quoted. We manage and control market
and counterparty credit risk through established internal control procedures that are reviewed on
an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal
credit policies, monitoring procedures and diversification. All of our derivative contracts are
with parties that are lenders under our Senior Bank Loan. We have included an estimate of
nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts.
We have measured nonperformance risk based upon credit default swaps or credit spreads. At
December 31, 2009 and December 31, 2008, the fair value of our oil and natural gas derivative
contracts was reduced by $0.8 million and $3.7 million, respectively, for estimated nonperformance
risk.
For accounting purposes, we do not apply hedge accounting to our oil and natural gas
derivative contracts. This means that any changes in the fair value of these derivative contracts
will be charged to earnings on a quarterly basis instead of charging the effective portion to other
comprehensive income and the ineffective portion to earnings. Information regarding our current
derivative contract positions and results of our historical derivative activity is included in Note
10 to the Consolidated Financial Statements.
At December 31, 2009, our derivative contracts were recorded at their fair value, which was a
net liability of approximately $128.7 million, a significant change from the $249.7 million fair
value asset recorded at December 31, 2008. This change is primarily related to the expiration of
oil derivative contracts during 2009, and to the oil and natural gas futures prices as of December
31, 2009, in relation to the new commodity derivative contracts we entered into during 2009 for
2010 and 2011.
Commodity Derivative Sensitivity Analysis
Based on NYMEX crude oil and natural gas futures prices as of December 31, 2009, and assuming
both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude
oil and natural gas derivative contracts as seen in the following table:
62
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
Natural Gas |
|
|
|
Derivative |
|
|
Derivative |
|
|
|
Contracts |
|
|
Contracts |
|
|
|
Receipt/ |
|
|
Receipt/ |
|
In thousands |
|
(Payment) |
|
|
(Payment) |
|
Based on: |
|
|
|
|
|
|
|
|
NYMEX futures prices as of December 31, 2009 |
|
$ |
(85,193 |
) |
|
$ |
(2,813 |
) |
10% increase in prices |
|
|
(148,189 |
) |
|
|
(17,310 |
) |
10% decrease in prices |
|
|
(45,653 |
) |
|
|
11,692 |
|
|
|
|
|
|
|
|
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with generally accepted accounting
principles requires that we select certain accounting policies and make certain estimates and
judgments regarding the application of those policies. Our significant accounting policies are
included in Note 1 to the Consolidated Financial Statements. These policies, along with the
underlying assumptions and judgments by our management in their application, have a significant
impact on our consolidated financial statements. Following is a discussion of our most critical
accounting estimates, judgments and uncertainties that are inherent in the preparation of our
financial statements.
Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Reserves
Businesses involved in the production of oil and natural gas are required to follow accounting
rules that are unique to the oil and gas industry. We apply the full-cost method of accounting for
our oil and natural gas properties. Another acceptable method of accounting for oil and gas
production activities is the successful efforts method of accounting. In general, the primary
differences between the two methods are related to the capitalization of costs and the evaluation
for asset impairment. Under the full cost method, all geological and geophysical costs,
exploratory dry holes and delay rentals are capitalized to the full cost pool, whereas under the
successful efforts method such costs are expensed as incurred. In the assessment of impairment of
oil and gas properties, the successful efforts method follows the FASB guidance under the,
Accounting for the Impairment or Disposal of Long-Lived Assets topic of the FASC, under which the
net book value of assets is measured for impairment against the undiscounted future cash flows
using commodity prices consistent with management expectations. Under the full cost method, the
full cost pool (net book value of oil and gas properties) is measured against future cash flows
discounted at 10% using the average first-day-of-the-month oil and natural gas price for each month
during the 12-month period ended as of each quarterly reporting period. The financial results for
a given period could be substantially different depending on the method of accounting that an oil
and gas entity applies. Further, we do not designate our oil and natural gas derivative contracts
as hedge instruments for accounting purposes under the FASC hedge accounting topic, and as a
result, these contracts are not considered in the full cost ceiling test.
We make significant estimates at the end of each period related to accruals for oil and gas
revenues, production, capitalized costs and operating expenses. We calculate these estimates with
our best available data, which includes, among other things, production reports, price posting,
information compiled from daily drilling reports and other internal tracking devices, and analysis
of historical results and trends. While management is not aware of any required revisions to its
estimates, there will likely be future adjustments resulting from such things as changes in
ownership interests, payouts, joint venture audits, re-allocations by the purchaser/pipeline, or
other corrections and adjustments common in the oil and natural gas industry, many of which will
require retroactive application. These types of adjustments cannot be currently estimated or
determined and will be recorded in the period during which the adjustment occurs.
Under full cost accounting, the estimated quantities of proved oil and natural gas reserves
used to compute depletion and the related present value of estimated future net cash flows
therefrom used to perform the full cost ceiling test have a significant impact on the underlying
financial statements. The process of estimating oil and natural gas reserves is very complex,
requiring significant decisions in the evaluation of all available geological, geophysical,
engineering and economic data. The data for a given field may also change substantially over time
as a result of numerous factors, including additional development activity, evolving production
history and continued
reassessment of the viability of production under varying economic conditions. As a result,
material revisions to
63
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
existing reserve estimates may occur from time to time. Although every
reasonable effort is made to ensure that the reported reserve estimates represent the most accurate
assessments possible, including the hiring of independent engineers to prepare the report, the
subjective decisions and variances in available data for various fields make these estimates
generally less precise than other estimates included in our financial statement disclosures. Over
the last four years, Denburys annual revisions to its reserve estimates have averaged
approximately 1.9% of the previous years estimates and have been both positive and negative.
Changes in commodity prices also affect our reserve quantities. Between 2006 and 2007, the
change to reserve quantities related to commodity prices was relatively small as prices were
relatively high each year-end; however, at December 31, 2008, the lower commodity prices lowered
our proved reserves by 13.8 MMBOE. Between 2008 and 2009, commodity prices increased, resulting in
an increase in our proved reserves of 4.2 MMBOE. These changes in quantities affect our DD&A rate,
and the combined effect of changes in quantities and commodity prices impacts our full cost ceiling
test calculation. For example, we estimate that a 5% increase in our estimate of proved reserves
quantities would have lowered our fourth quarter 2009 DD&A rate from $14.77 per BOE to
approximately $14.19 per BOE, and a 5% decrease in our proved reserve quantities would have
increased our DD&A rate to approximately $15.42 per BOE. Also, reserve quantities and their
ultimate values are the primary factors in determining the borrowing base under our bank credit
facility and are determined solely by our banks.
Under full cost accounting rules, we are required each quarter to perform a ceiling test
calculation. We did not have a full cost pool ceiling test write-down
in 2007 or 2009. However, during
2008, commodity prices were volatile, with oil NYMEX prices moving from $95.98 per Bbl at December
31, 2007, to $140.00 per Bbl at June 30, 2008, then down to $44.60 per Bbl at December 31, 2008.
Likewise, natural gas NYMEX prices went from $7.48 per Mcf as of December 31, 2007, to $13.35 per
Mcf at June 30, 2008, and down to $5.62 per Mcf as of December 31, 2008. Because of the 54%
decrease in NYMEX oil price and 25% decrease in NYMEX natural gas price between year-end 2007 and
year-end 2008, we recognized a full cost pool ceiling test write-down during 2008 of $226.0
million, or $13.32 per BOE. Commodity prices increased throughout 2009, ending the year with NYMEX
oil prices at $79.36 per barrel, and NYMEX natural gas prices at $5.57 per Mcf. Commodity prices
have historically been volatile and are expected to be in the future. If oil and natural gas
should again decrease, we may be required to record additional write-downs due to the full cost
ceiling test. Beginning in the fourth quarter of 2009, the full cost accounting rules require the
use of the average first-day-of-the-month oil and natural gas price for each month during the
12-month period ended as of each quarterly reporting period. The amount of any future write-down
is difficult to predict and will depend upon the oil and natural gas prices utilized in the ceiling
test, the incremental proved reserves that might be added during each period and additional capital
spent.
Tertiary Injection Costs
Our tertiary operations are conducted in reservoirs that have already produced significant
amounts of oil over many years; however, in accordance with the rules for recording proved
reserves, we cannot recognize proved reserves associated with enhanced recovery techniques such as
CO2 injection, until there is a production response to the injected CO2, or
unless the field is analogous to an existing flood. Our costs associated with the CO2
we produce (or acquire) and inject are principally our costs of production, transportation and
acquisition, and to pay royalties.
Prior to January 1, 2008, we expensed currently all costs associated with injecting
CO2 that we used in our tertiary recovery operations, even though some of these costs
were incurred prior to any tertiary related oil production. Commencing January 1, 2008, we began
capitalizing, as a development cost, injection costs in fields that are in their development stage,
which means we have not yet seen incremental oil production due to the CO2 injections
(i.e., a production response). These capitalized development costs will be included in our
unevaluated property costs if there are not already proved tertiary reserves in that field. After
we see a production response to the CO2 injections (i.e., the production stage),
injection costs will be expensed as incurred and any previously deferred unevaluated development
costs will become subject to depletion upon recognition of proved tertiary reserves. Had the new
method of accounting for tertiary injection costs been used in periods prior to January 1, 2008,
the effect on our financial statements would have been immaterial for all periods presented.
During 2008 and 2009, we capitalized $10.4 million and $8.0 million, respectively, of tertiary
injection costs associated with our tertiary projects that we would have previously expensed.
64
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Income Taxes
We make certain estimates and judgments in determining our income tax expense for financial
reporting purposes. These estimates and judgments occur in the calculation of certain tax assets
and liabilities that arise from differences in the timing and recognition of revenue and expense
for tax and financial reporting purposes. Our federal and state income tax returns are generally
not prepared or filed before the consolidated financial statements are prepared; therefore, we
estimate the tax basis of our assets and liabilities at the end of each period as well as the
effects of tax rate changes, tax credits, and net operating loss carryforwards. Adjustments
related to these estimates are recorded in our tax provision in the period in which we file our
income tax returns. Further, we must assess the likelihood that we will be able to recover or
utilize our deferred tax assets (primarily our enhanced oil recovery credits and state loss
carryforwards). If recovery is not likely, we must record a valuation allowance against such
deferred tax assets for the amount we would not expect to recover, which would result in an
increase to our income tax expense. As of December 31, 2009, we believe that all of our deferred
tax assets recorded on our Consolidated Balance Sheet will ultimately be recovered. If our
estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax
provision would increase in the period it is determined that recovery is not likely. A 1% increase
in our effective tax rate would have increased our calculated income tax expense
(benefit) by approximately $(1.2) million, $6.2 million, and $3.9 million for the years ended
December 31, 2009, 2008 and 2007, respectively. See Note 7 to the Consolidated Financial
Statements and see Income Taxes above for further information concerning our income taxes.
Fair Value Estimates
The FASC defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. It does not require us to make any new fair value
measurements, but rather establishes a fair value hierarchy that prioritizes the inputs to the
valuation techniques used to measure fair value. Level 1 inputs are given the highest priority in
the fair value hierarchy, as they represent observable inputs that reflect unadjusted quoted prices
for identical assets or liabilities in active markets as of the reporting date, while Level 3
inputs are given the lowest priority, as they represent unobservable inputs that are not
corroborated by market data. Valuation techniques that maximize the use of observable inputs are
favored. See Note 11 to the Consolidated Financial Statements for disclosures regarding our
recurring fair value measurements.
Significant uses of fair value measurements include:
|
|
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allocation of the purchase price paid to acquire businesses to the
assets acquired and liabilities assumed in those acquisitions, |
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|
|
|
assessment of impairment of long-lived assets, |
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assessment of impairment of goodwill, and |
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recorded value of derivative instruments. |
Acquisitions
Under the acquisition method of accounting for business combinations, the purchase price paid
to acquire a business is allocated to its assets and liabilities based on the estimated fair values
of the assets acquired and liabilities assumed as of the date of acquisition. FASC Business
Combinations topic defines the acquisition date as the date on which the acquirer obtains control
of the acquiree, which is usually a date different than the date the economics of the acquisition
are established between the acquirer and the acquiree. FASC Fair Value Measurements and
Disclosures topic defines fair value as the price that would be received to sell an asset or paid
to transfer a liability in an orderly transaction between market participants at the measurement
date (often referred to as the exit price). A fair value measurement is based on the assumptions
of market participants and not those of the reporting entity. Therefore, entity-specific intentions
do not impact the measurement of fair value unless those assumptions are consistent with market
participant views.
65
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
The excess of the purchase price over the fair value of the net tangible and identifiable
intangible assets acquired is recorded as goodwill. A significant amount of judgment is involved in
estimating the individual fair values involving property, plant and equipment and identifiable
intangible assets. This is even more difficult due to the nature of our core business, enhanced
oil recovery operations. In order to appropriately apply the FASC standard, we must estimate what
value a third party market participant would place on the acquired property. This is extremely
difficult as we are one of few industry entities that perform EOR operations and in our current
operating area, the Gulf Coast, we are the only entity that we know of that currently has a
significant source of CO2 available to them. Therefore, it is very subjective
as to what value another entity would place on the potential barrels recoverable with
CO2, which impacts our allocation of the purchase price to goodwill,
unevaluated properties and proved properties. Although we find that this standard is difficult to
apply in our circumstance, we use all available information to make these fair value determinations
and, for certain acquisitions, engage third-party consultants for assistance.
The fair values used to allocate the purchase price of an acquisition are often estimated
using the expected present value of future cash flows method, which requires us to project related
future cash inflows and outflows and apply an appropriate discount rate. The estimates used in
determining fair values are based on assumptions believed to be reasonable but which are inherently
uncertain. Accordingly, actual results may differ from the projected results used to determine fair
value.
Impairment Assessment of Goodwill
We test goodwill for impairment annually during the fourth quarter, or between annual tests if
an event occurs or circumstances change that would more likely than not reduce the fair value of a
reporting unit below its carrying amount. The need to test for impairment can be based on several
indicators, including a significant reduction in prices of oil or natural gas, a full-cost ceiling
write-down of oil and natural gas properties, unfavorable adjustments to reserves, significant
changes in the expected timing of production, other changes to contracts or changes in the
regulatory environment. The pending Merger, if approved, will likely result in a significant
increase to our existing goodwill.
Goodwill is tested for impairment at the reporting unit level. Denbury applies SEC full-cost
accounting rules, under which the acquisition cost of oil and gas properties is recognized on a
cost center basis (country), of which Denbury has only one cost center (United States). Goodwill is
assigned to this single reporting unit.
Fair value calculated for the purpose of testing for impairment of our goodwill is estimated
using the expected present value of future cash flows method and comparative market prices when
appropriate. A significant amount of judgment is involved performing these fair value estimates for
goodwill since the results are based on forecasted assumptions. Significant assumptions include
projections of future oil and natural gas prices, projections of estimated quantities of oil and
natural gas reserves, projections of future rates of production, timing and amount of future
development and operating costs, projected availability and cost of CO2, projected
recovery factors of tertiary reserves, and risk-adjusted discount rates. We base our fair value
estimates on projected financial information which we believe to be reasonable. However, actual
results may differ from those projections.
Oil and Natural Gas Derivative Contracts
We enter into oil and natural gas derivative contracts to mitigate our exposure to commodity
price risk associated with future oil and natural gas production. These contracts have
historically consisted of options, in the form of price floors or collars, and fixed price swaps.
We do not designate these derivative commodity contracts as hedge instruments for accounting
purposes under the FASC hedge accounting topic. This means that any changes in the future fair
value of these derivative contracts will be charged to earnings on a quarterly basis instead of
charging the effective portion to other comprehensive income and the balance to earnings. While we
may experience more volatility in our net income than if we were to apply hedge accounting
treatment as permitted by the FASC hedge accounting topic, we believe that for us the benefits
associated with applying hedge accounting do not outweigh the cost, time and effort to comply with
hedge accounting. During 2009, 2008 and 2007, we recognized expense (income) of $383.0 million,
$(257.6) million, and $39.1 million, respectively, related to non-cash changes in the fair market
value of our derivative contracts.
66
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Stock Compensation Plans
The FASB guidance under the Share-Based Payment topic of the FASC, requires that we
recognize the cost of employee services received in exchange for awards of equity instruments,
based on the grant date fair value of those awards, in the financial statements. We estimate the
fair value of stock option or stock appreciation right (SAR) awards on the date of grant using
the Black-Scholes option pricing model. The Black-Scholes option valuation model requires the
input of somewhat subjective assumptions, including expected stock price volatility and expected
term. Other assumptions required for estimating fair value with the Black-Scholes model are the
expected risk-free interest rate and expected dividend yield of the Companys stock. The risk-free
interest rates used are the U.S. Treasury yield for bonds matching the expected term of the option
on the date of grant. Our dividend yield is zero, as Denbury does not pay a dividend. We utilize
historical experience in arriving at our assumptions for volatility and expected term inputs.
We recognize the stock-based compensation expense on a straight-line basis over the requisite
service period for the entire award. The expense we recognize is net of estimated forfeitures. We
estimate our forfeiture rate based on prior experience and true it up for actual results as the
awards vest. As of December 31, 2009, there was $18.8 million of total compensation cost to be
recognized in future periods related to non-vested stock options and SARs. The cost is expected to
be recognized over a weighted-average period of 2.5 years.
Asset Retirement Obligations
We have significant obligations related to the plugging and abandonment of our oil, natural
gas and CO2 wells, the removal of equipment and facilities from leased acreage, and land
restoration. The FASC asset retirement topic requires that we estimate the future cost of this
obligation, discount it to its present value, and record a corresponding asset and liability in our
Consolidated Balance Sheets. The values ultimately derived are based on many significant
estimates, including the ultimate expected cost of the obligation, the expected future date of the
required cash payment, and interest and inflation rates. Revisions to these estimates may be
required based on changes to cost estimates, the timing of settlement, and changes in legal
requirements. Any such changes that result in upward or downward revisions in the estimated
obligation will result in an adjustment to the related capitalized asset and corresponding
liability on a prospective basis and an adjustment in our DD&A expense in future periods. See Note
4 to our Consolidated Financial Statements for further discussion regarding our asset retirement
obligations.
Use of Estimates
The preparation of financial statements requires us to make other estimates and assumptions
that affect the reported amounts of certain assets, liabilities, revenues and expenses during each
reporting period. We believe that our estimates and assumptions are reasonable and reliable, and
believe that the ultimate actual results will not differ significantly from those reported;
however, such estimates and assumptions are subject to a number of risks and uncertainties, and
such risks and uncertainties could cause the actual results to differ materially from our
estimates.
Recent Accounting Pronouncements
Transfers of Financial Assets. In June 2009, the FASB issued guidance related to the
accounting for transfers of financial assets. The guidance removes the concept of a qualifying
special-purpose entity (QSPE) from FASC topic, Transfers and Servicing, creates a new unit of
account definition that must be met for transfers of portions of financial assets to be eligible
for sale accounting, clarifies the de-recognition criteria for a transfer to be accounted for as a
sale, changes the amount of recognized gains or losses on the transfer of financial assets
accounted for as a sale when beneficial interests are received by the transferor and introduces new
disclosure requirements. The new guidance is effective for us beginning January 1, 2010. The
adoption did not have a material impact on our financial condition or results of operations.
Consolidation of Variable Interest Entities. In June 2009, the FASB issued guidance to
eliminate the exemption in the Consolidation topic of the FASC for QSPEs, introduce a new
approach for determining who should consolidate a variable interest entity and change the
requirement as to when it is necessary to reassess who should consolidate a variable interest
entity. We adopted the standard on January 1, 2010. The adoption did not have a material impact on
our financial condition or results of operations.
67
Denbury Resources Inc.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Fair Value Disclosures. In January 2010, the FASB issued guidance in the Fair Value
Measurements and Disclosures topic of the FASC to enhance disclosures surrounding the transfers of
assets in and out of level 1 and level 2, to present more detail surrounding asset activity for
level 3 assets and to clarify existing disclosure requirements. The new guidance is effective for
the Company beginning January 1, 2010, and will not have any impact on our financial position or
statement of operations.
Forward-Looking Information
The statements contained in this Annual Report on Form 10-K that are not historical facts,
including, but not limited to, statements found in this Managements Discussion and Analysis of
Financial Condition and Results of Operations, are forward-looking statements, as that term is
defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a
number of risks and uncertainties, and are subject to the impact of the Merger with Encore on the
results of operations and financial condition of the combined company. Such forward-looking
statements may be or may concern, among other things, forecasted capital expenditures, drilling
activity or methods, acquisition plans and proposals and dispositions, development activities, cost
savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve
quantities and values, CO2 reserves, potential reserves from tertiary operations,
hydrocarbon prices, pricing or cost assumptions based on current and projected oil and gas prices,
liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters,
mark-to-market values, competition, long-term forecasts of production, finding costs, rates of
return, estimated costs, or changes in costs, future capital expenditures and overall economics and
other variables surrounding our operations and future plans. Such forward-looking statements
generally are accompanied by words such as plan, estimate, expect, predict, anticipate,
projected, should, assume, believe, target or other words that convey the uncertainty of
future events or outcomes. Such forward-looking information is based upon managements current
plans, expectations, estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated actions, the timing of
such actions and the Companys financial condition and results of operations. As a consequence,
actual results may differ materially from expectations, estimates or assumptions expressed in or
implied by any forward-looking statements made by or on behalf of the Company. Among the factors
that could cause actual results to differ materially are: fluctuations of the prices received or
demand for the Companys oil and natural gas; unexpected difficulties in integrating the operations
of Denbury and Encore; effects of our indebtedness; success of our risk management techniques;
inaccurate cost estimates; availability of and fluctuations in the prices of goods and services;
the uncertainty of drilling results and reserve estimates; operating hazards; disruption of
operations and damages from hurricanes or tropical storms; acquisition risks; requirements for
capital or its availability; conditions in the financial and credit markets; general economic
conditions; competition and government regulations; and unexpected delays, as well as the risks and
uncertainties inherent in oil and gas drilling and production activities or which are otherwise
discussed in this annual report, including, without limitation, the portions referenced above, and
the uncertainties set forth from time to time in the Companys other public reports, filings and
public statements.
68
Denbury Resources Inc.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The information required by Item 7A is set forth under Market Risk Management in
Managements Discussion and Analysis of Financial Condition and Results of Operations, appearing
on pages 61 through 63.
Item 8. Financial Statements and Supplementary Data
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Page |
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70 |
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71 |
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72 |
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73 |
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74 |
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75 |
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76 |
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110 |
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115 |
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69
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Denbury Resources Inc.:
In our opinion, the consolidated financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Denbury Resources Inc. and its
subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2009, in conformity with
accounting principles generally accepted in the United States of America. Also in our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2009, based on criteria established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The
Companys management is responsible for these financial statements, for maintaining effective
internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in Managements Report on Internal Control over
Financial Reporting under Item 9A. Our responsibility is to express opinions on these financial
statements and on the Companys internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was maintained in all
material respects. Our audits of the financial statements included examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall
financial statement presentation. Our audit of internal control over financial reporting included
obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a
reasonable basis for our opinions.
As
discussed in Note 1 and Note 16 to the Consolidated Financial
Statements, the Company changed the manner in which it estimates the
quantities of oil and natural gas reserves in 2009.
A companys internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting
principles. A companys internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the companys assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to future periods
are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
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/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
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Dallas, Texas |
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March 1, 2010 |
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70
Denbury Resources Inc.
Consolidated Balance Sheets
(In thousands, except shares)
|
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|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Assets |
|
Current assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
20,591 |
|
|
$ |
17,069 |
|
Accrued production receivable |
|
|
120,667 |
|
|
|
67,805 |
|
Trade and other receivables, net of allowance of $414 and $377 |
|
|
67,874 |
|
|
|
80,579 |
|
Derivative assets |
|
|
309 |
|
|
|
249,746 |
|
Current deferred tax assets |
|
|
46,321 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
255,762 |
|
|
|
415,199 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment |
|
|
|
|
|
|
|
|
Oil and natural gas properties (using full cost accounting) |
|
|
|
|
|
|
|
|
Proved |
|
|
3,595,726 |
|
|
|
3,386,606 |
|
Unevaluated |
|
|
320,356 |
|
|
|
235,403 |
|
CO2 properties, equipment and pipelines |
|
|
1,529,781 |
|
|
|
899,542 |
|
Other |
|
|
82,537 |
|
|
|
70,328 |
|
Less accumulated depletion, depreciation and impairment |
|
|
(1,825,528 |
) |
|
|
(1,589,682 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
3,702,872 |
|
|
|
3,002,197 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deposits on property under option or contract |
|
|
|
|
|
|
48,917 |
|
Other assets |
|
|
66,810 |
|
|
|
43,357 |
|
Goodwill |
|
|
169,517 |
|
|
|
|
|
Investment in Genesis |
|
|
75,017 |
|
|
|
80,004 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
4,269,978 |
|
|
$ |
3,589,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
Current liabilities |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
169,874 |
|
|
$ |
202,633 |
|
Oil and gas production payable |
|
|
90,218 |
|
|
|
85,833 |
|
Derivative liabilities |
|
|
124,320 |
|
|
|
|
|
Deferred revenue Genesis |
|
|
4,070 |
|
|
|
4,070 |
|
Deferred tax liability |
|
|
|
|
|
|
89,024 |
|
Current maturities of long-term debt |
|
|
5,308 |
|
|
|
4,507 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
393,790 |
|
|
|
386,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities |
|
|
|
|
|
|
|
|
Long-term debt Genesis |
|
|
249,762 |
|
|
|
251,047 |
|
Long-term debt |
|
|
1,051,306 |
|
|
|
601,720 |
|
Asset retirement obligations |
|
|
53,251 |
|
|
|
43,352 |
|
Deferred revenue Genesis |
|
|
15,749 |
|
|
|
19,957 |
|
Deferred tax liability |
|
|
515,516 |
|
|
|
433,210 |
|
Derivative liabilities |
|
|
5,239 |
|
|
|
|
|
Other |
|
|
13,128 |
|
|
|
14,253 |
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
1,903,951 |
|
|
|
1,363,539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 12) |
|
|
|
|
|
|
|
|
Stockholders equity |
|
|
|
|
|
|
|
|
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding |
|
|
|
|
|
|
|
|
Common stock, $.001 par value, 600,000,000 shares authorized; 261,929,292 and
248,005,874 shares issued at December 31, 2009 and 2008, respectively |
|
|
262 |
|
|
|
248 |
|
Paid-in capital in excess of par |
|
|
910,540 |
|
|
|
707,702 |
|
Retained earnings |
|
|
1,064,419 |
|
|
|
1,139,575 |
|
Accumulated other comprehensive loss |
|
|
(557 |
) |
|
|
(627 |
) |
Treasury stock, at cost, 156,284 and 446,287 shares at December 31, 2009
and 2008, respectively |
|
|
(2,427 |
) |
|
|
(6,830 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
1,972,237 |
|
|
|
1,840,068 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
4,269,978 |
|
|
$ |
3,589,674 |
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
71
Denbury Resources Inc.
Consolidated Statements of Operations
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Revenues and other income |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and related product sales |
|
$ |
866,709 |
|
|
$ |
1,347,010 |
|
|
$ |
952,788 |
|
CO2 sales and transportation fees |
|
|
13,422 |
|
|
|
13,858 |
|
|
|
13,630 |
|
Interest income and other |
|
|
2,362 |
|
|
|
4,834 |
|
|
|
6,642 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
882,493 |
|
|
|
1,365,702 |
|
|
|
973,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
326,132 |
|
|
|
307,550 |
|
|
|
230,932 |
|
Production taxes and marketing expenses |
|
|
34,580 |
|
|
|
55,770 |
|
|
|
43,130 |
|
Transportation expense Genesis |
|
|
7,904 |
|
|
|
7,982 |
|
|
|
5,961 |
|
CO2 operating expenses |
|
|
4,649 |
|
|
|
4,216 |
|
|
|
4,214 |
|
General and administrative |
|
|
116,095 |
|
|
|
60,374 |
|
|
|
48,972 |
|
Interest, net of amounts capitalized of $68,596, $29,161, and
$20,385, respectively |
|
|
47,430 |
|
|
|
32,596 |
|
|
|
30,830 |
|
Depletion, depreciation and amortization |
|
|
238,323 |
|
|
|
221,792 |
|
|
|
195,900 |
|
Commodity derivative expense (income) |
|
|
236,226 |
|
|
|
(200,053 |
) |
|
|
18,597 |
|
Abandoned acquisition costs |
|
|
|
|
|
|
30,601 |
|
|
|
|
|
Write-down of oil and natural gas properties |
|
|
|
|
|
|
226,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
1,011,339 |
|
|
|
746,828 |
|
|
|
578,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in net income (loss) of Genesis |
|
|
6,657 |
|
|
|
5,354 |
|
|
|
(1,110 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(122,189 |
) |
|
|
624,228 |
|
|
|
393,414 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision (benefit) |
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes |
|
|
4,611 |
|
|
|
40,812 |
|
|
|
30,074 |
|
Deferred income taxes |
|
|
(51,644 |
) |
|
|
195,020 |
|
|
|
110,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(75,156 |
) |
|
$ |
388,396 |
|
|
$ |
253,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic |
|
$ |
(0.30 |
) |
|
$ |
1.59 |
|
|
$ |
1.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share diluted |
|
$ |
(0.30 |
) |
|
$ |
1.54 |
|
|
$ |
1.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
246,917 |
|
|
|
243,935 |
|
|
|
240,065 |
|
Diluted |
|
|
246,917 |
|
|
|
252,530 |
|
|
|
252,101 |
|
See accompanying Notes to Consolidated Financial Statements.
72
Denbury Resources Inc.
Consolidated Statements of Cash Flows
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(75,156 |
) |
|
$ |
388,396 |
|
|
$ |
253,147 |
|
Adjustments needed to reconcile to net cash flow provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
238,323 |
|
|
|
221,792 |
|
|
|
195,900 |
|
Write-down of oil and natural gas properties |
|
|
|
|
|
|
226,000 |
|
|
|
|
|
Deferred income taxes |
|
|
(51,644 |
) |
|
|
195,020 |
|
|
|
110,193 |
|
Deferred revenue Genesis |
|
|
(4,208 |
) |
|
|
(4,466 |
) |
|
|
(4,419 |
) |
Stock-based compensation |
|
|
35,581 |
|
|
|
14,068 |
|
|
|
10,595 |
|
Non-cash fair value derivative adjustments |
|
|
383,072 |
|
|
|
(257,502 |
) |
|
|
38,952 |
|
Founders retirement compensation |
|
|
6,350 |
|
|
|
|
|
|
|
|
|
Other |
|
|
7,719 |
|
|
|
(3,499 |
) |
|
|
4,149 |
|
Changes in assets and liabilities related to operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Accrued production receivable |
|
|
(52,863 |
) |
|
|
68,479 |
|
|
|
(63,886 |
) |
Trade and other receivables |
|
|
12,548 |
|
|
|
(58,236 |
) |
|
|
(10,409 |
) |
Derivative assets |
|
|
|
|
|
|
(15,471 |
) |
|
|
|
|
Other assets |
|
|
(426 |
) |
|
|
348 |
|
|
|
(819 |
) |
Accounts payable and accrued liabilities |
|
|
25,673 |
|
|
|
254 |
|
|
|
1,576 |
|
Oil and gas production payable |
|
|
4,385 |
|
|
|
1,683 |
|
|
|
31,906 |
|
Other liabilities |
|
|
1,245 |
|
|
|
(2,347 |
) |
|
|
3,329 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
530,599 |
|
|
|
774,519 |
|
|
|
570,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow used for investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas capital expenditures |
|
|
(343,351 |
) |
|
|
(587,968 |
) |
|
|
(621,187 |
) |
Acquisitions of oil and natural gas properties |
|
|
(452,795 |
) |
|
|
(31,367 |
) |
|
|
(49,077 |
) |
CO2 capital expenditures, including pipelines |
|
|
(666,372 |
) |
|
|
(407,103 |
) |
|
|
(164,075 |
) |
Investment in Genesis |
|
|
4,975 |
|
|
|
6,623 |
|
|
|
(47,738 |
) |
Purchases of other assets |
|
|
(13,591 |
) |
|
|
(23,799 |
) |
|
|
(13,672 |
) |
Proceeds from sales of oil and gas properties and equipment |
|
|
516,814 |
|
|
|
51,684 |
|
|
|
142,667 |
|
Other |
|
|
(15,394 |
) |
|
|
(2,729 |
) |
|
|
(9,431 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(969,714 |
) |
|
|
(994,659 |
) |
|
|
(762,513 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(856,000 |
) |
|
|
(222,000 |
) |
|
|
(265,000 |
) |
Bank borrowings |
|
|
906,000 |
|
|
|
147,000 |
|
|
|
281,000 |
|
Income tax benefit from equity awards |
|
|
3,913 |
|
|
|
19,665 |
|
|
|
19,181 |
|
Issuance of subordinated debt |
|
|
389,827 |
|
|
|
|
|
|
|
150,750 |
|
Pipeline financing Genesis |
|
|
369 |
|
|
|
225,252 |
|
|
|
|
|
Issuance of common stock |
|
|
12,991 |
|
|
|
13,972 |
|
|
|
18,222 |
|
Costs of debt financing |
|
|
(10,080 |
) |
|
|
(2,288 |
) |
|
|
(1,988 |
) |
Other |
|
|
(4,383 |
) |
|
|
(4,499 |
) |
|
|
(3,632 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
442,637 |
|
|
|
177,102 |
|
|
|
198,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
3,522 |
|
|
|
(43,038 |
) |
|
|
6,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
17,069 |
|
|
|
60,107 |
|
|
|
53,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
20,591 |
|
|
$ |
17,069 |
|
|
$ |
60,107 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
73
Denbury Resources Inc.
Consolidated Statements of Changes in Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paid-In |
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
Common Stock |
|
Capital in |
|
|
|
|
|
Other |
|
Treasury Stock |
|
Total |
|
|
($.001 Par Value) |
|
Excess of |
|
Retained |
|
Comprehensive |
|
(at cost) |
|
Stockholders |
Dollar amounts in thousands |
|
Shares |
|
Amount |
|
Par |
|
Earnings |
|
Income (Loss) |
|
Shares |
|
Amount |
|
Equity |
|
Balance December 31, 2006 |
|
|
120,506,815 |
|
|
$ |
121 |
|
|
$ |
616,046 |
|
|
$ |
498,032 |
|
|
$ |
|
|
|
|
370,327 |
|
|
$ |
(8,140 |
) |
|
$ |
1,106,059 |
|
Repurchase of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74,130 |
|
|
|
(2,960 |
) |
|
|
(2,960 |
) |
Issued pursuant to employee
stock purchase plan |
|
|
|
|
|
|
|
|
|
|
2,099 |
|
|
|
|
|
|
|
|
|
|
|
(149,360 |
) |
|
|
2,947 |
|
|
|
5,046 |
|
Issued pursuant to employee
stock option plan |
|
|
2,071,940 |
|
|
|
2 |
|
|
|
13,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,176 |
|
Issued pursuant to
directors compensation plan |
|
|
3,981 |
|
|
|
|
|
|
|
136 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
136 |
|
Two-for-one stock split |
|
|
122,626,451 |
|
|
|
122 |
|
|
|
(122 |
) |
|
|
|
|
|
|
|
|
|
|
342,698 |
|
|
|
|
|
|
|
|
|
Restricted stock grants |
|
|
198,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants forfeited |
|
|
(20,590 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation |
|
|
|
|
|
|
|
|
|
|
12,184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,184 |
|
Income tax benefit from
equity awards |
|
|
|
|
|
|
|
|
|
|
19,181 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,181 |
|
Derivative contracts, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,591 |
) |
|
|
|
|
|
|
|
|
|
|
(1,591 |
) |
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
253,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
253,147 |
|
|
|
|
Balance December 31, 2007 |
|
|
245,386,951 |
|
|
|
245 |
|
|
|
662,698 |
|
|
|
751,179 |
|
|
|
(1,591 |
) |
|
|
637,795 |
|
|
|
(8,153 |
) |
|
|
1,404,378 |
|
|
|
|
Repurchase of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
155,297 |
|
|
|
(3,762 |
) |
|
|
(3,762 |
) |
Issued pursuant to employee
stock purchase plan |
|
|
|
|
|
|
|
|
|
|
1,176 |
|
|
|
|
|
|
|
|
|
|
|
(346,805 |
) |
|
|
5,085 |
|
|
|
6,261 |
|
Issued pursuant to employee
stock option plan |
|
|
2,578,563 |
|
|
|
3 |
|
|
|
7,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,711 |
|
Issued pursuant to
directors compensation plan |
|
|
12,753 |
|
|
|
|
|
|
|
212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
212 |
|
Restricted stock grants |
|
|
278,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants forfeited |
|
|
(251,366 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation |
|
|
|
|
|
|
|
|
|
|
16,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,243 |
|
Income tax benefit from
equity awards |
|
|
|
|
|
|
|
|
|
|
19,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,665 |
|
Derivative contracts, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
964 |
|
|
|
|
|
|
|
|
|
|
|
964 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
388,396 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
388,396 |
|
|
|
|
Balance December 31, 2008 |
|
|
248,005,874 |
|
|
|
248 |
|
|
|
707,702 |
|
|
$ |
1,139,575 |
|
|
|
(627 |
) |
|
|
446,287 |
|
|
|
(6,830 |
) |
|
|
1,840,068 |
|
|
|
|
Repurchase of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
194,943 |
|
|
|
(3,014 |
) |
|
|
(3,014 |
) |
Issued pursuant to employee
stock purchase plan |
|
|
|
|
|
|
|
|
|
|
(81 |
) |
|
|
|
|
|
|
|
|
|
|
(484,946 |
) |
|
|
7,417 |
|
|
|
7,336 |
|
Issued pursuant to employee
stock option plan |
|
|
1,312,714 |
|
|
|
2 |
|
|
|
5,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,653 |
|
Issued pursuant to
directors compensation plan |
|
|
21,658 |
|
|
|
|
|
|
|
322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
322 |
|
Issued pursuant to
Conroe Field acquisition |
|
|
11,620,000 |
|
|
|
12 |
|
|
|
168,711 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168,723 |
|
Restricted stock grants |
|
|
1,032,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock grants forfeited |
|
|
(63,849 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation |
|
|
|
|
|
|
|
|
|
|
24,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,322 |
|
Income tax benefit from
equity awards |
|
|
|
|
|
|
|
|
|
|
3,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,913 |
|
Derivative contracts, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70 |
|
|
|
|
|
|
|
|
|
|
|
70 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(75,156 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(75,156 |
) |
|
|
|
Balance December 31, 2009 |
|
|
261,929,292 |
|
|
$ |
262 |
|
|
$ |
910,540 |
|
|
$ |
1,064,419 |
|
|
$ |
(557 |
) |
|
|
156,284 |
|
|
$ |
(2,427 |
) |
|
$ |
1,972,237 |
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
74
Denbury Resources Inc.
Consolidated Statements of Comprehensive Operations
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Net income (loss) |
|
$ |
(75,156 |
) |
|
$ |
388,396 |
|
|
$ |
253,147 |
|
Other comprehensive income (loss), net of income tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of interest rate lock contracts designated as a hedge,
net of taxes of $-, $49 and $1,017, respectively |
|
|
|
|
|
|
12 |
|
|
|
(1,591 |
) |
Interest rate lock derivative contracts reclassified to income, net of taxes
of $43, $583 and $-, respectively |
|
|
70 |
|
|
|
952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(75,086 |
) |
|
$ |
389,360 |
|
|
$ |
251,556 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
75
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies
Organization and Nature of Operations
Denbury Resources Inc. is a Delaware corporation, organized under Delaware General Corporation
Law, engaged in the acquisition, development, operation and exploration of oil and natural gas
properties. We have one primary business segment, which is the exploration, development and
production of oil and natural gas in the U.S. Gulf Coast region. We also own the rights to a
natural source of carbon dioxide (CO2) reserves that we use for injection
in our tertiary oil recovery operations. We also sell some of the CO2 we produce to
Genesis Energy, L.P. (Genesis) (see Note 3) and to third party industrial users.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in accordance with generally
accepted accounting principles (GAAP) and include the accounts of Denbury and its subsidiaries,
all of which are wholly owned. A former Denbury subsidiary, Genesis Energy, LLC is the general
partner of, and together with Denburys other subsidiaries, owned an aggregate 12% interest in
Genesis at December 31, 2009, a publicly traded master limited partnership. We accounted for our
12% ownership interest in Genesis under the equity method of
accounting. Even though we had
significant influence over the limited partnership in our role as general partner, because our
control was limited by the Genesis limited partnership agreement we did not consolidate Genesis.
On February 5, 2010, we sold our interest in Genesis Energy, LLC, but we still retain an
approximate 10% limited partner interest in Genesis (for which a resale registration statement was filed in January
2010) in which we continue to account for under the equity method of accounting. See Note 3,
Related Party Transactions Genesis for more information regarding our related party
transactions with Genesis and see Note 15, Subsequent Events for more information about the sale
of our general partnership interest. All material intercompany balances and transactions have been
eliminated. We have evaluated our consolidation of variable interest entities in accordance with
Consolidation topic of the Financial Accounting Standards Board Codification (FASC), and have
concluded that we do not have any variable interest entities that would require consolidation.
Stock Split
On November 19, 2007, stockholders of Denbury Resources Inc. approved an amendment to our
Restated Certificate of Incorporation to increase the number of shares of our authorized common
stock from 250,000,000 shares to 600,000,000 shares and to split our common stock on a 2-for-1
basis. Stockholders of record on December 5, 2007, received one additional share of Denbury common
stock for each share of common stock held at that time.
Information pertaining to shares and earnings per share has been retroactively adjusted in the
accompanying financial statements and related notes thereto to reflect the stock split, except for
the share amounts included on our Consolidated Balance Sheets and Consolidated Statements of
Changes in Stockholders Equity, which reflect the actual shares outstanding at each period end.
Oil and Natural Gas Operations
Capitalized Costs. We follow the full cost method of accounting for oil and natural
gas properties. Under this method, all costs related to acquisitions, exploration and development
of oil and natural gas reserves are capitalized and accumulated in a single cost center
representing our activities, which are undertaken exclusively in the United States. Such costs
include lease acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties, costs of drilling both productive and non-productive wells, capitalized
interest on qualifying projects, and general and administrative expenses directly related to
exploration and development activities, and do not include any costs related to production, general
corporate overhead or similar activities. Proceeds received from disposals are credited against
accumulated costs except when the sale represents a significant disposal of reserves, in which case
a gain or loss is recognized.
Depletion and Depreciation. The costs capitalized, including production equipment
and future development costs, are depleted or depreciated on the unit-of-production method, based
on proved oil and natural gas reserves as
76
Denbury Resources Inc.
Notes to Consolidated Financial Statements
determined by independent petroleum engineers. Oil and natural gas reserves are converted to
equivalent units based upon the relative energy content, which is six thousand cubic feet of
natural gas to one barrel of crude oil. The depletion and depreciation rate per BOE associated
with our oil and gas producing activities was $13.39 in 2009, $12.54 in 2008 and $11.60 in 2007.
Asset Retirement Obligations. In general, our future asset retirement obligations
relate to future costs associated with plugging and abandonment of our oil, natural gas and
CO2 wells, removal of equipment and facilities from leased acreage, and returning such
land to its original condition. The fair value of a liability for an asset retirement obligation
is recorded in the period in which it is incurred, discounted to its present value using our credit
adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying
amount of the related long-lived asset. The liability is accreted each period, and the capitalized
cost is depreciated over the useful life of the related asset. Revisions to estimated retirement
obligations will result in an adjustment to the related capitalized asset and corresponding
liability. If the liability is settled for an amount other than the recorded amount, the
difference is recorded to the full cost pool, unless significant. See Note 4 for more information
regarding our asset retirement obligations.
Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the
lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the
sum of (i) the present value of estimated future net revenues from proved reserves before future
abandonment costs (discounted at 10%), based on unescalated period-end oil and natural gas prices
during 2007, 2008 and for the first three quarters of 2009; and beginning in the fourth quarter of
2009, the average first-day-of-the-month oil and natural gas price for each month during the
12-month period ended December 31, 2009; (ii) plus the cost of properties not being amortized;
(iii) plus the lower of cost or estimated fair value of unproved properties included in the costs
being amortized, if any; (iv) less related income tax effects. We include that portion of net
capitalized costs of CO2 assets and CO2 pipelines that are required for our
current proved tertiary reserves in the net capitalized costs subject to the ceiling test. The
cost center ceiling test is prepared quarterly.
Joint Interest Operations. Substantially all of our oil and natural gas exploration and
production activities are conducted jointly with others. These financial statements reflect only
Denburys proportionate interest in such activities, and any amounts due from other partners are
included in trade receivables.
Proved Reserves. See Note 16, Supplemental Oil and Natural Gas Disclosures (Unaudited) for
information on our proved oil and natural gas reserves and the basis on which they are recorded.
Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have
already produced significant amounts of oil over many years; however, in accordance with the rules
for recording proved reserves, we cannot recognize proved reserves associated with enhanced
recovery techniques, such as CO2 injection, until there is a production response to the
injected CO2, or unless the field is analogous to an existing flood. Our costs
associated with the CO2 we produce (or acquire) and inject are principally our costs of
production, transportation and acquisition, and to pay royalties.
We capitalize, as a development cost, injection costs in fields that are in their development
stage, which means we have not yet seen incremental oil production due to the CO2
injections (i.e., a production response). These capitalized development costs are included in our
unevaluated property costs if there are not already proved tertiary reserves in that field. After
we see a production response to the CO2 injections (i.e., the production stage),
injection costs are expensed as incurred and any previously deferred unevaluated development costs
will become subject to depletion upon recognition of proved tertiary reserves. During the years
ended December 31, 2009 and 2008, we capitalized $8.0 million and $10.4 million, respectively, of
tertiary injection costs associated with our tertiary projects that were in the development phase.
Property and Equipment Other
Other property and equipment, which includes furniture and fixtures, vehicles, computer
equipment and software, and capitalized leases, is depreciated principally on a straight-line basis
over estimated useful lives. Estimated useful lives are generally as follows: vehicles and
furniture and fixtures 5 to 10 years; and computer equipment and software 3 to 5 years.
Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining
lease term.
77
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Leased property meeting certain capital lease criteria is capitalized, and the present value
of the related lease payments is recorded as a liability. Amortization of capitalized leased
assets is computed using the straight-line method over the shorter of the estimated useful life or
the initial lease term.
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts due
from purchasers of oil and natural gas are included in accrued production receivable.
We follow the sales method of accounting for our oil and natural gas revenue, whereby we
recognize revenue on all oil or natural gas sold to our purchasers regardless of whether the sales
are proportionate to our ownership in the property. A receivable or liability is recognized only
to the extent that we have an imbalance on a specific property greater than the expected remaining
proved reserves. As of December 31, 2009 and 2008, our aggregate oil and natural gas imbalances
were not material to our consolidated financial statements.
We recognize revenue and expenses of purchased producing properties at the time we assume
effective control, commencing from either the closing or purchase agreement date, depending on the
underlying terms and agreements. We follow the same methodology in reverse when we sell properties
by recognizing revenue and expenses of the sold properties until either the closing or purchase
agreement date, depending on the underlying terms and agreements.
Derivative Instruments and Hedging Activities
We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity
price risk associated with our future oil and natural gas production. These derivative contracts
have historically consisted of options, in the form of price floors or collars, and fixed price
swaps. We have also used interest rate lock contracts to mitigate our exposure to interest rate
fluctuations related to sale-leaseback financing of certain equipment used at our oilfield
facilities. Our derivative financial instruments are recorded on the balance sheet as either an
asset or a liability measured at fair value. We do not apply hedge accounting to our oil and
natural gas derivative contracts and accordingly the changes in the fair value of these instruments
are recognized in income in the period of change. See Note 10 for further information on our
derivative contracts.
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk
Our financial instruments that are exposed to concentrations of credit risk consist primarily
of cash equivalents, trade and accrued production receivables, and the derivative instruments
discussed above. Our cash equivalents represent high-quality securities placed with various
investment-grade institutions. This investment practice limits our exposure to concentrations of
credit risk. Our trade and accrued production receivables are dispersed among various customers
and purchasers; therefore, concentrations of credit risk are limited. Also, most of our
significant purchasers are large companies with excellent credit ratings. If customers are
considered a credit risk, letters of credit are the primary security obtained to support lines of
credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and
natural gas derivative contracts through formal credit policies, monitoring procedures and
diversification. There are no margin requirements with the counterparties of our derivative
contracts.
CO2
Operations
We own and produce CO2 reserves that are used for our own tertiary oil recovery
operations, and in addition, we sell a portion to Genesis and to other third party industrial
users. We record revenue from our sales of CO2 to third parties when it is produced and
sold. CO2 used for our own tertiary oil recovery operations is not recorded as revenue
in the Consolidated Statements of Operations. Expenses related to the production of CO2
are allocated between volumes sold to third parties and volumes used for our own use. The expenses
related to third party sales are recorded in CO2 operating expenses and the expenses
related to our own uses are recorded in Lease operating expenses in the Consolidated Statements
of Operations or are capitalized as oil and gas properties in our
78
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Consolidated Balance Sheets, depending on the status of floods that receive the CO2
(see Tertiary Injection Costs on page 77 for further discussion). We capitalize acquisitions and
the costs of exploring and developing CO2 reserves. The costs capitalized are depleted
or depreciated on the unit-of-production method, based on proved CO2 reserves as
determined by independent engineers. To evaluate our CO2 assets for impairment, we
determine the CO2 required for our proved tertiary reserves and include the estimated
net capitalized costs of those CO2 assets in the oil and natural gas ceiling test. The
remaining net capitalized CO2 asset cost is evaluated for impairment by comparing our
expected future revenues from these assets to their net carrying value.
CO2 Pipelines
CO2 pipelines are used for transportation of CO2 to our tertiary floods
from our CO2 source field located near Jackson, Mississippi. We are continuing
expansion of our CO2 pipeline infrastructure with several pipelines currently under
construction. At December 31, 2009 and 2008, we had $779.1 million and $402.0 million of costs,
respectively, related to construction in progress, recorded under CO2 properties,
equipment and pipelines in our Consolidated Balance Sheets. These costs of CO2
pipelines under construction were not being depreciated at December 31, 2009 or December 31, 2008.
Depreciation will commence when the pipelines are placed into service. The Green Pipeline, which
had $766.9 million in cost at December 31, 2009, is expected to be placed into service during 2010.
Each pipeline is depreciated on a straight-line basis over its estimated useful life, which ranges
from 20 to 30 years. We include the net capitalized cost of the pipelines which provide
CO2 to the tertiary floods that have proved tertiary reserves, in the oil and natural
gas ceiling test.
Goodwill
We recorded goodwill during 2009 in conjunction with our Hastings Field and Conroe Field
acquisitions (see Note 2, Acquisitions and Divestitures). Goodwill represents the excess of the
purchase price over the estimated fair value of the net assets acquired in the acquisition of a
business. Goodwill is not amortized, but rather it is tested for impairment annually during the
fourth quarter and also when events or changes in circumstances indicate that the fair value of a
reporting unit with goodwill has been reduced below carrying value. The impairment test requires
allocating goodwill and other assets and liabilities to reporting units. In the case of Denbury, we
have only one reporting unit. The fair value of the reporting unit is determined and compared to
the book value of the reporting unit. If the fair value of the reporting unit is less than the book
value, including goodwill, the recorded goodwill is impaired to its implied fair value with a
charge to operating expense. We completed our annual goodwill impairment test during the fourth
quarter of 2009 and did not record goodwill impairment during 2009.
Cash Equivalents
We consider all highly liquid investments to be cash equivalents if they have maturities of
three months or less at the date of purchase.
Restricted Cash and Investments
At December 31, 2009 and 2008, we had approximately $22.8 million and $7.4 million,
respectively, of restricted cash and investments held in escrow accounts for future site
reclamation costs. These balances are recorded at amortized cost and are included in Other
assets in the Consolidated Balance Sheets. The estimated fair market value of these investments
at December 31, 2009 and 2008 was approximately the same as amortized cost.
Net Income Per Common Share
Basic net income per common share is computed by dividing the net income attributable to
common stockholders by the weighted average number of shares of common stock outstanding during the
period. Diluted net income per common share is calculated in the same manner, but also considers
the impact to net income and common shares for the potential dilution from stock options,
non-vested stock appreciation rights (SARs), non-vested restricted stock and any other
convertible securities outstanding.
79
Denbury Resources Inc.
Notes to Consolidated Financial Statements
All shares have been adjusted for the 2-for-1 stock split effective December 5, 2007. For
each of the three years in the period ended December 31, 2009, there were no adjustments to net
income for purposes of calculating basic and diluted net income per common share.
The following is a reconciliation of the weighted average shares used in the basic and diluted
net income per common share computations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
In thousands |
|
2009 |
|
2008 |
|
2007 |
Weighted average common shares basic |
|
|
246,917 |
|
|
|
243,935 |
|
|
|
240,065 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
|
|
|
|
7,102 |
|
|
|
10,485 |
|
Restricted stock |
|
|
|
|
|
|
1,493 |
|
|
|
1,551 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
246,917 |
|
|
|
252,530 |
|
|
|
252,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average common shares basic amount in 2009, 2008 and 2007 excludes 2.5 million,
2.2 million and 2.7 million shares of non-vested restricted stock, respectively, that is subject to
future vesting over time. As these restricted shares vest, they will be included in the shares
outstanding used to calculate basic net income per common share (although all restricted stock is
issued and outstanding upon grant). For purposes of calculating weighted average common shares
diluted, the non-vested restricted stock is included in the computation using the treasury stock
method, with the proceeds equal to the average unrecognized compensation during the period,
adjusted for any estimated future tax consequences recognized directly in equity.
The following securities could potentially dilute earnings per share in the future, but were
not included in the computation of diluted net earnings per share as their effect would have been
anti-dilutive:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
In thousands |
|
2009 |
|
2008 |
|
2007 |
Stock options and SARs |
|
|
10,764 |
|
|
|
1,098 |
|
|
|
130 |
|
Performance equity awards |
|
|
523 |
|
|
|
|
|
|
|
|
|
Restricted stock |
|
|
2,507 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
13,794 |
|
|
|
1,098 |
|
|
|
130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes
Income taxes are accounted for using the liability method under which deferred income taxes
are recognized for the future tax effects of temporary differences between the financial statement
carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory
tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is
recognized in income in the period that includes the enactment date. A valuation allowance for
deferred tax assets is recorded when it is more likely than not that the benefit from the deferred
tax asset will not be realized.
Effective January 1, 2007, we adopted new accounting guidelines codified in the Income Taxes
topic of the FASC that address how tax benefits claimed or expected to be claimed on a tax return
should be recorded in the financial statements. Under the revised guidance, the Company may
recognize the tax benefit from an uncertain tax position only if it is more likely than not that
the tax position will be sustained on examination by the taxing authorities, based on the technical
merits of the position. The tax benefits recognized in the financial statements from such a
position should be measured based on the largest benefit that has a greater than fifty percent
likelihood of being realized upon ultimate settlement. See Note 7, Income Taxes, for further
information regarding our income taxes.
80
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amount of certain assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during each reporting period. Management believes its
estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a
number of risks and uncertainties that may cause actual results to differ materially from such
estimates. Significant estimates underlying these financial statements include (i) the fair value
of financial derivative instruments, (ii) the estimated quantities of proved oil and natural gas
reserves used to compute depletion of oil and natural gas properties, the related present value of
estimated future net cash flows therefrom and ceiling test, (iii) accruals related to oil and gas
production and revenues, capital expenditures and lease operating expenses, (iv) the estimated
costs and timing of future asset retirement obligations, (v) estimates made in the calculation of
income taxes and, (vi) estimates made in determining the fair values for purchase price
allocations. While management is not aware of any significant revisions to any of its estimates,
there will likely be future revisions to its estimates resulting from matters such as revisions in
estimated oil and gas volumes, changes in ownership interests, payouts, joint venture audits,
re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil
and gas industry, many of which require retroactive application. These types of adjustments cannot
be currently estimated and will be recorded in the period during which the adjustment occurs.
Reclassifications
Certain prior period amounts have been reclassified to conform with the current year
presentation. Such reclassifications had no impact on our reported net income, current assets,
total assets, current liabilities, total liabilities or stockholders equity.
Recently Adopted Accounting Pronouncements
FASB Accounting Standards CodificationTM. In June 2009, the Financial Accounting Standards Board (FASB) introduced the FASC as
the new source of authoritative U.S. GAAP for nongovernmental entities. The Company applied the
new guidance to our financial statements issued for the nine months ended September 30, 2009. This
standard did not have any impact on the Companys financial position or results of operations.
Subsequent Events. In May 2009, the FASB issued guidance under the Subsequent Events
topic of the FASC to establish accounting standards for events that occur after the balance sheet
date but before financial statements are issued or are available to be issued. The new guidance
does not significantly change current practice but does require companies to disclose the date
through which subsequent events were evaluated and whether or not that date was the date the
financial statements were issued or available for issuance. The Company adopted the new guidance
upon its issuance with no resulting impact on the Companys financial position or results of
operations.
Business Combinations. In December 2007, the FASB issued guidance under the Business
Combinations topic of the FASC to establish principles and requirements for how an acquirer
recognizes and measures in its financial statements, the identifiable assets acquired, the
liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. The
guidance also establishes disclosure requirements to enable the evaluation of the nature and
financial effects of the business combination. We adopted the new guidance on January 1, 2009.
While the adoption did not have an adoption-date impact on our financial position or results of
operations, we did apply the revised guidance to our Hastings Field and Conroe Field acquisitions
during 2009.
Equity Method Accounting. In November 2008, the FASB issued guidance in the Investments
Equity Company and Joint Ventures topic of the FASC to clarify how the application of equity
method accounting will be affected by newly issued guidance on business combinations and
noncontrolling interests in consolidated financial statements. The new guidance clarifies that an
entity shall continue to use the cost accumulation model for its equity method investments. It also
confirms past accounting practices related to the treatment of contingent consideration and
impairment. Additionally, it requires an equity method investor to account for a share issuance by
an investee as if the investor had sold a proportionate share of the investment. This guidance was
effective January 1, 2009, applies prospectively and did not have any impact on our financial
position or results of operations.
81
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Noncontrolling Interests. In December 2007, the FASB issued guidance under
Consolidations topic of the FASC which establishes accounting and reporting standards for
ownership interests in subsidiaries held by parties other than the parent, the amount of
consolidated net income attributable to the parent and to the noncontrolling interest, changes in a
parents ownership interest, and the valuation of retained noncontrolling equity investments when a
subsidiary is deconsolidated. The new guidance also establishes disclosure requirements that
clearly identify and distinguish between the interests of the parent and the interests of the
noncontrolling owners. We adopted this guidance on January 1, 2009 and, since we currently do not
have any noncontrolling interests, the adoption did not have any impact on our financial position
or results of operations.
Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB
issued guidance under the Derivatives and Hedging topic of the FASC which requires entities that
utilize derivative instruments to provide qualitative disclosures about their objectives and
strategies for using such instruments, as well as any details of credit risk related contingent
features contained within derivatives. The guidance also requires entities to disclose additional
information about the amounts and location of derivatives within the financial statements, how the
provisions of accounting guidance related to derivatives and hedging have been applied, and the
impact that hedges have on an entitys financial position, financial performance, and cash flows.
We adopted the disclosure requirement beginning January 1, 2009 (see Note 10, Derivative
Instruments and Hedging Activities). The adoption of this statement did not have any impact on our
financial position or results of operations.
Fair Value Measurements. In 2006, the FASB issued guidance which defined fair value,
established a framework for measuring fair value and expanded disclosures about fair value
measurements. In February 2008, the FASB delayed the effective date of the new guidance for all
nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at
fair value in the financial statements on a recurring basis (at least annually). We adopted the new
guidance on January 1, 2009. The adoption of this guidance did not have any impact on our financial
position or results of operations.
In April 2009, the FASB issued new rules to provide additional application guidance and
enhance disclosures regarding fair value measurements and impairments of securities. The FASB
enhanced its guidance under the Fair Value Measurements and Disclosures topic of the FASC to 1)
determine fair value when the volume and level of activity for an asset or liability have
significantly decreased and 2) identify transactions that are not orderly. The FASB issued
guidance under the Financial Instruments topic of the FASC to enhance consistency in financial
reporting by increasing the frequency of fair value disclosures. The FASB also issued guidance in
the Investments Debt and Equity Securities topic of the FASC to provide additional guidance to
create greater clarity and consistency in accounting for and presenting impairment losses on
securities. The new guidance was effective for interim and annual periods ending after June 15,
2009. Although adoption of the guidance enhanced our interim financial statement disclosures, it
did not have any impact on our financial position or results of operations.
In August 2009, the FASB issued guidance under the Fair Value Measurements and Disclosures
topic of the FASC to provide additional guidance on measuring the fair value of liabilities. The
new guidance was effective for the Company on October 1, 2009, and did not have any impact on the
Companys financial position or results of operations.
Modernization of Oil and Gas Reporting. On December 31, 2008, the Securities and Exchange
Commission adopted major revisions to its rules governing oil and gas company reporting
requirements. These include provisions that permit the use of new technologies to determine proved
reserves, and allow companies to disclose their probable and possible reserves to investors. The
prior rules limited disclosure to only proved reserves. The new rules also require companies that
have an audit performed on their reserves to report the independence and qualifications of the
reserve auditor, and file reports when a third party reserve engineer is relied upon to prepare
reserve estimates. The new rules also require that oil and gas reserves be reported and the full
cost ceiling value be calculated using an average of first-day-of-the-month prices for the prior
twelve-month period. In January 2010, the FASB issued guidance in the Extractive Activities Oil
and Gas topic of the FASC that aligns the FASBs oil and gas reserve estimation and disclosure
requirements with the new SEC rule revisions. The new guidance is effective for the Company for the
year ending December 31, 2009. The revised guidance did not have a material impact on our
financial position or results of operations. It did, however, impact the prices we use to
estimated proved reserves and the standardized measure of future net cash flows (see Note 16,
Supplemental Oil and Natural Gas Disclosures).
82
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Recently Issued Accounting Pronouncements
Transfers of Financial Assets. In June 2009, the FASB issued guidance related to the
accounting for transfers of financial assets. The guidance removes the concept of a qualifying
special-purpose entity (QSPE) from FASC topic Transfers and Servicing, creates a new unit of
account definition that must be met for transfers of portions of financial assets to be eligible
for sale accounting, clarifies the de-recognition criteria for a transfer to be accounted for as a
sale, changes the amount of recognized gains or losses on the transfer of financial assets
accounted for as a sale when beneficial interests are received by the transferor and introduces new
disclosure requirements. The new guidance is effective for us beginning January 1, 2010. The
adoption will not have a material impact on our financial condition or results of operations.
Consolidation of Variable Interest Entities. In June 2009, the FASB issued guidance to
eliminate the exemption in the Consolidation topic of the FASC for QSPEs, introduce a new
approach for determining who should consolidate a variable interest entity and change the
requirement as to when it is necessary to reassess who should consolidate a variable interest
entity. We adopted the standard on January 1, 2010. The adoption
will not have a material impact on
our financial condition or results of operations.
Fair Value Disclosures. In January 2009, the FASB issued guidance in the Fair Value
Measurements and Disclosures topic of the FASC to enhance disclosures surrounding the transfers of
assets in and out of level 1 and level 2, to present more detail surrounding asset activity for
level 3 assets and to clarify existing disclosure requirements. The new guidance is effective for
the Company beginning January 1, 2010, and will not have any impact on our financial position or
statement of operations.
Note 2. Acquisitions and Divestitures
2009 Acquisitions
Conroe Field Acquisition. In August 2008, we entered into an agreement with a privately owned
company to purchase a 91.4% interest in Conroe Field, a significant potential tertiary flood north
of Houston, Texas, for $600 million, plus additional potential consideration if oil prices were to
exceed $121 per barrel during the next three years. Closing was provided for in early October
2008. Based on capital market conditions in early October, and a desire to refrain from increasing
our leverage in that environment, we cancelled the contract to purchase the Conroe Field,
forfeiting a $30 million non-refundable deposit. The $30 million deposit plus miscellaneous
acquisition costs of $0.6 million are included in Abandoned acquisition costs in our Consolidated
Statement of Operations for the year ended December 31, 2008.
On December 18, 2009, we purchased Conroe Field for consideration consisting of approximately
$254.2 million in cash (before closing adjustments) and 11,620,000 shares of our common stock. The
common stock was valued at $168.7 million based on the closing date price of our stock on December
18, 2009 of $14.52. The effective date of purchase was December 1, 2009, and consequently
operating net revenues, net of capital expenditures, from December 1, 2009 through December 18,
2009 will be accounted for as adjustments to the ultimate purchase price. The cash amount paid at
closing was $269.8 million, which reflects $15.6 million for amounts in escrow accounts reserved
for plugging and abandonment and other adjustments. We believe the acquisition includes
significant opportunities for enhanced oil recovery using our available sources of CO2,
which we have recorded as unevaluated oil and gas properties as determined under the FASC Fair
Value Measurement topic (see Purchase Price Allocations below). During the year ended December
31, 2009, we recognized $2.3 million and $1.4 million of revenues and net field operating income
(revenues less production taxes and lease operating expenses), respectively, related to our
acquisition of Conroe Field. Acquisition-related costs (legal, accounting, due diligence, etc.)
have been expensed.
Denbury shares issued to Wapiti in conjunction with the purchase of Conroe Field are subject
to a registration rights agreement whereby Denbury has agreed to register the shares with the SEC
and maintain the effectiveness of the shares for a period of time which we currently estimate to be
one year. The shares were registered with the SEC on February 2, 2010.
Hastings Field Acquisition. During November 2006, we entered into an agreement with a
subsidiary of Venoco, Inc., that gave us an option to purchase their interest in Hastings Field, a
strategically significant potential tertiary flood candidate located near Houston, Texas. We
exercised the purchase option prior to September 2008, and closed the acquisition during
February 2009. As consideration for the option agreement, during 2006 through
83
Denbury Resources Inc.
Notes to Consolidated Financial Statements
2008, we made cash payments totaling $50 million which we recorded as a deposit. The remaining
purchase price of approximately $196 million was paid in cash, and was determined as of January 1,
2009 (the effective date) with closing on February 2, 2009. The final closing adjustments were
completed during the three months ended September 30, 2009. The final closing price, adjusted for
interim net cash flows between the effective date and closing date of the acquisition (including
minor purchase price adjustments), totaled $246.8 million. During the year ended December 31,
2009, we recognized $43.5 million and $18.8 million of revenues and net field operating income
(revenues less production taxes and lease operating expenses), respectively, related to our
acquisition of Hastings Field. The acquisition-related costs (legal, accounting, due diligence,
etc.) have been expensed.
Under the terms of the agreement, Venoco, Inc., the seller, retained a 2% override and a
reversionary interest of approximately 25% following payout, as defined in the option agreement. We
plan to commence flooding the field with CO2 beginning in 2011, after
completion of our Green Pipeline currently under construction and construction of field recycling
facilities. Under the agreement, we are required to make aggregate net cumulative capital
expenditures in this field of approximately $179 million prior to December 31, 2014 as follows:
$26.8 million by December 31, 2010, $71.5 million by December 31, 2011, $107.2 million by
December 31, 2012, $142.9 million by December 31, 2013, and $178.7 million by December 31, 2014. If
we fail to spend the required amounts by the due dates, we are required to make a cash payment
equal to 10% of the cumulative shortfall at each applicable date. During 2009, we made capital
expenditures related to CO2 flood development at Hastings Field totaling $1.7
million. Further, we are committed to inject at least an average of 50 MMcf/day of
CO2 (total of purchased and recycled) in the West Hastings Unit for the 90-day
period prior to January 1, 2013. If such injections do not occur, we must either (1) relinquish our
rights to initiate (or continue) tertiary operations and reassign to Venoco all assets previously
purchased for the value of such assets at that time based upon the discounted value of the fields
proved reserves using a 20% discount rate, or (2) make an additional payment of $20 million in
January 2013, less any payments made for failure to meet the capital spending requirements as of
December 31, 2012, and a $30 million payment for each subsequent year (less amounts paid for
capital expenditure shortfalls) until the CO2 injection rate in the Hastings
Field equals or exceeds the minimum required injection rate. At this time, the Company believes it
will be compliant with both of these commitments.
Purchase Price Allocations. Conroe Field and Hastings Field meet the definition of
a business under the FASC Business Combinations topic. As such, we estimated the fair value of
each property as of the acquisition date, as defined in the FASC, is the date on which the acquirer
obtains control of the acquiree, which was the closing date for both Conroe and Hastings Fields.
The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would
be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date (often referred to as the exit price). The fair value
measurement is based on the assumptions of market participants and not those of the reporting
entity. Therefore, entity-specific intentions should not impact the measurement of fair value
unless those assumptions are consistent with market participant views.
In applying these accounting principles, we estimated the fair value of the assets
acquired as follows:
|
|
|
|
|
|
|
|
|
In thousands |
|
Conroe Field |
|
|
Hastings Field |
|
Proved oil and natural gas properties |
|
$ |
304,313 |
|
|
$ |
107,582 |
|
Unevaluated oil and natural gas properties |
|
|
93,585 |
|
|
|
|
|
Other assets |
|
|
15,654 |
|
|
|
2,425 |
|
Asset retirement obligations |
|
|
(5,705 |
) |
|
|
(2,067 |
) |
Goodwill |
|
|
30,687 |
|
|
|
138,830 |
|
|
|
|
|
|
|
|
|
|
$ |
438,534 |
|
|
$ |
246,770 |
|
|
|
|
|
|
|
|
The FASC defines goodwill as an asset representing the future economic benefits arising from
other assets acquired in a business combination that are not individually identified and separately
recognized. For the Conroe Field and Hastings Field acquisitions, goodwill is the excess of the
consideration paid to acquire these fields over their acquisition date estimated fair values.
Goodwill recorded in both the Conroe Field and Hastings Field acquisitions is due to the estimated
fair value assigned to the estimated oil reserves recoverable through a CO2
84
Denbury Resources Inc.
Notes to Consolidated Financial Statements
enhanced oil recovery (EOR) project. Denbury has one of the few known significant natural
sources of CO2 in the United States, and the largest known source east of the
Mississippi river. This source of CO2 that we own will allow Denbury to carry
out CO2 EOR activities in this field at a much lower cost than other market
participants. However, FASC Fair Value Measurements and Disclosures topic does not allow
entity-specific assumptions in the measurement of fair value. Therefore, we estimated the fair
value of the oil reserves recoverable through CO2 EOR using an estimated cost
of CO2 to other market participants. This assumption of a higher cost of
CO2 resulted in an estimated fair value of the projected
CO2 EOR reserves that would not have been economically viable at Hastings Field
on the acquisition date and resulted in a lower fair value assigned to undeveloped property in the
Conroe Field acquisition. In addition, goodwill recorded in the Hastings Field acquisition is also
due to the decrease in the NYMEX oil and natural gas futures prices between the effective date of
January 1, 2009, which is the date at which the acquisition price was determined, and the
acquisition date of February 2, 2009, which is the date at which the assets were valued for
accounting purposes. The purchase agreement provided that the Hastings Field reserves be valued
using the NYMEX oil and gas futures prices on the effective date of January 1, 2009.
The fair value of Conroe Field and Hastings Field was based on significant inputs not
observable in the market, which FASC Fair Value Measurements and Disclosures topic defines as
Level 3 inputs. Key assumptions include (1) NYMEX oil and natural gas futures (this input is
observable), (2) projections of the estimated quantities of oil and natural gas reserves,
(3) projections of future rates of production, (4) timing and amount of future development and
operating costs, (5) projected cost of CO2 to a market participant,
(6) projected recovery factors and, (7) risk adjusted discount rates. Goodwill is deductible for
tax purposes. The Conroe Field purchase price allocation is preliminary and subject to changes
resulting from final closing adjustments.
Unaudited Pro Forma Information. Had our acquisitions of both Conroe Field and Hastings
Fields occurred on January 1, 2009 and January 1, 2008, Denburys combined pro forma revenue and
net income (loss) would have been as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
In thousands |
|
2009 |
|
2008 |
Revenues |
|
$ |
937,986 |
|
|
$ |
1,547,776 |
|
Net income (loss) |
|
|
(71,774 |
) |
|
|
422,707 |
|
2009 Dispositions
May 2009 Sale of 60% of Denburys Barnett Shale Natural Gas Assets. In May 2009, we entered
into an agreement to sell 60% of our Barnett Shale natural gas assets to Talon Oil and Gas LLC
(Talon), a privately held company, for $270 million (before closing adjustments). We closed on
approximately three-quarters of the sale in June 2009 and closed on the remainder of the sale in
July 2009. Net proceeds were $259.8 million (after preliminary closing adjustments, and net of
$8.1 million for natural gas swaps transferred in the sale). The agreement has an effective date of
June 1, 2009, and consequently operating net revenues after June 1, net of capital expenditures,
along with any other purchase price adjustments, were adjustments to the selling price. We did not
record a gain or loss on the sale in accordance with the full cost method of accounting.
December 2009 Sale of Remaining 40% of Denburys Barnett Shale Natural Gas Assets. In
December 2009, Denbury closed the sale of its remaining 40% interest in Barnett Shale natural gas
assets to Talon for $210 million (before closing adjustments). The effective date under the
agreement was December 1, 2009. Denbury did not record a gain or loss on the sale in accordance
with the full cost method of accounting.
2007 Acquisitions and Dispositions
Sale of Louisiana Natural Gas Asset. In October 2007, we entered into an agreement to sell
our Louisiana natural gas assets to a privately held company for approximately $180 million (before
closing adjustments) plus we retained a net profits interest in one well. In late December 2007,
we closed on approximately 70% of that sale with net proceeds of approximately $108.6 million
(including estimated final purchase price adjustments). We closed on the remaining portion of the
sale in February 2008 and received net proceeds of approximately $48.9 million. The agreement was
effective August 1, 2007, and consequently operating net revenue after August 1, net of capital
expenditures, along with any other minor closing items were adjustments to the purchase price. The
potential net
85
Denbury Resources Inc.
Notes to Consolidated Financial Statements
profits interest relates to a well in the South Chauvin field and is only earned if operating
income from that well exceeds certain levels. During 2009, we began receiving revenue payments
related to the net profits interest in this well. The operating results of these sold properties
are included in our financial statements through the applicable closing dates of the sold
properties. We did not record any gain or loss on the sale in accordance with the full cost method
of accounting.
Purchase of Seabreeze Complex. On March 30, 2007, Denbury completed the acquisition of the
Seabreeze Complex, which is composed of two significant fields and four smaller fields in the
general area of Houston, Texas. Two of these fields are future potential CO2 tertiary
flood candidates. Tertiary flooding at one of these fields, Oyster Bayou, is expected to begin
during 2010. The adjusted purchase price was approximately $39.4 million, of which $33.9 million
was assigned to unevaluated properties.
Note 3. Related Party Transactions Genesis
Interest in and Transactions with Genesis
Denburys former subsidiary, Genesis Energy, LLC, is the general partner of, and together with
Denburys other subsidiaries, at December 31, 2009, owned an aggregate 12% interest in Genesis, a
publicly traded master limited partnership. On February 5, 2010, we sold our interest in Genesis
Energy, LLC (see Note 15, Subsequent Events). Genesis business is focused on the mid stream
segment of the oil and gas industry in the Gulf Coast area of the United States, and its activities
include gathering, marketing and transportation of crude oil and natural gas, refinery services,
wholesale marketing of CO2, and supply and logistic services.
Prior to the sale, we accounted for our 12% ownership in Genesis under the equity method of
accounting as we had significant influence over the limited partnership; however, our control was
limited under the limited partnership agreement and therefore we did not consolidate Genesis.
Denbury received cash distributions from Genesis of $11.6 million in 2009, $7.1 million in 2008,
and $1.7 million in 2007. We also received $0.2 million in
2009 and 2008 and $0.1
million in 2007, in directors fees for certain officers of Denbury that were board members of
Genesis prior to the February 5, 2010 sale of our General Partner ownership. There are no
guarantees by Denbury or any of our other subsidiaries of the debt of Genesis or of Genesis Energy,
LLC.
We continue to own an aggregate of 4,028,096 common units of Genesis, representing an
approximate 10% limited partnership interest, for which a resale registration statement was filed
in January 2010. We also continue to account for our remaining 10% ownership interest in Genesis
under the equity method of accounting. Our cumulative investments in Genesis of $85.5 million
exceeded our percentage of net equity in the limited partnership at the time of acquisition by
approximately $15.7 million, which represents goodwill and is not subject to amortization. At
December 31, 2009, the balance of our total equity investment in
Genesis was $75.0 million (see Note 15, Subsequent
Events Sale of General Partner Ownership in Genesis). Based
on quoted market values of Genesis publicly traded limited
partnership units at December 31, 2009,
the estimated market value of our publicly traded common units of Genesis was approximately $76.1
million.
Incentive Compensation Agreement
In late December 2008, our subsidiary, Genesis Energy, LLC, entered into agreements with three
members of Genesis management, for the purpose of providing them incentive compensation, which
agreements make them Class B Members in Genesis Energy, LLC, and each an owner of a Class B
ownership interest. The awards are mandatorily redeemable upon a change in control and require the
membership interests of the holders of the awards to be redeemed for cash (or in certain
circumstances Genesis limited partnership units) by Genesis Energy, LLC. Upon the sale by Denbury
of our interest in Genesis Energy, LLC in February 2010, the change in control provision of each
members compensation agreement was triggered. As such, the awards were settled for cash in
February 2010 for $14.9 million. As of December 31, 2009, we had approximately $13.8 million
recorded under Accounts payable and accrued liabilities for these awards in our Consolidated
Balance Sheet. We recorded approximately $14.2 million for the year ended December 31, 2009, in
General and administrative expenses on our Consolidated Statement of Operations, of which $0.4
million relates to cash payments made under these awards and $13.8 million is associated with the
fair value of the award.
86
Denbury Resources Inc.
Notes to Consolidated Financial Statements
NEJD Pipeline and Free State Pipeline Transactions
On May 30, 2008, we closed on two transactions with Genesis involving our Northeast Jackson
Dome (NEJD) pipeline system and Free State Pipeline, which included a 20-year financing lease for
the NEJD system and a long-term transportation service agreement for the Free State Pipeline. We
have recorded both of these transactions as financing leases. At December 31, 2009, we have
recorded $170.6 million for the NEJD financing and $80.0 million for the Free State Pipeline as
debt, of which $3.8 million was included in current liabilities in our Consolidated Balance Sheet.
At December 31, 2008, we had recorded $173.6 million for the NEJD financing and $76.6 million for
the Free State Pipeline as debt, of which $3.0 million was included in current liabilities in our
Consolidated Balance Sheet (see Note 6, Long-term Debt).
Oil Sales and Transportation Services
We utilize Genesis trucking services and common carrier pipeline to transport certain of our
crude oil production to sales points where it is sold to third party purchasers. We expensed $7.9
million in 2009, $8.0 million in 2008, and $6.0 million in 2007 for these transportation services.
Transportation Leases
We have pipeline transportation agreements with Genesis to transport our crude oil from
certain of our fields in Southwest Mississippi, and to transport CO2 from our main
CO2 pipeline to Brookhaven Field for our tertiary operations. We have accounted for
these agreements as capital leases. The pipelines held under these capital leases are classified
as property and equipment and are amortized using the straight-line method over the lease terms.
Lease amortization is included in depreciation expense. The related obligations are recorded as
debt. At December 31, 2009 and 2008, we had $3.8 million and $4.5 million, respectively, of
capital lease obligations with Genesis recorded as liabilities in our Consolidated Balance Sheets.
CO2 Volumetric Production Payments
During 2003 through 2005, we sold 280.5 Bcf of CO2 to Genesis under three separate
volumetric production payment agreements. We have recorded the net proceeds of these volumetric
production payment sales as deferred revenue and recognize such revenue as CO2 is
delivered under the volumetric production payments. At December 31, 2009 and 2008, $19.8 million
and $24.0 million, respectively, was recorded as deferred revenue of which $4.1 million was
included in current liabilities at both December 31, 2009 and 2008. We recognized deferred revenue
of $4.2 million, $4.5 million and $4.4 million for the years ended December 31, 2009, 2008 and
2007, respectively, for deliveries under these volumetric production payments. We provide Genesis
with certain processing and transportation services in connection with transporting CO2
to their industrial customers for a fee of approximately $0.20 per Mcf of CO2. For
these services, we recognized revenues of $5.5 million, $5.5 million and $5.2 million for the years
ended December 31, 2009, 2008 and 2007, respectively.
Note 4. Asset Retirement Obligations
In general, our future asset retirement obligations relate to future costs associated with
plugging and abandonment of our oil, natural gas and CO2 wells, removal of equipment and
facilities from leased acreage and land restoration. The fair value of a liability for an asset
retirement is recorded in the period in which it is incurred, discounted to its present value using
our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing
the carrying amount of the related long-lived asset. The liability is accreted each period, and
the capitalized cost is depreciated over the useful life of the related asset.
The following table summarizes the changes in our asset retirement obligations for the years
ended December 31, 2009 and 2008.
87
Denbury Resources Inc.
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
Beginning asset retirement obligation |
|
$ |
45,064 |
|
|
$ |
41,258 |
|
Liabilities incurred and assumed during period |
|
|
8,911 |
|
|
|
1,382 |
|
Revisions in estimated retirement obligations |
|
|
2,357 |
|
|
|
4,456 |
|
Liabilities settled during period |
|
|
(3,478 |
) |
|
|
(4,711 |
) |
Accretion expense |
|
|
3,280 |
|
|
|
3,048 |
|
Sales |
|
|
(1,796 |
) |
|
|
(369 |
) |
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
54,338 |
|
|
$ |
45,064 |
|
|
|
|
|
|
|
|
At December 31, 2009 and 2008, $1.1 million and $1.7 million, respectively, of our asset
retirement obligation was classified in Accounts payable and accrued liabilities under current
liabilities in our Consolidated Balance Sheets. Liabilities incurred and assumed during 2009 are
primarily related to the acquisition of Hastings Field and Conroe Field. Liabilities incurred and
assumed during 2008 were primarily for new wells drilled. Liabilities sold during 2009 are
primarily related to our Barnett Shale natural gas properties (see Note 2, Acquisitions and
Divestitures). Liabilities sold in 2008 were primarily associated with the sale of our Louisiana
natural gas properties in February 2008. The reversal of these asset retirement obligations, which
were assumed by the purchasers, was recorded as an adjustment to the full cost pool with no gain or
loss recognized, in accordance with the full cost method of accounting. We have escrow accounts
that are legally restricted for certain of our asset retirement obligations. The balances of these
escrow accounts were $22.8 million and $7.4 million at December 31, 2009 and 2008, respectively,
and are included in Other assets in our Consolidated Balance Sheets. The increase in the escrow
balance is related to escrow accounts acquired in the Conroe Field acquisition.
Note 5. Property and Equipment
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
Oil and natural gas properties |
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
3,595,726 |
|
|
$ |
3,386,606 |
|
Unevaluated properties |
|
|
320,356 |
|
|
|
235,403 |
|
|
|
|
|
|
|
|
Total |
|
|
3,916,082 |
|
|
|
3,622,009 |
|
Accumulated depletion and depreciation |
|
|
(1,685,171 |
) |
|
|
(1,481,801 |
) |
|
|
|
|
|
|
|
Net oil and natural gas properties |
|
|
2,230,911 |
|
|
|
2,140,208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 properties and equipment |
|
|
438,045 |
|
|
|
377,711 |
|
Accumulated depletion and depreciation |
|
|
(79,196 |
) |
|
|
(60,758 |
) |
|
|
|
|
|
|
|
Net CO2 properties |
|
|
358,849 |
|
|
|
316,953 |
|
|
|
|
|
|
|
|
|
|
CO2 pipelines in service |
|
|
312,656 |
|
|
|
119,819 |
|
CO2 pipelines under construction |
|
|
779,080 |
|
|
|
402,012 |
|
Accumulated depletion and depreciation |
|
|
(22,426 |
) |
|
|
(16,392 |
) |
|
|
|
|
|
|
|
Net CO2 pipelines |
|
|
1,069,310 |
|
|
|
505,439 |
|
|
|
|
|
|
|
|
|
|
Capital leases |
|
|
9,857 |
|
|
|
9,565 |
|
Accumulated depletion and depreciation |
|
|
(4,787 |
) |
|
|
(3,333 |
) |
|
|
|
|
|
|
|
Net capital leases |
|
|
5,070 |
|
|
|
6,232 |
|
|
|
|
|
|
|
|
|
|
Other |
|
|
72,680 |
|
|
|
60,763 |
|
Accumulated depletion and depreciation |
|
|
(33,948 |
) |
|
|
(27,398 |
) |
|
|
|
|
|
|
|
Net other |
|
|
38,732 |
|
|
|
33,365 |
|
|
|
|
|
|
|
|
Net property and equipment |
|
$ |
3,702,872 |
|
|
$ |
3,002,197 |
|
|
|
|
|
|
|
|
88
Denbury Resources Inc.
Notes to Consolidated Financial Statements
At December 31, 2009 and 2008, we had $779.1 million and $402.0 million of costs,
respectively, related to pipelines under construction, and as such, were not being depreciated at
December 31, 2009 or December 31, 2008, respectively. Depreciation will commence when the
pipelines are placed into service. The Green Pipeline, which had
$766.9 million in cost, including capitalized interest, at
December 31, 2009, is expected to be placed into service during 2010. The Company capitalizes
interest on its CO2 pipelines during the construction period. Interest capitalized on
these CO2 pipelines was $54.2 million in 2009 and $11.5 million in 2008.
Unevaluated Oil and Natural Gas Properties Excluded From Depletion
Under full cost accounting, we may exclude certain unevaluated costs from the amortization
base pending determination of whether proved reserves can be assigned to such properties. We
assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated
properties based on the estimated fair values as defined in the FASC Fair Value Measurements and
Disclosures topic. The costs classified as unevaluated are transferred to the full cost
amortization base as the properties are developed, tested and evaluated. A summary of the
unevaluated properties excluded from oil and natural gas properties being amortized at December 31,
2009, and the year in which they were incurred follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
|
Costs Incurred During: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 and |
|
|
|
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
prior |
|
|
Total |
|
Property acquisition costs |
|
$ |
95,477 |
|
|
$ |
2,573 |
|
|
$ |
31,042 |
|
|
$ |
70,350 |
|
|
$ |
199,442 |
|
Exploration and development |
|
|
68,530 |
|
|
|
21,898 |
|
|
|
2,645 |
|
|
|
|
|
|
|
93,073 |
|
Capitalized interest |
|
|
12,477 |
|
|
|
7,442 |
|
|
|
5,341 |
|
|
|
2,581 |
|
|
|
27,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
176,484 |
|
|
$ |
31,913 |
|
|
$ |
39,028 |
|
|
$ |
72,931 |
|
|
$ |
320,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs for 2009 are primarily for CO2 tertiary potential at
Conroe Field. Property acquisition costs for 2007 are primarily for CO2 tertiary oil
field candidates acquired in the Seabreeze Complex. Property acquisition costs for 2006 and prior
are primarily for Delhi Field, South Cypress Creek Field, and Citronelle Field. We commenced
CO2 injection at Delhi Field in November 2009 and we plan to commence CO2
injection at Seabreeze in mid-2010. See Note 2, Acquisitions and Divestitures. Exploration and
development costs are primarily associated with our CO2 tertiary oil fields that are
under development and did not have proved reserves at December 31, 2009. During 2009, we
established proved reserves at Cranfield Field and as a result we transferred $82.4 million of
costs incurred on this project into the amortization base. Costs are transferred into the
amortization base on an ongoing basis as the projects are evaluated and proved reserves established
or impairment determined. We review the excluded properties for impairment at least annually. We
currently estimate that evaluation of most of these properties and the inclusion of their costs in
the amortization base is expected to be completed within five years. Until we are able to
determine whether there are any proved reserves attributable to the above costs, we are not able to
assess the future impact on the amortization rate of the full cost pool.
Full Cost Ceiling Test
In 2008 the Company recognized a write-down of its oil and natural gas properties of $226
million under the full cost ceiling test at December 31, 2008. In accordance with the full cost
ceiling rules at December 31, 2008, the ceiling limit was calculated utilizing the unescalated
period-end prices, which were a NYMEX WTI oil price per Bbl of $44.60 and a Henry Hub cash price
per MMBtu of $5.71. We included the portion of net capitalized cost of CO2 assets and
CO2 pipelines that were required for our proved tertiary reserves in the net capitalized
costs subject to this ceiling test. The fair value of our oil derivative contracts at December 31,
2008 of $249.7 million, which contracts had a floor price of $75.00 per barrel on 30,000 barrels
per day for calendar year 2009, was not included in the ceiling test as we did not designate these
contracts as hedge instruments for accounting purposes.
Because oil prices have recovered during 2009 from their year-end 2008 levels, we did not have
a ceiling test write-down during 2009. However, if oil prices were to decrease significantly in
subsequent periods, we may be
89
Denbury Resources Inc.
Notes to Consolidated Financial Statements
required to record additional write-downs under the full cost pool ceiling test in the future.
The possibility and amount of any future write-down is difficult to predict, and will depend upon
oil and natural gas prices, the incremental proved reserves that may be added each period,
revisions to previous reserve estimates and future capital expenditures, and additional capital
spent. The SEC adopted major revisions to its rules governing oil and gas company reporting
requirements which are effective for us beginning with this December 31, 2009, Form 10-K. Under
these new rules, the full cost ceiling value is calculated using an average price based on the
first day of every month during the period.
Note 6. Long-Term Debt
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
9.75% Senior Subordinated Notes due 2016 |
|
$ |
426,350 |
|
|
$ |
|
|
Discount on Senior Subordinated Notes due 2016 |
|
|
(26,424 |
) |
|
|
|
|
7.5% Senior Subordinated Notes due 2015 |
|
|
300,000 |
|
|
|
300,000 |
|
Premium on Senior Subordinated Notes due 2015 |
|
|
513 |
|
|
|
599 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(631 |
) |
|
|
(826 |
) |
NEJD financing Genesis |
|
|
170,633 |
|
|
|
173,618 |
|
Free State financing Genesis |
|
|
79,987 |
|
|
|
76,634 |
|
Senior bank loan |
|
|
125,000 |
|
|
|
75,000 |
|
Capital lease obligations Genesis |
|
|
3,780 |
|
|
|
4,544 |
|
Capital lease obligations |
|
|
2,168 |
|
|
|
2,705 |
|
|
|
|
|
|
|
|
Total |
|
|
1,306,376 |
|
|
|
857,274 |
|
Less current obligations |
|
|
5,308 |
|
|
|
4,507 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
1,301,068 |
|
|
$ |
852,767 |
|
|
|
|
|
|
|
|
9.75% Senior Subordinated Notes due 2016
On February 13, 2009, we issued $420 million of 9.75% Senior Subordinated Notes due 2016
(2016 Notes). The 2016 Notes, which carry a coupon rate of 9.75%, were sold at a discount
(92.816% of par), which equates to an effective yield to maturity of approximately 11.25%. The net
proceeds of $381.4 million were used to repay most of our then-outstanding borrowings under our
bank credit facility, which increased from the December 31, 2008 balance, primarily associated with
the funding of the Hastings Field acquisition (see Note 2, Acquisitions and Divestitures). In
conjunction with this debt offering we amended our bank credit facility in early February 2009,
which, among other things, allowed us to issue these senior subordinated notes.
In June 2009, we issued an additional $6.35 million of 2016 Notes to our founder, Gareth
Roberts, as part of a Founders Retirement Agreement. In connection with this issuance, we
recorded compensation expense of $6.35 million in General and administrative expense in our
Consolidated Statement of Operations during the year ended December 31, 2009.
The 2016 Notes mature on March 1, 2016, and interest on the 2016 Notes is payable March 1 and
September 1 of each year. We may redeem the 2016 Notes in whole or in part at our option beginning
March 1, 2013, at the following redemption prices: 104.875% after March 1, 2013, 102.4375% after
March 1, 2014, and 100% after March 1, 2015. In addition, we may at our option, redeem up to an
aggregate of 35% of the 2016 Notes before March 1, 2012, at a price of 109.75%. The indenture
contains certain restrictions on our ability to incur additional debt, pay dividends on our common
stock, make investments, create liens on our assets, engage in transactions with our affiliates,
transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2016
Notes are not subject to any sinking fund requirements. All of our significant subsidiaries fully
and unconditionally guarantee this debt.
NEJD Financing and Free State Financing
On May 30, 2008, we closed on two transactions with Genesis involving two of our pipelines.
The two transactions have been recorded as financing leases. See Note 3, Related Party
Transactions Genesis NEJD
Pipeline and Free State Pipeline Transactions.
90
Denbury Resources Inc.
Notes to Consolidated Financial Statements
7.5% Senior Subordinated Notes due 2015
On April 3, 2007, we issued $150 million of Senior Subordinated Notes due 2015 as an
additional issuance under our existing indenture governing our December 2005 sale of $150 million
of 7.5% Senior Subordinated Notes due 2015 (collectively, the 2015 Notes) discussed below. These
notes, which carry a coupon rate of 7.5%, were sold at 100.5% of par, which equates to an effective
yield to maturity of approximately 7.4%. Net proceeds from the sale were approximately $149.2
million. The net proceeds were used to repay a portion of the outstanding borrowings under our
bank credit facility.
The $150 million of 2015 Notes issued on December 21, 2005 were priced at par, and we used the
$148.0 million of net proceeds from the offering to fund a portion of the $250 million oil and
natural gas property acquisition, which closed in January 2006. The 2015 Notes mature on December
15, 2015, and interest on the 2015 Notes is payable each June 15 and December 15. We may redeem
the 2015 Notes at our option beginning December 15, 2010, at the following redemption prices:
103.75% after December 15, 2010, 102.5% after December 15, 2011, 101.25% after December 15, 2012,
and 100% after December 15, 2013. The indenture contains certain restrictions on our ability to
incur additional debt, pay dividends on our common stock, make investments, create liens on our
assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge,
or sell substantially all of our assets. The 2015 Notes are not subject to any sinking fund
requirements. All of our significant subsidiaries fully and unconditionally guarantee this debt.
7.5% Senior Subordinated Notes due 2013
On March 25, 2003, we issued $225 million of 7.5% Senior Subordinated Notes due 2013 (2013
Notes). The 2013 Notes were priced at 99.135% of par. The 2013 Notes mature on April 1, 2013,
and interest on the 2013 Notes is payable each April 1 and October 1. We may redeem the 2013 Notes
at our option beginning April 1, 2008, at the following remaining redemption prices: 102.5% after
April 1, 2009, 101.25% after April 1, 2010, and 100% after April 1, 2011, and thereafter. The
indenture contains certain restrictions on our ability to incur additional debt, pay dividends on
our common stock, make investments, create liens on our assets, engage in transactions with our
affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets.
The 2013 Notes are not subject to any sinking fund requirements. All of our significant
subsidiaries fully and unconditionally guarantee this debt.
Issuance of 8.25% Senior Subordinated Notes Due 2020
On February 10, 2010, we issued $1 billion of 8.25% Senior Subordinated Notes due 2020. (See
Note 15, Subsequent Events).
Senior Bank Loan
To clarify that Denbury entities are allowed to guarantee obligations of other Denbury
entities, in May 2009 we amended our Sixth Amended and Restated Credit Agreement, the instrument
governing our Senior Bank Loan, to explicitly permit these guarantees and waive any possible
previous technical violations of this provision.
In June and December 2009, we again amended our Senior Bank Loan agreement. The June 2009
amendment was made in conjunction with the sale of our Barnett Shale natural gas properties, and
(i) reduced our borrowing base from $1.0 billion to $900 million, and (ii) allowed for an
additional percentage of our forecasted production to be hedged through June 30, 2009. The June
amendment did not impact the banks commitment amount, which remained at $750 million. The
December 2009 amendment was made in conjunction with our acquisition of Conroe Field and the sale
of our remaining interests in the Barnett Shale natural gas properties. This December amendment
(i) allowed for the consummation of the Conroe-Barnett transactions, and (ii) allowed for an
additional percentage of our forecasted production to be hedged through May 31, 2010. Our
borrowing base of $900 million did not change as a result of this December amendment.
With regard to our bank credit facility, the borrowing base represents the amount that can be
borrowed from a credit standpoint based on our mortgaged assets, as confirmed by the banks, while
the commitment amount is the amount the banks have committed to fund pursuant to the terms of the
credit agreement. The banks have the option to participate in any borrowing request by us in
excess of the commitment amount ($750 million), up to the
91
Denbury Resources Inc.
Notes to Consolidated Financial Statements
borrowing base limit ($900 million), although the banks are not obligated to fund any amount
in excess of the commitment amount.
The bank credit facility is secured by substantially all of our producing oil and natural gas
properties, and contains several restrictions including, among others: (i) a prohibition on the
payment of dividends, (ii) a requirement to maintain positive working capital, as defined, (iii) a
minimum interest coverage test, and (iv) a prohibition of most debt and corporate guarantees.
Additionally, there is a limitation on the aggregate amount of forecasted production that can be
economically hedged with oil or natural gas derivative contracts. We were in compliance with all
of our bank covenants as of December 31, 2009. Borrowings under the credit facility are generally
in tranches that can have maturities up to one year. Interest on any borrowings is based on the
Prime Rate or LIBOR rate plus an applicable margin as determined by the borrowings outstanding.
The facility matures in September 2011.
As of December 31, 2009, we had $125 million of outstanding borrowings under the facility and
$10.5 million in letters of credit secured by the facility. The weighted average interest rate on
these outstanding borrowings was 1.49% at December 31, 2009. The next scheduled redetermination of
the borrowing base will be as of April 1, 2010, based on December 31, 2009 assets and proved
reserves. Our bank debt borrowing base is adjusted at the banks discretion and is based in part
upon external factors over which we have no control. If our borrowing base were to be less than
our outstanding borrowings under the facility, we will be required to repay the deficit over a
period of six months.
Newly Committed Bank Revolving Credit Agreement
On November 1, 2009, Denbury and Encore Acquisition Company announced they had entered into a
definitive merger agreement pursuant to which Denbury will acquire Encore in a stock and cash
transaction. In November 2009, we received commitments for a new $1.6 billion, 4-year revolving
credit facility. (See Note 15, Subsequent Events).
Indebtedness Repayment Schedule
At December 31, 2009, our indebtedness, excluding the discount and premium on our senior
subordinated debt, is repayable over the next five years and thereafter as follows:
|
|
|
|
|
In thousands |
|
|
|
|
|
2010 |
|
$ |
5,308 |
|
2011 |
|
|
132,449 |
|
2012 |
|
|
7,792 |
|
2013 |
|
|
233,203 |
|
2014 |
|
|
9,158 |
|
Thereafter |
|
|
945,008 |
|
|
|
|
|
Total indebtedness |
|
$ |
1,332,918 |
|
|
|
|
|
92
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 7. Income Taxes
Our income tax provision (benefit) is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Current income tax expense (benefit) |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
7,090 |
|
|
$ |
32,475 |
|
|
$ |
21,948 |
|
State |
|
|
(2,479 |
) |
|
|
8,337 |
|
|
|
8,126 |
|
|
|
|
|
|
|
|
|
|
|
Total current income tax expense |
|
|
4,611 |
|
|
|
40,812 |
|
|
|
30,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense (benefit) |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
(50,457 |
) |
|
|
184,630 |
|
|
|
113,868 |
|
State |
|
|
(1,187 |
) |
|
|
10,390 |
|
|
|
(3,675 |
) |
|
|
|
|
|
|
|
|
|
|
Total deferred income tax expense (benefit) |
|
|
(51,644 |
) |
|
|
195,020 |
|
|
|
110,193 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit) |
|
$ |
(47,033 |
) |
|
$ |
235,832 |
|
|
$ |
140,267 |
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2009, we had tax effected state net operating loss carryforwards (NOLs)
totaling $4.4 million and an estimated $38.9 million of enhanced oil recovery credits to carry
forward related to our tertiary operations. Our state NOLs expire in 2024. Our enhanced oil
recovery credits will begin to expire in 2024.
During the third quarter of 2008, we obtained approval from the Internal Revenue Service
(IRS) to change our method of tax accounting for certain assets used in our tertiary oilfield
recovery operations. Previously, we had capitalized and depreciated these costs, but now we can
deduct these costs once the assets are placed into service. As a result, we expect to receive tax
refunds of approximately $10.6 million for tax years through 2007, along with other tax benefits,
and we have reduced our current income tax expense and increased our deferred income tax expense in
2008 to adjust for the impact of this change. This change is not expected to have a significant
impact on our overall tax rate; however, it will allow for a quicker deduction of costs for tax
purposes.
Deferred income taxes relate to temporary differences based on tax laws and statutory rates in
effect at the December 31, 2009 and 2008 balance sheet dates. We believe that we will be able to
realize all of our deferred tax assets at December 31, 2009, and therefore have provided no
valuation allowance against our deferred tax assets.
At December 31, 2009 and 2008, our deferred tax assets and liabilities were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Loss carryforwards state |
|
$ |
4,394 |
|
|
$ |
152 |
|
Tax credit carryover |
|
|
32,156 |
|
|
|
32,156 |
|
Derivative contracts |
|
|
47,056 |
|
|
|
|
|
Enhanced oil recovery credit carryforwards |
|
|
38,929 |
|
|
|
43,772 |
|
Stock based compensation |
|
|
23,840 |
|
|
|
16,216 |
|
Other |
|
|
6,150 |
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
152,525 |
|
|
|
92,296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Property and equipment |
|
|
(619,621 |
) |
|
|
(520,455 |
) |
Derivative contracts |
|
|
|
|
|
|
(91,080 |
) |
Other |
|
|
(2,099 |
) |
|
|
(2,995 |
) |
|
|
|
|
|
|
|
Total deferred tax liabilities |
|
|
(621,720 |
) |
|
|
(614,530 |
) |
|
|
|
|
|
|
|
Total net deferred tax liability |
|
$ |
(469,195 |
) |
|
$ |
(522,234 |
) |
|
|
|
|
|
|
|
93
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Our income tax provision varies from the amount that would result from applying the federal
statutory income tax rate to income before income taxes as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Income tax provision (benefit) calculated using the
federal statutory income tax rate |
|
$ |
(42,765 |
) |
|
$ |
218,479 |
|
|
$ |
137,695 |
|
State income taxes |
|
|
(3,666 |
) |
|
|
18,865 |
|
|
|
11,536 |
|
Estimated statutory rate change |
|
|
|
|
|
|
|
|
|
|
(7,351 |
) |
Other |
|
|
(602 |
) |
|
|
(1,512 |
) |
|
|
(1,613 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit) |
|
$ |
(47,033 |
) |
|
$ |
235,832 |
|
|
$ |
140,267 |
|
|
|
|
|
|
|
|
|
|
|
Uncertain Tax Positions
We adopted the new accounting guidance within the Income Taxes topic of the FASC as of
January 1, 2007. As a result of the implementation, we determined that approximately $4.0 million
of tax benefits previously recognized were considered uncertain tax positions, as the timing of
these deductions may not be sustained upon examination by taxing authorities. As such, upon
adoption, we recorded income taxes payable of $4.3 million (including $0.3 million in estimated
interest) which was offset by a corresponding reduction of the deferred tax liability of $4.1
million for the tax position that we believe will ultimately be sustained. At December 31, 2009,
the total amount of unrecognized tax benefits was $1.0 million, exclusive of interest.
There was no cumulative adjustment made to the opening balance of retained earnings at January
1, 2007. Our uncertain tax positions relate primarily to timing differences, and we do not believe
any of such uncertain tax positions will materially impact our effective tax rate in future
periods. The amount of unrecognized tax benefits is expected to change over the next 12 months,
however, such change is not expected to have a material impact on our results of operations or
financial position.
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in
many state jurisdictions. We are currently under examination by the
IRS for the 2006, 2007 and 2008 tax years. The IRS concluded its examination of our 2004 tax year
during the third quarter of 2007 and concluded its examination of our 2005 tax year during the
second quarter of 2008. The state of Mississippi concluded its audit of tax years 1998 through
2000 during the third quarter of 2007 and is currently examining years 2001 through 2004. None of
the concluded examinations by the Internal Revenue Service or the state of Mississippi resulted in
any material assessments. As a result of the examinations concluded during 2007 and 2008, we
decreased our total amount of unrecognized tax benefits from $4.5 million at January 1, 2007, to
$3.5 million at December 31, 2007, and to $1.0 million at December 31, 2008. These adjustments are
all related to temporary timing differences and did not have any impact on our effective tax rate.
We have not paid any significant interest or penalties associated with our income taxes, but
classify both interest expense and penalties as part of our income tax expense.
Note 8. Stockholders Equity
Authorized
We are authorized to issue 600 million shares of common stock, par value $.001 per share, and
25 million shares of preferred stock, par value $.001 per share. The preferred shares may be
issued in one or more series with rights and conditions determined by the Board of Directors.
Stock Split
On November 19, 2007, stockholders of Denbury Resources Inc. approved an amendment to our
Restated Certificate of Incorporation to increase the number of shares of our authorized common
stock from 250,000,000 shares to 600,000,000 shares and to split our common stock on a 2-for-1
basis. Stockholders of record on December 5, 2007, received one additional share of Denbury common
stock for each share of common stock held at that time.
94
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Information pertaining to shares and earnings per share has been retroactively adjusted in the
accompanying financial statements and related notes thereto to reflect the stock splits, except for
the share amounts included on our Consolidated Balance Sheets and Consolidated Statements of
Changes in Stockholders Equity, which reflect the actual shares outstanding at each period end.
Stock Issuance
In December 2009, the Company issued 11,620,000 shares of common stock to Wapiti in
conjunction with our purchase of oil and gas assets in the Conroe Field (see Note 2, Acquisitions
and Divestitures).
Stock Repurchases
In 2007, 2008 and 2009, all of our share repurchases were from employees of Denbury that
delivered shares to the Company to satisfy their minimum tax withholding requirements as provided
for under Denburys stock compensation plans and were not part of a formal stock repurchase plan.
Employee Stock Purchase Plan
We have an Employee Stock Purchase Plan that is authorized to issue up to 8,900,000 shares of
common stock. As of December 31, 2009, there were 1,447,342 authorized shares remaining to be
issued under the plan. In accordance with the plan, eligible employees may contribute up to 10% of
their base salary and Denbury matches 75% of their contribution. The combined funds are used to
purchase previously unissued Denbury common stock or treasury stock purchased by the Company in the
open market for that purpose, in either case, based on the market value of Denburys common stock
at the end of each quarter. We recognize compensation expense for the 75% company match portion,
which totaled $3.1 million, $2.7 million and $2.2 million for the years ended December 31, 2009,
2008 and 2007, respectively. This plan is administered by the Compensation Committee of Denburys
Board of Directors.
401(k) Plan
Denbury offers a 401(k) plan to which employees may contribute tax deferred earnings subject
to Internal Revenue Service limitations. Effective January 1, 2008, Denbury increased its match to
100% of an employees contribution, up to 6% of compensation, as defined by the plan. Previously,
up to 3% of an employees compensation was matched by Denbury at 100%, and an employees
contribution between 3% and 6% of compensation was matched by Denbury at 50%. Denburys match is
vested immediately. During 2009, 2008 and 2007, Denburys matching contributions were
approximately $4.0 million, $3.3 million and $2.2 million, respectively, to the 401(k) Plan.
Note 9. Stock Compensation Plans
Stock Incentive Plans
Denbury has two stock compensation plans. The first plan has been in existence since 1995
(the 1995 Plan) and expired in August 2005 (although options granted under the 1995 Plan prior to
that time can remain outstanding for up to 10 years). The 1995 Plan only provided for the issuance
of stock options, and in January 2005, we issued stock options under the 1995 Plan that utilized
substantially all of the remaining authorized shares. The second plan, the 2004 Omnibus Stock and
Incentive Plan (the 2004 Plan), has a 10-year term and was approved by the stockholders in May
2004. In May 2007, shareholders approved an increase to the number of shares that may be used
under our 2004 Plan, from 10.0 million to 14.0 million shares. In May 2009, the shareholders
approved an additional increase from 14.0 million to 21.5 million shares. The 2004 Plan provides
for the issuance of incentive and non-qualified stock options, restricted stock awards, stock
appreciation rights (SARs) settled in stock, and performance awards that may be issued to
officers, employees, directors and consultants. Awards covering a total of 21.5 million shares of
common stock are authorized for issuance pursuant to the 2004 Plan, of which awards covering no
more than 14.2 million shares may be issued in the form of restricted stock or performance vesting
awards. At December 31, 2009, a total of 7,565,963 shares were available for future issuance of
awards, of which only 7,348,042 shares may be in the form of restricted stock or performance
vesting awards.
Denbury has historically granted incentive and non-qualified stock options to its employees.
Effective January 1, 2006, we completely replaced the use of stock options for employees with SARs
settled in stock, as SARs are less
95
Denbury Resources Inc.
Notes to Consolidated Financial Statements
dilutive to our stockholders while providing an employee with essentially the same economic
benefits as stock options. The stock options and SARs generally become exercisable over a
four-year vesting period with the specific terms of vesting determined at the time of grant based
on guidelines established by the Board of Directors. The stock options and SARs expire over terms
not to exceed 10 years from the date of grant, 90 days after termination of employment, and 90 days
or one year after permanent disability, depending on the plan, or one year after the death of the
optionee. The stock options and SARs are granted at the fair market value at the time of grant,
which is defined in the 2004 Plan as the closing price on the NYSE on the date of grant. The plan
is administered by the Compensation Committee of Denburys Board of Directors.
In 2004, Denbury began the use of restricted stock awards for its officers and independent
directors, all granted under the 2004 Plan. The holders of these shares have all of the rights and
privileges of owning the shares (including voting rights) except that the holders are not entitled
to delivery of a portion thereof until certain requirements are met. With respect to the
restricted stock granted to officers of Denbury in 2004, the vesting restrictions on those shares
are as follows: i) 65% of the awards vest 20% per year over five years, and ii) 35% of the awards
vest upon retirement, as defined in the 2004 Plan. On January 30, 2009, the Board of Directors
modified the vesting provisions for the 35% of the awards that would vest upon retirement to now
vest ratably each January 31 (beginning January 31, 2009) until the final vesting on the retirement
eligibility date.
Total stock-based compensation expense was $21.9 million, $14.1 million and $10.6 million for
the years ended December 31, 2009, 2008 and 2007, respectively. Part of this expense, $1.4 million
in 2009, $1.4 million in 2008 and $1.5 million in 2007, was included in Lease operating expenses
for stock compensation expense associated with our field employees, and the remaining amount
recognized in General and administrative expenses in the Consolidated Statements of Operations.
The total income tax benefit recognized in the Consolidated Statements of Operations for
share-based compensation arrangements was $8.7 million, $5.3 million and $4.1 million for the years
ended December 31, 2009, 2008 and 2007, respectively. Share-based compensation associated with our
employees involved in exploration and drilling activities of $2.5 million, $2.2 million and $1.6
million for the years ended December 31, 2009, 2008 and 2007, respectively, has been capitalized as
part of Oil and natural gas properties in the Consolidated Balance Sheets.
Stock Options and SARs
The fair value of each SAR award is estimated on the date of grant using the Black-Scholes
option pricing model with the assumptions noted in the following table. The risk-free rate for
periods within the contractual life of the option is based on the U.S. Treasury yield curve in
effect at the time of grant. The expected life of stock options and SARs granted was derived from
examination of our historical option grants and subsequent exercises. The contractual terms
(4-year cliff vesting and 4-year graded vesting) are evaluated separately for the expected life, as
the exercise behavior for each is different. Expected volatilities are based on the historical
volatility of our stock. Implied volatility was not used in this analysis as our tradable call
option terms are short and the trading volume is low. Our dividend yield is zero, as Denbury does
not pay a dividend.
Beginning in 2009, SARs granted have a term of 7 years as compared to 10 years for grants in
prior periods. Additionally, these SARs were issued with a graded vesting as compared to a
combination of cliff and graded vesting in prior periods. Both of these changes resulted in a
reduced expected term as compared to awards previously issued.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
Weighted average fair value
of SARs granted |
|
$ |
6.40 |
|
|
$ |
11.91 |
|
|
$ |
6.90 |
|
Risk free interest rate |
|
|
1.58 |
% |
|
|
3.29 |
% |
|
|
4.54 |
% |
Expected life |
|
|
3.9 to 4.7 years |
|
|
|
4.5 to 6.2 years |
|
|
|
4.6 to 6.4 years |
|
Expected volatility |
|
|
60.1 |
% |
|
|
38.1 |
% |
|
|
38.3 |
% |
Dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of our stock option and SARs activity.
96
Denbury Resources Inc.
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Options |
|
|
Price |
|
|
of Options |
|
|
Price |
|
|
of Options |
|
|
Price |
|
Outstanding at beginning of year |
|
|
9,514,999 |
|
|
$ |
9.32 |
|
|
|
11,463,285 |
|
|
$ |
6.28 |
|
|
|
14,964,920 |
|
|
$ |
4.96 |
|
Granted |
|
|
2,883,311 |
|
|
|
13.23 |
|
|
|
1,042,810 |
|
|
|
29.45 |
|
|
|
873,649 |
|
|
|
16.34 |
|
Exercised |
|
|
(1,315,535 |
) |
|
|
4.33 |
|
|
|
(2,612,134 |
) |
|
|
3.36 |
|
|
|
(4,054,844 |
) |
|
|
3.44 |
|
Forfeited |
|
|
(318,820 |
) |
|
|
16.36 |
|
|
|
(378,962 |
) |
|
|
13.80 |
|
|
|
(320,440 |
) |
|
|
7.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year |
|
|
10,763,955 |
|
|
|
10.77 |
|
|
|
9,514,999 |
|
|
|
9.32 |
|
|
|
11,463,285 |
|
|
|
6.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year |
|
|
6,087,019 |
|
|
$ |
6.48 |
|
|
|
4,593,407 |
|
|
$ |
4.55 |
|
|
|
3,969,466 |
|
|
$ |
3.26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total intrinsic value of stock options and SARs exercised during the years ended
December 31, 2009, 2008 and 2007, was approximately $14.8 million, $65.8 million and $60.3 million,
respectively. The total grant-date fair value of stock options and SARs vested during the years
ended December 31, 2009, 2008 and 2007, was approximately $10.1 million, $7.2 million and $6.8
million, respectively. The aggregate intrinsic value of stock options and SARs outstanding at
December 31, 2009, was approximately $59.2 million, and these options and SARs have a
weighted-average remaining contractual life of 5.3 years. The aggregate intrinsic value of options
and SARs exercisable at December 31, 2009, was approximately $52.8 million, and these stock options
and SARs have a weighted-average remaining contractual life of 4.3 years.
A summary of the status of our non-vested stock options and SARs as of December 31, 2009, and
the changes during the year ended December 31, 2009, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Grant-Date |
Non-Vested Stock Options and SARs |
|
Shares |
|
Fair Value |
Non-vested at January 1, 2009 |
|
|
4,921,592 |
|
|
$ |
5.87 |
|
Granted |
|
|
2,883,311 |
|
|
|
6.40 |
|
Vested |
|
|
(2,809,147 |
) |
|
|
3.61 |
|
Forfeited |
|
|
(318,820 |
) |
|
|
7.27 |
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2009 |
|
|
4,676,936 |
|
|
|
7.45 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009, there was $18.8 million of total compensation cost to be recognized
in future periods related to non-vested stock option and SAR share-based compensation arrangements.
The cost is expected to be recognized over a weighted-average period of 2.5 years. Cash received
from stock option exercises under share-based payment arrangements for the years ended December 31,
2009, 2008 and 2007, was $5.7 million, $7.7 million and $13.1 million, respectively. The tax
benefit realized from the exercises of stock options and SARs totaled $3.1 million for 2009, $18.9
million for 2008, and $18.7 million for 2007.
Restricted Stock
As of December 31, 2009, we had issued 5,900,134 shares of restricted stock (net of forfeited
shares) pursuant to the 2004 Plan and have recorded deferred compensation expense of $50.0 million,
the fair market value of the shares on the grant dates, net of estimated forfeitures of $6.7
million. This expense is amortized over the applicable five-year, four-year, or retirement date
vesting periods. As of December 31, 2009, there was $16.8 million of unrecognized compensation
expense related to non-vested restricted stock grants. This unrecognized compensation cost is
expected to be recognized over a weighted-average period of 3.57 years.
97
Denbury Resources Inc.
Notes to Consolidated Financial Statements
A summary of the status of our non-vested restricted stock grants and the changes during the
year ended December 31, 2009, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant-Date |
|
Non-Vested Restricted Stock Grants |
|
Shares |
|
|
Fair Value |
|
Non-vested at January 1, 2009 |
|
|
2,210,683 |
|
|
$ |
10.52 |
|
Granted |
|
|
1,032,896 |
|
|
|
13.34 |
|
Vested |
|
|
(672,732 |
) |
|
|
7.12 |
|
Forfeited |
|
|
(63,849 |
) |
|
|
22.42 |
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2009 |
|
|
2,506,998 |
|
|
|
12.29 |
|
|
|
|
|
|
|
|
|
The total vesting date fair value of restricted stock vested during the years ended December
31, 2009, 2008 and 2007 was $10.0 million, $12.3 million and $10.7 million, respectively.
Performance Equity Awards
Beginning in 2007, the Board of Directors has awarded an annual grant of performance equity
awards to the officers of Denbury. These performance-based shares vest over a 1.25 to 3.25 year
period. The number of performance-based shares that will be earned (and eligible to vest) during
the performance period will depend on the Companys level of success in achieving four specifically
identified performance targets. Generally, one-half of the shares earnable under the
performance-based shares will be earned for performance at the designated target levels (100%
target vesting levels) or upon any earlier change of control, and twice the number of shares will
be earned if the higher maximum target levels are met. If performance is below designated minimum
levels for all performance targets, no performance-based shares will be earned. Any portion of the
performance shares that are not earned by the end of the three-year measurement period will be
forfeited. In certain change of control events, one-half (i.e., the target level amount) of the
performance-based shares would vest.
During 2009, we granted 293,571 shares of performance-based equity awards (at the 100%
targeted vesting level) to the Companys executive officers with an average grant date fair value
of $12.97 per share. The aggregate number of performance-based equity awards outstanding at
December 31, 2009 was 475,912 (at the 100% targeted vesting level, less actual forfeitures). The
actual number of shares to be delivered pursuant to the performance-based awards could range from
zero to 200% (951,824) of the stated 100% targeted amount. The Company recognizes compensation
expense when it becomes probable that the performance criteria specified in the plan will be
achieved. We currently estimate a targeted vesting level of 110%,
100% and 120% for the 2009, 2008
and 2007 performance grants, respectively. During the years ended December 31, 2009, 2008, 2007, we
recorded $4.7 million, $1.2 million and $0.4 million, respectively, of expense in General and
administrative expenses in our Consolidated Statements of Operations for these performance-based
awards.
Note 10. Derivative Instruments and Hedging Activities
Oil and Natural Gas Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts and
therefore the changes in the fair values of these instruments are recognized in income in the
period of change. These fair value changes, along with the cash settlements of expired contracts
are shown under Commodity derivative expense (income) in our Consolidated Statements of
Operations.
From time to time, we enter into various oil and natural gas derivative contracts to provide
an economic hedge of our exposure to commodity price risk associated with anticipated future oil
and natural gas production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have consisted of price floors, collars and fixed price swaps.
Historically, we have hedged up to 80% of our anticipated production for the following year to
provide us with a reasonably certain amount of cash flow to cover most of our budgeted
98
Denbury Resources Inc.
Notes to Consolidated Financial Statements
exploration and development expenditures without incurring significant debt. Also, in light
of the recently announced acquisition of Encore, and our desire to protect our cash flows given the
increased debt levels we expect in connection with the acquisition, in November 2009 we entered
into costless collar crude oil contracts covering 25,000 Bbls/d during 2011.
All of the mark-to-market valuations used for our oil and natural gas derivative contracts are
provided by external sources and are based on prices that are actively quoted. We manage and
control market and counterparty credit risk through established internal control procedures that
are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties
through formal credit policies, monitoring procedures and diversification. All of our derivative
contracts are with parties that are lenders under our Senior Bank Loan. We have included an
estimate of nonperformance risk in the fair value measurement of our derivative contracts as
required by FASC guidance on fair value. At December 31, 2009 and 2008, the fair value of our
derivative contracts was reduced by $0.8 million and $3.7 million, respectively, for estimated
nonperformance risk.
The following is a summary of Commodity derivative income (expense), included in our
Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Receipt (payment) on settlements of derivative contracts oil |
|
$ |
146,734 |
|
|
$ |
(30,969 |
) |
|
$ |
(9,833 |
) |
Receipt (payment) on settlements of derivative contracts gas |
|
|
|
|
|
|
(26,584 |
) |
|
|
30,313 |
|
Fair value adjustments to derivative contracts income (expense) |
|
|
(382,960 |
) |
|
|
257,606 |
|
|
|
(39,077 |
) |
|
|
|
|
|
|
|
|
|
|
Commodity derivative income (expense) |
|
$ |
(236,226 |
) |
|
$ |
200,053 |
|
|
$ |
(18,597 |
) |
|
|
|
|
|
|
|
|
|
|
Fair Value of Commodity Derivative Contracts Not Classified as Hedging Instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
NYMEX Contract Prices Per Unit |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
|
|
|
|
Collar Prices |
|
|
December 31, |
|
Type of Contract and Period |
|
Bbls/d |
|
|
Swap Price |
|
|
Floor |
|
|
Ceiling |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Crude Oil Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Oil Collars |
|
|
30,000 |
|
|
$ |
|
|
|
$ |
75.00 |
|
|
$ |
115.00 |
|
|
$ |
|
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2010 Oil Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2010-Mar 2010 |
|
|
6,667 |
|
|
|
52.50 |
|
|
|
|
|
|
|
|
|
|
|
(16,552 |
) |
|
|
|
|
Jan 2010-Mar 2010 |
|
|
3,333 |
|
|
|
52.20 |
|
|
|
|
|
|
|
|
|
|
|
(8,365 |
) |
|
|
|
|
Jan 2010-Mar 2010 |
|
|
5,000 |
|
|
|
50.90 |
|
|
|
|
|
|
|
|
|
|
|
(13,131 |
) |
|
|
|
|
Jan 2010-Mar 2010 |
|
|
5,000 |
|
|
|
51.45 |
|
|
|
|
|
|
|
|
|
|
|
(12,884 |
) |
|
|
|
|
Jan 2010-Mar 2010 |
|
|
5,000 |
|
|
|
52.10 |
|
|
|
|
|
|
|
|
|
|
|
(12,593 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(63,525 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2010 Oil Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2010-Mar 2010 |
|
|
3,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
92.00 |
|
|
|
53 |
|
|
|
|
|
Jan 2010-Mar 2010 |
|
|
2,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
92.40 |
|
|
|
42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2010 Oil Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2010-Jun 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
76.40 |
|
|
|
(4,454 |
) |
|
|
|
|
Apr 2010-Jun 2010 |
|
|
10,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
73.15 |
|
|
|
(10,858 |
) |
|
|
|
|
Apr 2010-Jun 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
76.00 |
|
|
|
(4,569 |
) |
|
|
|
|
Apr 2010-Jun 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
74.30 |
|
|
|
(5,074 |
) |
|
|
|
|
Apr 2010-Jun 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
95.25 |
|
|
|
214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24,741 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99
Denbury Resources Inc.
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
NYMEX Contract Prices Per Unit |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
|
|
|
|
Collar Prices |
|
|
December 31, |
|
Type of Contract and Period |
|
Bbls/d |
|
|
Swap Price |
|
|
Floor |
|
|
Ceiling |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands |
|
Q3 2010 Oil Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jul 2010-Sept 2010 |
|
|
2,500 |
|
|
|
|
|
|
|
55.00 |
|
|
|
80.10 |
|
|
|
(2,176 |
) |
|
|
|
|
Jul 2010-Sept 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
55.00 |
|
|
|
80.00 |
|
|
|
(4,378 |
) |
|
|
|
|
Jul 2010-Sept 2010 |
|
|
7,500 |
|
|
|
|
|
|
|
60.00 |
|
|
|
80.40 |
|
|
|
(5,894 |
) |
|
|
|
|
Jul 2010-Sept 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
60.00 |
|
|
|
81.05 |
|
|
|
(3,768 |
) |
|
|
|
|
Jul 2010-Sept 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
55.00 |
|
|
|
80.00 |
|
|
|
(4,378 |
) |
|
|
|
|
Jul 2010-Sept 2010 |
|
|
2,500 |
|
|
|
|
|
|
|
70.00 |
|
|
|
96.00 |
|
|
|
(115 |
) |
|
|
|
|
Jul 2010-Sept 2010 |
|
|
2,500 |
|
|
|
|
|
|
|
70.00 |
|
|
|
97.00 |
|
|
|
(52 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,761 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q4 2010 Oil Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct 2010-Dec 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
60.00 |
|
|
|
89.70 |
|
|
|
(2,555 |
) |
|
|
|
|
Oct 2010-Dec 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
60.00 |
|
|
|
89.50 |
|
|
|
(2,592 |
) |
|
|
|
|
Oct 2010-Dec 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
60.00 |
|
|
|
89.00 |
|
|
|
(2,684 |
) |
|
|
|
|
Oct 2010-Dec 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
60.00 |
|
|
|
89.50 |
|
|
|
(2,592 |
) |
|
|
|
|
Oct 2010-Dec 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
60.00 |
|
|
|
88.75 |
|
|
|
(2,730 |
) |
|
|
|
|
Oct 2010-Dec 2010 |
|
|
2,500 |
|
|
|
|
|
|
|
70.00 |
|
|
|
96.00 |
|
|
|
(115 |
) |
|
|
|
|
Oct 2010-Dec 2010 |
|
|
2,500 |
|
|
|
|
|
|
|
70.00 |
|
|
|
97.00 |
|
|
|
(52 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,320 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 Oil Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2011-Dec 2011 |
|
|
3,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
101.10 |
|
|
|
(865 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
2,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
101.55 |
|
|
|
(487 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
2,500 |
|
|
|
|
|
|
|
70.00 |
|
|
|
100.95 |
|
|
|
(758 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
2,500 |
|
|
|
|
|
|
|
70.00 |
|
|
|
102.00 |
|
|
|
(500 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
2,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
103.00 |
|
|
|
(211 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
2,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
106.00 |
|
|
|
310 |
|
|
|
|
|
Jan 2011-Dec 2011 |
|
|
1,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
105.50 |
|
|
|
114 |
|
|
|
|
|
Jan 2011-Dec 2011 |
|
|
1,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
101.50 |
|
|
|
(249 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
2,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
104.00 |
|
|
|
(31 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
2,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
101.20 |
|
|
|
(557 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
3,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
102.00 |
|
|
|
(600 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
2,000 |
|
|
|
|
|
|
|
70.00 |
|
|
|
104.65 |
|
|
|
82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,752 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil Contracts |
|
$ |
(126,004 |
) |
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Natural Gas Swaps |
|
|
39,000 |
|
|
$ |
5.67 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,759 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,759 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 Natural Gas Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2011-Dec 2011 |
|
|
10,000 |
|
|
|
6.27 |
|
|
|
|
|
|
|
|
|
|
|
(244 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
10,000 |
|
|
|
6.25 |
|
|
|
|
|
|
|
|
|
|
|
(296 |
) |
|
|
|
|
Jan 2011-Dec 2011 |
|
|
7,000 |
|
|
|
6.16 |
|
|
|
|
|
|
|
|
|
|
|
(441 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(981 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Contracts |
|
$ |
(2,740 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Commodity Derivative Contracts |
|
$ |
(128,744 |
) |
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Additional Disclosures about Derivative Instruments:
At December 31, 2009 and 2008, we had derivative financial instruments recorded in our
Consolidated Balance Sheets as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
|
|
Asset (Liability) |
|
|
|
|
|
December 31, |
|
Type of Contract |
|
Balance Sheet Location |
|
2009 |
|
|
2008 |
|
|
|
|
|
In thousands |
|
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
Derivative Asset |
|
|
|
|
|
|
|
|
|
|
Crude Oil contracts |
|
Derivative assets current |
|
$ |
309 |
|
|
$ |
249,746 |
|
Crude Oil contracts |
|
Other assets |
|
|
506 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liability |
|
|
|
|
|
|
|
|
|
|
Crude Oil contracts |
|
Derivative liabilities current |
|
|
(122,561 |
) |
|
|
|
|
Natural Gas contracts |
|
Derivative liabilities current |
|
|
(1,759 |
) |
|
|
|
|
Crude Oil contracts |
|
Derivative liabilities long-term |
|
|
(4,258 |
) |
|
|
|
|
Natural Gas contracts |
|
Derivative liabilities long-term |
|
|
(981 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments |
|
$ |
(128,744 |
) |
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
For the years ended December 31, 2009, 2008, and 2007, the net effect on income of derivative
financial instruments was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain/(Loss) |
|
|
|
|
|
Recognized in Income |
|
|
|
Location of Gain/(Loss) |
|
Year Ended December 31, |
|
Type of Contract |
|
Recognized in Income |
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
In thousands |
|
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Contracts |
|
Commodity derivative income (expense) |
|
$ |
(229,016 |
) |
|
$ |
228,920 |
|
|
$ |
(24,310 |
) |
Natural Gas Contracts |
|
Commodity derivative income (expense) |
|
|
(7,210 |
) |
|
|
(28,867 |
) |
|
|
5,713 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments |
|
$ |
(236,226 |
) |
|
$ |
200,053 |
|
|
$ |
(18,597 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Note 11. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the measurement date (exit
price). We utilize market data or assumptions that market participants would use in pricing the
asset or liability, including assumptions about risk and the risks inherent in the inputs to the
valuation technique. These inputs can be readily observable, market corroborated, or generally
unobservable. We primarily apply the market approach for recurring fair value measurements and
endeavor to utilize the best available information. Accordingly, we utilize valuation techniques
that maximize the use of observable inputs and minimize the use of unobservable inputs. We are
able to classify fair value balances based on the observability of those inputs. The FASC
establishes a fair value hierarchy that prioritizes the inputs
101
Denbury Resources Inc.
Notes to Consolidated Financial Statements
used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted
prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest
priority to unobservable inputs (level 3 measurement). The three levels of the fair value
hierarchy are as follows:
Level 1 Quoted prices in active markets for identical assets or liabilities as of the
reporting date. For the years ended December 31, 2009 and 2008, we had no level 1 recurring
measurements.
Level 2 Pricing inputs are other than quoted prices in active markets included in level 1,
which are either directly or indirectly observable as of the reported date. Level 2 includes those
financial instruments that are valued using models or other valuation methodologies. These models
are primarily industry-standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and current market and contractual prices
for the underlying instruments, as well as other relevant economic measures. Substantially all of
these assumptions are observable in the marketplace throughout the full term of the instrument, can
be derived from observable data or are supported by observable levels at which transactions are
executed in the marketplace.
Instruments in this category include non-exchange-traded oil and natural gas derivatives such
as over-the-counter swaps. We have included an estimate of nonperformance risk in the fair value
measurement of our oil and natural gas derivative contracts. We have measured nonperformance risk
based upon credit default swaps or credit spreads. At December 31, 2009 and 2008, the fair value
of our oil and natural gas derivative contracts was reduced by $0.8 million and $3.7 million,
respectively, for estimated nonperformance risk.
Level 3 Pricing inputs include significant inputs that are generally less observable from
objective sources. These inputs may be used with internally developed methodologies that result in
managements best estimate of fair value.
The following table sets forth by level within the fair value hierarchy our financial assets
and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009
and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
in Active |
|
|
Observable |
|
|
Unobservable |
|
|
|
|
|
|
Markets |
|
|
Inputs |
|
|
Inputs |
|
|
|
|
In thousands |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
December 31,
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivative contracts |
|
$ |
|
|
|
$ |
815 |
|
|
$ |
|
|
|
$ |
815 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
derivative contracts |
|
|
|
|
|
|
(129,559 |
) |
|
|
|
|
|
|
(129,559 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
(128,744 |
) |
|
$ |
|
|
|
$ |
(128,744 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivative contracts |
|
$ |
|
|
|
$ |
249,746 |
|
|
$ |
|
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
249,746 |
|
|
$ |
|
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth the fair value of financial instruments that are not recorded
at fair value in our Consolidated Financial Statements.
102
Denbury Resources Inc.
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
December 31, 2008 |
|
|
Carrying |
|
Estimated |
|
Carrying |
|
Estimated |
In thousands |
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
9.75% Senior
Subordinated Notes
due 2016 |
|
$ |
399,926 |
|
|
$ |
455,129 |
|
|
$ |
|
|
|
$ |
|
|
7.5% Senior
Subordinated Notes
due 2015 |
|
|
300,513 |
|
|
|
299,250 |
|
|
|
300,599 |
|
|
|
213,000 |
|
7.5% Senior
Subordinated Notes
due 2013 |
|
|
224,369 |
|
|
|
226,125 |
|
|
|
224,174 |
|
|
|
171,000 |
|
Senior Bank Loan |
|
|
125,000 |
|
|
|
122,500 |
|
|
|
75,000 |
|
|
|
64,000 |
|
The fair values of our senior subordinated notes are based on quoted market prices. The
carrying value of our Senior Bank Loan is approximately fair value based on the fact that it is
subject to short-term floating interest rates that approximate the rates available to us for those
periods. We adjusted the estimated fair value measurement of our Senior Bank Loan for estimated
nonperformance risk. This estimated nonperformance risk totaled approximately $2.5 million and
$11.0 million at December 31, 2009 and 2008, respectively, and was determined utilizing industry
credit default swaps. We have other financial instruments consisting primarily of cash, cash
equivalents, short-term receivables and payables that approximate fair value due to the nature of
the instrument and the relatively short maturities.
Note 12. Commitments and Contingencies
We have operating leases for the rental of equipment, office space and vehicles that totaled
$162.2 million, $128.6 million and $143.8 million as of December 31, 2009, 2008 and 2007,
respectively. During the last seven years, we entered into lease financing agreements for
equipment at certain of our oil and natural gas properties and CO2 source fields. These
lease financings totaled $49.3 million during 2009, $6.1 million during 2008, and $27.1 million
during 2007 with associated required monthly payments of approximately $670,000 for the 2009
leases, $56,000 for the 2008 leases, and $257,000 for the 2007 leases. Leases entered into prior
to 2006 have seven-year terms, leases entered into in 2006 through 2008 have 10-year terms, and
leases entered into in 2009 have five to 10-year terms. Rental expense for operating leases
totaled $37.6 million in 2009, $32.3 million in 2008, and $24.6 million in 2007. We have subleased
part of the office space where we have operating leases. The cash payments we will receive under
these contracts total approximately $0.9 million for 2010 through 2012.
In 2005 and 2006, we entered into three agreements with Genesis to transport crude oil and
CO2. These agreements are accounted for as capital leases and are discussed in detail
in Note 3, Related Party Transactions-Genesis. In 2008, we entered into two transactions with
Genesis involving our NEJD Pipeline system and Free State Pipeline, which included a
long-term transportation service agreement for the Free State Pipeline and a 20-year financing
lease for the NEJD Pipeline system. These two transactions are accounted for as financing leases
and are discussed in detail in Note 3, Related Party Transactions-Genesis.
103
Denbury Resources Inc.
Notes to Consolidated Financial Statements
At December 31, 2009, long-term commitments for these items require the following future
minimum rental payments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline |
|
|
|
|
|
|
|
|
|
Financing |
|
|
Capital |
|
|
Operating |
|
In thousands |
|
Leases |
|
|
Leases |
|
|
Leases |
|
2010 |
|
$ |
31,759 |
|
|
$ |
1,974 |
|
|
$ |
27,566 |
|
2011 |
|
|
33,205 |
|
|
|
1,974 |
|
|
|
26,621 |
|
2012 |
|
|
33,438 |
|
|
|
1,272 |
|
|
|
23,248 |
|
2013 |
|
|
33,518 |
|
|
|
700 |
|
|
|
20,544 |
|
2014 |
|
|
33,513 |
|
|
|
673 |
|
|
|
17,145 |
|
Thereafter |
|
|
393,623 |
|
|
|
721 |
|
|
|
47,037 |
|
|
|
|
|
|
|
|
|
|
|
Total minimum lease payments |
|
|
559,056 |
|
|
|
7,314 |
|
|
$ |
162,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Amount representing interest |
|
|
(308,436 |
) |
|
|
(1,366 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value of minimum lease payments |
|
$ |
250,620 |
|
|
$ |
5,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term contracts require us to deliver CO2 to our industrial CO2
customers at various contracted prices, plus we have a CO2 delivery obligation to
Genesis related to three CO2 volumetric production payments (VPPs) (see Note 3).
Based upon the maximum amounts deliverable as stated in the industrial contracts and the volumetric
production payments, we estimate that we may be obligated to deliver up to 433 Bcf of
CO2 to these customers over the next 18 years; however, since the group as a whole has
historically purchased less CO2 than the maximum allowed in their contracts, based on
the current level of deliveries, we project that the amount of CO2 that we will
ultimately be required to deliver would likely be reduced to 165 Bcf. The maximum volume required
in any given year is approximately 136 MMcf/d. Given the size of our proven CO2
reserves at December 31, 2009 (approximately 6.3 Tcf before deducting approximately 127.1 Bcf for
the three VPPs), our current production capabilities and our projected levels of CO2
usage for our own tertiary flooding program, we believe that we can meet these contractual delivery
obligations.
We currently have long-term commitments to purchase manufactured CO2 from eight
proposed gasification plants: four are in the Gulf Coast region and four are in the Midwest region
(Illinois, Indiana and Kentucky area) of the United States. The Midwest plants are not only
conditioned on those specific plants being constructed, but also upon Denbury contracting
additional volumes of CO2 for purchase in the general area of the proposed plants that
would provide an acceptable economic return on the CO2 pipeline that we would need to
construct to transport these volumes to our existing CO2 pipeline system. If all of
these plants are built, these CO2 sources are currently anticipated to provide us with
aggregate CO2 volumes of around 1.2 Bcf/d to 1.9 Bcf/d. Due to the current economic
conditions, the earliest we would expect any plant to be completed and provide CO2 would
be 2014, and there is some doubt as to whether they will be constructed at all. The base price of
CO2 per Mcf from these CO2 sources varies by plant and location, but is
generally higher than our most recent all-in cost of CO2 from our natural sources
(Jackson Dome) using current oil prices. Prices for CO2 delivered from these projects
are expected to be competitive with the cost of our natural CO2 after adjusting for our
estimates of future prices for our share of potential carbon emissions reduction credits. If all
eight plants are built, the aggregate purchase obligation for this CO2 would be around
$280 million per year, assuming a $70 per barrel oil price, before any potential savings from our
share of carbon emissions reduction credits. All of the contracts have price adjustments that
fluctuate based on the price of oil. Construction has not yet commenced on any of these plants,
and their construction is contingent on the satisfactory resolution of various issues, including
financing. While it is likely that not every plant currently under contract will be constructed,
there are several other plants under consideration that could provide CO2 to us that
would either supplement or replace the CO2 volumes from the eight proposed plants for
which we currently have CO2 purchase contracts. We are having ongoing discussions with
several of these other potential sources. We have invested a total of $13.8 million in preferred
stock of one of the proposed plants. All of our investment may later be redeemed, with a return,
or converted to equity after construction financing for the project has been obtained. We have
recorded our investment in this debt security at cost and classified it as held-to-maturity, since
we have the intent and ability to hold it until it is redeemed. The investment is included in
Other assets in our Consolidated Balance Sheets.
104
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The Encore Merger Agreement contains certain termination rights for both Denbury and Encore,
including,
among others, if the Merger is not completed by May 31, 2010. In the event of a termination of
the Merger Agreement under certain circumstances, Encore may be required to pay Denbury a
termination fee of either $60 million or $120 million, or Denbury may be required to pay Encore a
termination fee of either $60 million, $120 million or $300 million, in each case depending on the
circumstances of the termination. In addition, Encore is obligated to reimburse Denbury for up to
$10 million of its expenses related to the Merger if specified termination events occur. In
addition, fee letters executed in conjunction with the financing commitment from JP Morgan require
Denbury to pay up to approximately $48 million in fees if the Merger is not consummated and the
loans do not close.
Denbury is subject to various possible contingencies that arise primarily from interpretation
of federal and state laws and regulations affecting the oil and natural gas industry. Such
contingencies include differing interpretations as to the prices at which oil and natural gas sales
may be made, the prices at which royalty owners may be paid for production from their leases,
environmental issues and other matters. Although management believes that it has complied with the
various laws and regulations, administrative rulings and interpretations thereof, adjustments could
be required as new interpretations and regulations are issued. In addition, production rates,
marketing and environmental matters are subject to regulation by various federal and state
agencies.
Litigation
In connection with the Merger, three shareholder lawsuits styled as class actions have been
filed against Encore Acquisition Company (Encore) and its board of directors. The lawsuits are
entitled Sanjay Israni, Individually and On Behalf of All Others Similarly Situated vs. Encore
Acquisition Company et al. (filed November 4, 2009 in the District Court of Tarrant County, Texas),
Teamsters Allied Benefit Funds, Individually and On Behalf of All Others Similarly Situated vs.
Encore Acquisition Company et al. (filed November 5, 2009 in the Court of Chancery in the State of
Delaware) and Thomas W. Scott, Jr., individually and on behalf of all others similarly situated v.
Encore Acquisition Company et al. (filed November 6, 2009 in the District Court of Tarrant County,
Texas). The Teamsters and Scott lawsuits also name Denbury as a defendant. The complaints generally
allege that (1) Encores directors breached their fiduciary duties in negotiating and approving the
Merger and by administering a sale process that failed to maximize shareholder value and (2)
Encore, and, in the case of the Teamsters and Scott complaints, Denbury aided and abetted Encores
directors in breaching their fiduciary duties. The Teamsters complaint also alleges that Encores
directors and executives stand to receive substantial financial benefits if the transaction is
consummated on its current terms. The plaintiffs in these lawsuits seek, among other things, to
enjoin the Merger and to rescind the Merger Agreement. Encore and Denbury have entered into a
Memorandum of Understanding with the plaintiffs in these lawsuits agreeing in principle to the
settlement of the lawsuits based upon inclusion in our joint proxy
statement/prospectus dated February 5, 2010, mailed to shareholders
of Denbury and Encore in connection with their respective shareholder
meetings to approve the Merger, of
additional disclosures requested by the plaintiffs, and agreeing that the parties to the lawsuits
will use best efforts to enter into a definitive settlement
agreement, which has not yet occurred pending completion of limited
discovery, and to seek court approval for
the settlement which would be binding on all Encore shareholders who do not opt-out of the
settlement. We currently believe the ultimate outcome of the
settlement of these lawsuits will not have a material adverse effect
on our financial position, results of operations or cash flows.
A shareholder suit regarding a compensation matter brought as a derivative action on behalf of
Denbury against Denburys board of directors, entitled Harbor Police Retirement System v. Gareth
Roberts, et al, in the District Court of Dallas County, Texas, was amended during January 2010 to
generally allege breach of the Denbury directors fiduciary duties based upon the further
allegation that the directors approved an unreasonably high purchase price in the Merger. On
February 19, 2010, the plaintiff filed a motion for leave to amend its petition to add proxy
disclosure claims related to the joint proxy statement/prospectus dated February 5, 2010.
The plaintiff seeks monetary damages and equitable relief, and if the motion to amend their
petition is granted, to enjoin the Denbury shareholders meeting. A hearing is currently scheduled
for March 1, 2010 on various pending motions, including a motion to dismiss the complaint. Denbury
believes that its directors have a valid defense to all claims against them, and that the other
allegations in this suit are without merit. Denbury and its directors intend to defend this
litigation vigorously.
We currently believe the ultimate outcome of this lawsuit will not
have a material adverse effect on our financial position, results of
operations or cash flows.
We are involved in other various lawsuits, claims and regulatory proceedings incidental to our
businesses. While we currently believe that the ultimate outcome of these proceedings,
individually and in the aggregate, will not have a material adverse effect on our financial
position or overall trends in results of operations or cash flows, litigation is subject to
inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a
105
Denbury Resources Inc.
Notes to Consolidated Financial Statements
material adverse impact on our net income in the period in which the ruling occurs. We
provide accruals for litigation and claims if we determine that a loss is probable and the amount
can be reasonably estimated.
Note 13. Supplemental Information
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the
current area market price. The loss of any purchaser would not be expected to have a material
adverse effect upon our operations. For the year ended December 31, 2009, two purchasers accounted
for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (52%) and Hunt
Crude Oil Supply Co. (21%). For the year ended December 31, 2008, we had three significant
purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon
Petroleum Company LLC (49%), Hunt Crude Oil Supply Co. (20%) and Crosstex Energy Field Services
Inc. (14%). For the year ended December 31, 2007, three purchasers each accounted for 10% or more
of our oil and natural gas revenues: Marathon Petroleum Company LLC (43%), Hunt Crude Oil Supply
Co. (19%) and Crosstex Energy Field Services Inc. (16%).
Accounts Payable and Accrued Liabilities
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
Accounts payable |
|
$ |
40,140 |
|
|
$ |
111,899 |
|
Accrued exploration and development costs |
|
|
40,375 |
|
|
|
50,571 |
|
Accrued compensation |
|
|
35,292 |
|
|
|
10,746 |
|
Accrued lease operating expense |
|
|
14,512 |
|
|
|
10,014 |
|
Accrued interest |
|
|
24,214 |
|
|
|
6,780 |
|
Taxes payable |
|
|
5,358 |
|
|
|
6,282 |
|
Asset retirement obligations current |
|
|
1,087 |
|
|
|
1,712 |
|
Other |
|
|
8,896 |
|
|
|
4,629 |
|
|
|
|
|
|
|
|
Total |
|
$ |
169,874 |
|
|
$ |
202,633 |
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
In thousands, except shares |
|
2009 |
|
2008 |
|
2007 |
Cash paid for interest, net of amounts capitalized |
|
$ |
20,924 |
|
|
$ |
26,997 |
|
|
$ |
27,892 |
|
Cash paid for income taxes |
|
|
241 |
|
|
|
70,349 |
|
|
|
10,277 |
|
Interest capitalized |
|
|
68,596 |
|
|
|
29,161 |
|
|
|
20,385 |
|
Increase (decrease) in liabilities for capital
expenditures |
|
|
(76,025 |
) |
|
|
59,183 |
|
|
|
(421 |
) |
Common stock issued pursuant to Conroe Field
Acquisition |
|
|
168,723 |
|
|
|
|
|
|
|
|
|
Genesis common units received in lease financing |
|
|
|
|
|
|
25,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market value of restricted stock issued |
|
$ |
13,781 |
|
|
$ |
8,749 |
|
|
$ |
6,487 |
|
Shares of restricted stock issued |
|
|
1,032,896 |
|
|
|
278,973 |
|
|
|
367,108 |
|
106
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 14. Condensed Consolidating Financial Information
Our subordinated debt is fully and unconditionally guaranteed jointly and severally by all of
Denbury Resources Inc.s subsidiaries other than minor subsidiaries, except that with respect to
our $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and Denbury
Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources Inc. is
the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. The results of our equity
interest in Genesis are reflected through the equity method by one of our subsidiaries, Denbury
Gathering & Marketing. Each subsidiary guarantor and the subsidiary co-obligor are 100% owned,
directly or indirectly, by Denbury Resources Inc. The following is condensed consolidating
financial information for Denbury Resources Inc., Denbury Onshore, LLC, and subsidiary guarantors:
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
637,334 |
|
|
$ |
253,601 |
|
|
$ |
20,718 |
|
|
$ |
(655,891 |
) |
|
$ |
255,762 |
|
Property and equipment |
|
|
|
|
|
|
3,482,310 |
|
|
|
220,562 |
|
|
|
|
|
|
|
3,702,872 |
|
Investment in subsidiaries (equity method) |
|
|
1,303,728 |
|
|
|
23,792 |
|
|
|
1,299,186 |
|
|
|
(2,551,689 |
) |
|
|
75,017 |
|
Other assets |
|
|
746,442 |
|
|
|
225,938 |
|
|
|
6,078 |
|
|
|
(742,131 |
) |
|
|
236,327 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,687,504 |
|
|
$ |
3,985,641 |
|
|
$ |
1,546,544 |
|
|
$ |
(3,949,711 |
) |
|
$ |
4,269,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
14,827 |
|
|
$ |
795,486 |
|
|
$ |
239,368 |
|
|
$ |
(655,891 |
) |
|
$ |
393,790 |
|
Long-term liabilities |
|
|
700,440 |
|
|
|
1,942,194 |
|
|
|
3,448 |
|
|
|
(742,131 |
) |
|
|
1,903,951 |
|
Stockholders equity |
|
|
1,972,237 |
|
|
|
1,247,961 |
|
|
|
1,303,728 |
|
|
|
(2,551,689 |
) |
|
|
1,972,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
2,687,504 |
|
|
$ |
3,985,641 |
|
|
$ |
1,546,544 |
|
|
$ |
(3,949,711 |
) |
|
$ |
4,269,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
458,051 |
|
|
$ |
408,940 |
|
|
$ |
14,992 |
|
|
$ |
(466,784 |
) |
|
$ |
415,199 |
|
Property and equipment |
|
|
|
|
|
|
2,973,947 |
|
|
|
28,250 |
|
|
|
|
|
|
|
3,002,197 |
|
Investment in subsidiaries (equity method) |
|
|
1,371,347 |
|
|
|
24,901 |
|
|
|
1,368,759 |
|
|
|
(2,685,003 |
) |
|
|
80,004 |
|
Other assets |
|
|
312,239 |
|
|
|
89,471 |
|
|
|
899 |
|
|
|
(310,335 |
) |
|
|
92,274 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,141,637 |
|
|
$ |
3,497,259 |
|
|
$ |
1,412,900 |
|
|
$ |
(3,462,122 |
) |
|
$ |
3,589,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
970 |
|
|
$ |
810,476 |
|
|
$ |
41,405 |
|
|
$ |
(466,784 |
) |
|
$ |
386,067 |
|
Long-term liabilities |
|
|
300,599 |
|
|
|
1,373,127 |
|
|
|
148 |
|
|
|
(310,335 |
) |
|
|
1,363,539 |
|
Stockholders equity |
|
|
1,840,068 |
|
|
|
1,313,656 |
|
|
|
1,371,347 |
|
|
|
(2,685,003 |
) |
|
|
1,840,068 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
and stockholders
equity |
|
$ |
2,141,637 |
|
|
$ |
3,497,259 |
|
|
$ |
1,412,900 |
|
|
$ |
(3,462,122 |
) |
|
$ |
3,589,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
58,984 |
|
|
$ |
882,492 |
|
|
$ |
1 |
|
|
$ |
(58,984 |
) |
|
$ |
882,493 |
|
Expenses |
|
|
64,348 |
|
|
|
996,138 |
|
|
|
9,837 |
|
|
|
(58,984 |
) |
|
|
1,011,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before the following: |
|
|
(5,364 |
) |
|
|
(113,646 |
) |
|
|
(9,836 |
) |
|
|
|
|
|
|
(128,846 |
) |
Equity in net earnings of subsidiaries |
|
|
(67,689 |
) |
|
|
528 |
|
|
|
(59,635 |
) |
|
|
133,453 |
|
|
|
6,657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
(73,053 |
) |
|
|
(113,118 |
) |
|
|
(69,471 |
) |
|
|
133,453 |
|
|
|
(122,189 |
) |
Income tax provision (benefit) |
|
|
2,103 |
|
|
|
(47,354 |
) |
|
|
(1,782 |
) |
|
|
|
|
|
|
(47,033 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(75,156 |
) |
|
$ |
(65,764 |
) |
|
$ |
(67,689 |
) |
|
$ |
133,453 |
|
|
$ |
(75,156 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
22,500 |
|
|
$ |
1,365,658 |
|
|
$ |
44 |
|
|
$ |
(22,500 |
) |
|
$ |
1,365,702 |
|
Expenses |
|
|
22,982 |
|
|
|
743,033 |
|
|
|
3,313 |
|
|
|
(22,500 |
) |
|
|
746,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(482 |
) |
|
|
622,625 |
|
|
|
(3,269 |
) |
|
|
|
|
|
|
618,874 |
|
Equity in net earnings of subsidiaries |
|
|
408,393 |
|
|
|
666 |
|
|
|
412,100 |
|
|
|
(815,805 |
) |
|
|
5,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
407,911 |
|
|
|
623,291 |
|
|
|
408,831 |
|
|
|
(815,805 |
) |
|
|
624,228 |
|
Income tax provision |
|
|
19,515 |
|
|
|
215,879 |
|
|
|
438 |
|
|
|
|
|
|
|
235,832 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
388,396 |
|
|
$ |
407,412 |
|
|
$ |
408,393 |
|
|
$ |
(815,805 |
) |
|
$ |
388,396 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
19,594 |
|
|
$ |
972,992 |
|
|
$ |
68 |
|
|
$ |
(19,594 |
) |
|
$ |
973,060 |
|
Expenses |
|
|
20,046 |
|
|
|
574,134 |
|
|
|
3,950 |
|
|
|
(19,594 |
) |
|
|
578,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(452 |
) |
|
|
398,858 |
|
|
|
(3,882 |
) |
|
|
|
|
|
|
394,524 |
|
Equity in net earnings of subsidiaries |
|
|
253,970 |
|
|
|
|
|
|
|
256,443 |
|
|
|
(511,523 |
) |
|
|
(1,110 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
253,518 |
|
|
|
398,858 |
|
|
|
252,561 |
|
|
|
(511,523 |
) |
|
|
393,414 |
|
Income tax provision (benefit) |
|
|
371 |
|
|
|
141,305 |
|
|
|
(1,409 |
) |
|
|
|
|
|
|
140,267 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
253,147 |
|
|
$ |
257,553 |
|
|
$ |
253,970 |
|
|
$ |
(511,523 |
) |
|
$ |
253,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statements of Cash Flows
Denbury Resources Inc. (Parent) has no independent assets or operations. Denbury Onshore, LLC
is our operating subsidiary. Cash flow activity of Denbury Resources Inc. consists of intercompany
loans between Denbury Resources Inc. and Denbury Onshore, LLC to service the parent company issued
debt. This intercompany cash flow activity is eliminated in consolidation. Cash flow activity of
Denbury Onshore, LLC combined with the other guarantor subsidiaries is presented in our
Consolidated Statements of Cash Flows.
108
Denbury Resources Inc.
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
|
|
|
$ |
530,460 |
|
|
$ |
139 |
|
|
$ |
|
|
|
$ |
530,599 |
|
Cash flow from investing activities |
|
|
(412,837 |
) |
|
|
(969,714 |
) |
|
|
|
|
|
|
412,837 |
|
|
|
(969,714 |
) |
Cash flow from financing activities |
|
|
412,837 |
|
|
|
442,637 |
|
|
|
|
|
|
|
(412,837 |
) |
|
|
442,637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash |
|
|
|
|
|
|
3,383 |
|
|
|
139 |
|
|
|
|
|
|
|
3,522 |
|
Cash, beginning of period |
|
|
24 |
|
|
|
16,898 |
|
|
|
147 |
|
|
|
|
|
|
|
17,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
24 |
|
|
$ |
20,281 |
|
|
$ |
286 |
|
|
$ |
|
|
|
$ |
20,591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
(10 |
) |
|
$ |
776,112 |
|
|
$ |
(1,583 |
) |
|
$ |
|
|
|
$ |
774,519 |
|
Cash flow from investing activities |
|
|
(29,874 |
) |
|
|
(994,659 |
) |
|
|
|
|
|
|
29,874 |
|
|
|
(994,659 |
) |
Cash flow from financing activities |
|
|
29,874 |
|
|
|
177,102 |
|
|
|
|
|
|
|
(29,874 |
) |
|
|
177,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash |
|
|
(10 |
) |
|
|
(41,445 |
) |
|
|
(1,583 |
) |
|
|
|
|
|
|
(43,038 |
) |
Cash, beginning of period |
|
|
34 |
|
|
|
58,343 |
|
|
|
1,730 |
|
|
|
|
|
|
|
60,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
24 |
|
|
$ |
16,898 |
|
|
$ |
147 |
|
|
$ |
|
|
|
$ |
17,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
33 |
|
|
$ |
570,098 |
|
|
$ |
83 |
|
|
$ |
|
|
|
$ |
570,214 |
|
Cash flow from investing activities |
|
|
(183,204 |
) |
|
|
(762,513 |
) |
|
|
|
|
|
|
183,204 |
|
|
|
(762,513 |
) |
Cash flow from financing activities |
|
|
183,204 |
|
|
|
198,533 |
|
|
|
|
|
|
|
(183,204 |
) |
|
|
198,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash |
|
|
33 |
|
|
|
6,118 |
|
|
|
83 |
|
|
|
|
|
|
|
6,234 |
|
Cash, beginning of period |
|
|
1 |
|
|
|
52,225 |
|
|
|
1,647 |
|
|
|
|
|
|
|
53,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
34 |
|
|
$ |
58,343 |
|
|
$ |
1,730 |
|
|
$ |
|
|
|
$ |
60,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 15. Subsequent Events (Unaudited)
Encore Merger
On October 31, 2009, the Company entered into a definitive merger agreement providing for
Encore Acquisition Company (Encore) to merge with and into the Company. Under the terms of the
definitive agreement, Encore stockholders will receive $50.00 per share for each share of Encore
common stock, comprised of $15.00 in cash and $35.00 in Denbury common stock subject to both an
election feature and a collar mechanism on the stock portion of the consideration. Consummation of
the merger is subject to shareholder approval as well as other customary conditions. Denbury and
Encore each scheduled March 9, 2010 as the date for their respective upcoming special stockholder
meetings, at which time shareholders will vote on, among other items, the merger of Encore with and
into Denbury.
109
Denbury Resources Inc.
Notes to Consolidated Financial Statements
New Senior Subordinated Notes
On February 10, 2010, Denbury issued $1.0 billion of 8.25% Senior Subordinated Notes due 2020
(2020 Notes). The 2020 Notes, which carry a coupon rate of 8.25%, were sold at par. The net
proceeds of approximately $980 million were deposited into escrow. If the merger with Encore does
not occur on or prior to May 31, 2010, or if the merger agreement is terminated at any time, we
will be required to redeem the 8.25% Senior Subordinated Notes at 100% of par, plus accrued and
unpaid interest. After the merger, to the extent that fewer than $600.0 million principal amount of
Encore senior subordinated notes are tendered for repurchase by August 1, 2010, we will be required
to redeem an amount of the 2020 Notes equal to such shortfall.
The 2020 Notes mature on February 15, 2020, and interest is payable on February 15 and August
15 of each year, beginning August 15, 2010. We may redeem the 2020 Notes in whole or in part at
our option beginning February 15, 2015, at the following redemption prices: 104.125% after February
15, 2015, 102.75% after February 15, 2016, 101.375% after February 15, 2017, and 100% after
February 15, 2018. Prior to February 15, 2013, we may at our option redeem up to an aggregate of
35% of the principal amount of the 2020 Notes at a price of 108.25% with the proceeds of certain
equity offerings. In addition, at any time prior to February 15, 2015, we may redeem 100% of
the principal amount of the 2020 Notes at a price equal to 100% of the principal amount plus a
make whole premium and accrued and unpaid interest. The indenture contains certain restrictions
on our ability to incur additional debt, pay dividends on our common stock, make investments,
create liens on our assets, engage in transactions with our affiliates, transfer or sell assets,
consolidate or merge, or sell substantially all of our assets. The 2020 Notes are not subject to
any sinking fund requirements. All of our significant subsidiaries fully and unconditionally
guarantee this debt.
Newly Committed Credit Facility
On October 31, 2009, Denbury received a financing commitment from JP Morgan, subject to
customary conditions, to underwrite a new senior secured revolving credit facility. The newly
committed credit facility, together with the proceeds from the 8.25% Senior Subordinated Notes,
will be used to fund a portion of the cash consideration for the merger with Encore, repay amounts
outstanding under Denburys existing $750 million revolving credit facility, potentially retire and
replace a portion of Encores outstanding senior subordinated notes and to pay other merger-related
expenses. The aggregate commitment of the senior secured lenders is $1.6 billion and the term of
the newly committed credit facility is four years.
Sale of General Partner Ownership in Genesis
On February 5, 2010, we sold our interest in Genesis Energy, LLC to an affiliate of Quintana
Capital Group L.P. (Quintana) for net proceeds of approximately $82 million, calculated as $100
million less adjustments including those related to Genesis management incentive compensation and
other selling costs. This sale gives Quintana control of Genesis general partner. We continue to
own approximately 10% of the outstanding common units of Genesis, for which a resale registration
statement was filed in January 2010.
Equity Award Grant
On January 4, 2010, we granted equity incentive awards to our employees under the 2004 Plan.
The grant included 659,509 shares of restricted stock valued at $15.63 per share and 1,780,276 SARs
with an exercise price of $15.63 and a weighted average grant date fair value of $8.22 per unit.
The awards generally vest 25% per year over a four-year period.
Note 16. Supplemental Oil and Natural Gas Disclosures (Unaudited)
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and natural gas property
acquisition, exploration and development activities. Property acquisition costs are those costs
incurred to purchase, lease, or otherwise acquire property, including both undeveloped leasehold
and the purchase of reserves in place. Exploration costs include costs of identifying areas that
may warrant examination and examining specific areas that are considered to have prospects
containing oil and natural gas reserves, including costs of drilling exploratory wells, geological
and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred
to obtain access to proved reserves, including the cost of drilling development wells, and to
provide
facilities for extracting, treating, gathering and storing the oil and natural gas, and the
cost of improved recovery systems.
110
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The Company capitalizes interest on unevaluated oil and gas properties that have ongoing
development activities. Included in the costs incurred below are capitalized interest of $14.3
million in 2009, $17.6 million in 2008 and $18.3 million in 2007. Costs incurred also include new
asset retirement obligations established, as well as changes to asset retirement obligations
resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations
included in the table below were $11.2 million in 2009, $5.8 million in 2008 and $7.5 million in
2007 (see Note 4, Asset Retirement Obligations).
Costs incurred in oil and natural gas activities were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Property acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
585,637 |
|
|
$ |
32,781 |
|
|
$ |
15,531 |
|
Unevaluated |
|
|
104,772 |
|
|
|
16,129 |
|
|
|
60,079 |
|
Exploration |
|
|
4,635 |
|
|
|
5,710 |
|
|
|
42,726 |
|
Development |
|
|
292,545 |
|
|
|
575,947 |
|
|
|
553,315 |
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred (1) |
|
$ |
987,589 |
|
|
$ |
630,567 |
|
|
$ |
671,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Capitalized general and administrative costs that directly relate
to exploration and development activities were $14.0 million,
$12.5 million and $10.3 million for the years ended December 31,
2009, 2008, 2007, respectively. |
Oil and Natural Gas Operating Results
Results of operations from oil and natural gas producing activities, excluding corporate
overhead and interest costs, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands, except per BOE data |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Oil, natural gas and related product sales |
|
$ |
866,709 |
|
|
$ |
1,347,010 |
|
|
$ |
952,788 |
|
|
Lease operating costs |
|
|
326,132 |
|
|
|
307,550 |
|
|
|
230,932 |
|
Production taxes and marketing expenses |
|
|
42,484 |
|
|
|
63,752 |
|
|
|
49,091 |
|
Depletion, depreciation and amortization |
|
|
206,999 |
|
|
|
195,839 |
|
|
|
177,333 |
|
CO2 depletion, depreciation and amortization (1) |
|
|
29,076 |
|
|
|
16,771 |
|
|
|
9,403 |
|
Write-down of oil and natural gas properties |
|
|
|
|
|
|
226,000 |
|
|
|
|
|
Commodity derivative expense (income) |
|
|
236,226 |
|
|
|
(200,053 |
) |
|
|
18,597 |
|
|
|
|
|
|
|
|
|
|
|
Net operating income |
|
|
25,792 |
|
|
|
737,151 |
|
|
|
467,432 |
|
Income tax provision |
|
|
9,927 |
|
|
|
278,643 |
|
|
|
177,624 |
|
|
|
|
|
|
|
|
|
|
|
Results of
operations from oil
and natural gas
producing
activities |
|
$ |
15,865 |
|
|
$ |
458,508 |
|
|
$ |
289,808 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization per BOE |
|
$ |
13.39 |
|
|
$ |
12.54 |
|
|
$ |
11.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents an allocation of the depletion, depreciation and
amortization of our CO2 properties and pipelines associated with
our tertiary oil producing activities. |
111
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Oil and Natural Gas Reserves
Effective December 31, 2009, the Company adopted new guidance issued by the SEC related to the
quantification of oil and natural gas reserves (see Note 1, Significant Accounting Policies
Recently Adopted Accounting Pronouncements). The SECs new guidance enhances disclosures related
to oil and natural gas reserves, permits the use of new technology to quantify reserves, and
adjusts the pricing used to determine proved reserves. Estimates of reserves as of year-end 2009
were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon
prices received on a field-by-field basis on the first day of each month within the 12-month period
ended December 31, 2009. Estimates of reserves as of year-end 2007 and 2008 were prepared using
constant prices and costs in accordance with previous guidelines of the Securities and Exchange
Commission based on hydrocarbon prices received on a field-by-field basis as of December
31st of each year. The adoption of the new guidance did not have a material impact on
Denburys estimate of proved reserves at December 31, 2009. The standardized measure of discounted
future net cash flows as of December 31, 2009, reflects a
decrease of $1.1 billion as a result of the
change in sales prices resulting from new pricing guidelines.
Net proved oil and natural gas reserve estimates for all years presented were prepared by
DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. Reserve
estimates do not include any value for probable or possible reserves that may exist, nor do they
include any value for undeveloped acreage. The reserve estimates represent our net revenue
interest in our properties. (See Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves below for a discussion of the
effect of the different prices on reserve quantities and values.) Operating costs, production and
ad valorem taxes and future development costs were based on current costs.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in
projecting the future rates of production and timing of development expenditures. The following
reserve data represents estimates only and should not be construed as being exact. Moreover, the
present values should not be construed as the current market value of our oil and natural gas
reserves or the costs that would be incurred to obtain equivalent reserves. All of our reserves
are located in the United States.
Estimated Quantities of Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2009 |
|
2008 |
|
2007 |
|
|
Oil |
|
Gas |
|
Oil |
|
Gas |
|
Oil |
|
Gas |
|
|
(MBbl) |
|
(MMcf) |
|
(MBbl) |
|
(MMcf) |
|
(MBbl) |
|
(MMcf) |
Balance at beginning of year |
|
|
179,126 |
|
|
|
427,955 |
|
|
|
134,978 |
|
|
|
358,608 |
|
|
|
126,185 |
|
|
|
288,826 |
|
Revisions of previous estimates |
|
|
(69 |
) |
|
|
(1,298 |
) |
|
|
1,348 |
|
|
|
10,291 |
|
|
|
(1,601 |
) |
|
|
1,478 |
|
Revisions due to price changes |
|
|
4,557 |
|
|
|
(2,079 |
) |
|
|
(13,320 |
) |
|
|
(2,915 |
) |
|
|
1,538 |
|
|
|
(355 |
) |
Extensions and discoveries |
|
|
334 |
|
|
|
11,785 |
|
|
|
5,037 |
|
|
|
107,020 |
|
|
|
6,887 |
|
|
|
131,451 |
|
Improved recovery(1) |
|
|
13,875 |
|
|
|
|
|
|
|
59,317 |
|
|
|
|
|
|
|
12,376 |
|
|
|
|
|
Production |
|
|
(13,495 |
) |
|
|
(24,764 |
) |
|
|
(11,505 |
) |
|
|
(32,736 |
) |
|
|
(10,193 |
) |
|
|
(35,456 |
) |
Acquisition of minerals in place |
|
|
28,379 |
|
|
|
2,317 |
|
|
|
3,653 |
|
|
|
79 |
|
|
|
405 |
|
|
|
1,935 |
|
Sales of minerals in place |
|
|
(19,828 |
) |
|
|
(325,941 |
) |
|
|
(382 |
) |
|
|
(12,392 |
) |
|
|
(619 |
) |
|
|
(29,271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year |
|
|
192,879 |
|
|
|
87,975 |
|
|
|
179,126 |
|
|
|
427,955 |
|
|
|
134,978 |
|
|
|
358,608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of year |
|
|
96,746 |
|
|
|
298,114 |
|
|
|
97,005 |
|
|
|
226,271 |
|
|
|
83,703 |
|
|
|
176,648 |
|
Balance at end of year |
|
|
116,192 |
|
|
|
69,513 |
|
|
|
96,746 |
|
|
|
298,114 |
|
|
|
97,005 |
|
|
|
226,271 |
|
|
|
|
(1) |
|
Improved recovery additions result from the application of
secondary recovery methods such as water-flooding or tertiary
recovery methods such as CO2 flooding. |
112
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Acquisitions of minerals in place during 2009 were primarily from the Conroe Field and
Hastings Field acquisitions. The sales of minerals in place during 2009 were primarily due to the
sale of our Barnett Shale assets. We added 17.6 MMBbls of tertiary related proved oil reserves
during 2009, primarily initial proved tertiary oil reserves at Cranfield Field in Phase 4, plus
additional reserves at Tinsley, Heidelberg and Eucutta Fields. In order to recognize proved
tertiary oil reserves, we must either have an oil production response to CO2 injections
or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that
we can book in any given year will depend on our progress with new floods and the timing of the
production response.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to
Proved Oil and Natural Gas Reserves (Standardized Measure) does not purport to present the fair
market value of our oil and natural gas properties. An estimate of such value should consider,
among other factors, anticipated future prices of oil and natural gas, the probability of
recoveries in excess of existing proved reserves, the value of probable reserves and acreage
prospects, and perhaps different discount rates. It should be noted that estimates of reserve
quantities, especially from new discoveries, are inherently imprecise and subject to substantial
revision.
Under the Standardized Measure, 2009 future cash inflows were estimated by applying a
first-day-of-the-month 12-month average price to the estimated future production of year-end proved
reserves. Prior to 2009, future cash inflows were estimated by applying year-end prices to the
estimated future production of year-end proved reserves. The product prices used in calculating
these reserves have varied widely during the three-year period. These prices have a significant
impact on both the quantities and value of the proved reserves as reductions in oil and gas prices
can cause wells to reach the end of their economic life much sooner and can make certain proved
undeveloped locations uneconomical, both of which reduce the reserves. The following
representative oil and natural gas prices were used in the Standardized Measure. These prices were
adjusted by field to arrive at the appropriate corporate net price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2009 |
|
2008 |
|
2007 |
Oil (NYMEX)
|
|
$ |
61.18 |
|
|
$ |
44.60 |
|
|
$ |
95.98 |
|
Natural Gas (Henry Hub)
|
|
|
3.87 |
|
|
|
5.71 |
|
|
|
6.80 |
|
Future cash inflows were reduced by estimated future production, development and abandonment
costs based on current cost with no escalation to determine pre-tax cash inflows. Future income
taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over
our tax basis in the associated proved oil and natural gas properties. Tax credits and net
operating loss carryforwards were also considered in the future income tax calculation. Future net
cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the
Standardized Measure.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Future cash inflows |
|
$ |
11,579,159 |
|
|
$ |
9,024,224 |
|
|
$ |
14,082,865 |
|
Future production costs |
|
|
(5,034,393 |
) |
|
|
(4,039,898 |
) |
|
|
(3,687,197 |
) |
Future development costs |
|
|
(836,455 |
) |
|
|
(944,716 |
) |
|
|
(605,638 |
) |
Future income taxes |
|
|
(1,257,844 |
) |
|
|
(1,071,939 |
) |
|
|
(3,283,702 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
4,450,467 |
|
|
|
2,967,671 |
|
|
|
6,506,328 |
|
10% annual discount for estimated timing of cash flows |
|
|
(1,993,082 |
) |
|
|
(1,552,173 |
) |
|
|
(2,966,711 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of
discounted future net cash
flows |
|
$ |
2,457,385 |
|
|
$ |
1,415,498 |
|
|
$ |
3,539,617 |
|
|
|
|
|
|
|
|
|
|
|
113
Denbury Resources Inc.
Notes to Consolidated Financial Statements
The following table sets forth an analysis of changes in the Standardized Measure of
Discounted Future Net Cash Flows from proved oil and natural gas reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2007 |
|
Beginning of year |
|
$ |
1,415,498 |
|
|
$ |
3,539,617 |
|
|
$ |
1,837,341 |
|
Sales of oil and natural gas produced, net of production costs |
|
|
(498,093 |
) |
|
|
(975,708 |
) |
|
|
(672,765 |
) |
Net changes in sales prices |
|
|
1,263,346 |
|
|
|
(3,296,580 |
) |
|
|
2,346,008 |
|
Extensions and discoveries, less applicable future development
and production costs |
|
|
6,735 |
|
|
|
142,199 |
|
|
|
344,615 |
|
Improved recovery(1) |
|
|
202,145 |
|
|
|
338,313 |
|
|
|
513,840 |
|
Previously estimated development costs incurred |
|
|
98,659 |
|
|
|
157,321 |
|
|
|
192,696 |
|
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production |
|
|
(63,044 |
) |
|
|
(321,733 |
) |
|
|
(214,994 |
) |
Accretion of discount |
|
|
192,686 |
|
|
|
538,512 |
|
|
|
269,520 |
|
Acquisition of minerals in place |
|
|
365,771 |
|
|
|
12,764 |
|
|
|
32,212 |
|
Sales of minerals in place |
|
|
(419,601 |
) |
|
|
(53,356 |
) |
|
|
(121,209 |
) |
Net change in income taxes |
|
|
(106,717 |
) |
|
|
1,334,149 |
|
|
|
(987,647 |
) |
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
2,457,385 |
|
|
$ |
1,415,498 |
|
|
$ |
3,539,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Improved recovery additions result from the application of
secondary recovery methods such as water flooding or tertiary
recovery methods such as CO2 flooding. |
CO2 Reserves
Based on engineering reports prepared by DeGolyer and MacNaughton, our CO2
reserves, on a 100% working interest basis, were estimated at approximately 6.3 Tcf at
December 31, 2009 (includes 127.1 Bcf of reserves dedicated to three volumetric production payments
with Genesis), 5.6 Tcf at December 31, 2008 (includes 153.8 Bcf of reserves dedicated to three
volumetric production payments with Genesis), and 5.6 Tcf at December 31, 2007 (includes 182.3 Bcf
of reserves dedicated to three volumetric production payments with Genesis). We make reference to
the gross amount of proved reserves as that is the amount that is available both for Denburys
tertiary recovery programs and for industrial users who are customers of Denbury and others, as we
are responsible for distributing the entire CO2 production stream for both of these
purposes.
114
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 17. Unaudited Quarterly Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands, except per share amounts |
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 |
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
171,821 |
|
|
$ |
215,362 |
|
|
$ |
225,415 |
|
|
$ |
269,895 |
|
Expenses(1) |
|
|
202,734 |
|
|
|
358,060 |
|
|
|
185,987 |
|
|
|
264,558 |
|
Net income (loss) |
|
|
(18,297 |
) |
|
|
(87,240 |
) |
|
|
26,885 |
|
|
|
3,496 |
|
Net income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
(0.07 |
) |
|
|
(0.35 |
) |
|
|
0.11 |
|
|
|
0.01 |
|
Diluted |
|
|
(0.07 |
) |
|
|
(0.35 |
) |
|
|
0.11 |
|
|
|
0.01 |
|
Cash flow from operations |
|
|
112,619 |
|
|
|
148,170 |
|
|
|
145,645 |
|
|
|
124,165 |
|
Cash flow used for investing activities(2) |
|
|
(509,539 |
) |
|
|
(65,301 |
) |
|
|
(161,550 |
) |
|
|
(233,324 |
) |
Cash flow provided by (used for) financing activities(3) |
|
|
398,058 |
|
|
|
(41,117 |
) |
|
|
(22,365 |
) |
|
|
108,061 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
317,255 |
|
|
$ |
417,049 |
|
|
$ |
407,474 |
|
|
$ |
223,924 |
|
Expenses(4) |
|
|
201,446 |
|
|
|
234,310 |
|
|
|
156,537 |
|
|
|
154,535 |
|
Net income |
|
|
73,002 |
|
|
|
114,053 |
|
|
|
157,548 |
|
|
|
43,793 |
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
0.30 |
|
|
|
0.47 |
|
|
|
0.64 |
|
|
|
0.18 |
|
Diluted |
|
|
0.29 |
|
|
|
0.45 |
|
|
|
0.63 |
|
|
|
0.18 |
|
Cash flow from operations |
|
|
206,257 |
|
|
|
164,072 |
|
|
|
262,442 |
|
|
|
141,748 |
|
Cash flow used for investing activities(5) |
|
|
(163,688 |
) |
|
|
(218,384 |
) |
|
|
(235,605 |
) |
|
|
(376,982 |
) |
Cash flow provided by (used for) financing activities(6) |
|
|
(28,637 |
) |
|
|
127,282 |
|
|
|
1,464 |
|
|
|
76,993 |
|
|
|
|
(1) |
|
Includes commodity derivative expense (income) of $20.5 million during the first quarter of 2009,
$152.8 million during the second quarter of 2009, $3.7 million during the third quarter of 2009, and
$59.2 million during the fourth quarter of 2009. Also includes expenses related to the incentive
compensation awards for the management of Genesis in the amount of $14.2 million in 2009 (see Note
3, Related Party Transactions Genesis.). In June 2009, we expensed a $10.0 million ($3.65
million in cash and $6.35 million of the Companys 9.75% Senior Subordinated Notes due 2016)
compensation charge associated with retirement of Gareth Roberts as CEO and President of the
Company. During the fourth quarter of 2009, we incurred $8.7 million in expenses related to the
Encore acquisition (see Note 2, Acquisitions and Divestitures.) |
|
(2) |
|
During the first quarter of 2009, we made cash payments of
approximately $197.9 million associated
with the Hasting Field Acquisition. During June and July of 2009, we received cash payments of
approximately $197.5 million and $62.3 million, respectively, for the sale of 60% of our Barnett
Shale natural gas assets. During the fourth quarter of 2009, we received cash payments of
approximately $210.0 million for the sale of our remaining 40% interests in our Barnett Shale
natural gas assets. During the fourth quarter of 2009, we acquired
Conroe Field for a cash payment
of approximately $254.2 million and 11,620,000 shares of Denbury common stock (see Note 2,
Acquisitions and Divestitures.) |
|
(3) |
|
In the first quarter of 2009, we issued $420 million of 9.75% Senior Subordinated Notes due 2016,
and received net proceeds of $381.4 million (see Note 6, Long-term Debt.) |
|
(4) |
|
Includes commodity derivative expense (income) of $46.8 million in the first quarter of 2008, $58.8
million in the second quarter of 2008, ($62.0) million in the third quarter of 2008, and ($243.6)
million in the fourth quarter of 2008. We had a full cost ceiling write-down of $226 million during
the fourth quarter of 2008. In addition, during the third quarter of 2008, we expensed approximately
$30 million associated with a non-refundable deposit on a cancelled acquisition. |
|
(5) |
|
In December 2007 and February 2008, we received cash proceeds of $108.6 million and $48.9 million,
respectively, for the sale of our Louisiana natural gas assets (see Note 2, Acquisitions and
Divestitures.) |
|
(6) |
|
In the second quarter of 2008, we received $225 million in cash from two financing leases entered
into with Genesis (see Note 3, Related Party Transactions Genesis). Also during 2008, we had
net borrowings of $75 million during the fourth quarter, and net payments of $39 million during the
first quarter, and $111 million in the second quarter, all under our senior bank loan. |
115
Denbury Resources Inc.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the
design and operation of the Companys disclosure controls and procedures (as defined in Rule
13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of
the Companys management, including our Chief Executive Officer and our Chief
Financial Officer. Based on that evaluation, the Companys Chief Executive Officer
and our Chief Financial Officer concluded that the Companys disclosure controls and procedures
were effective as of December 31, 2009 to ensure: that information required to be disclosed in the
reports it files and submits under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SECs rules and forms; and that
information that is required to be disclosed under the Exchange Act is accumulated and communicated
to the Companys management, including our Chief Executive Officer and our Chief
Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Evaluation of Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of our management, including our
Chief Executive Officer and our Chief Financial Officer, we have determined that, during the
fourth quarter of fiscal 2009, there were no changes in our internal control over financial
reporting that have materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
Managements Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of
1934, as amended. Under the supervision and with the participation of our management, including
our Chief Executive Officer and our Chief Financial Officer, we assessed the
effectiveness of our internal control over financial reporting as of the end of the period covered
by this report based on the framework in Internal ControlIntegrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our
Chief Executive Officer and our Chief Financial Officer concluded that our internal
control over financial reporting was effective to provide reasonable assurance regarding the
reliability of our financial reporting and the preparation of our financial statements for external
purposes in accordance with U.S. generally accepted accounting principles.
The effectiveness of the Companys internal control over financial reporting as of December
31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which appears herein.
Important Considerations
The effectiveness of our disclosure controls and procedures and our internal control over
financial reporting is subject to various inherent limitations, including cost limitations,
judgments used in decision making, assumptions about the likelihood of future events, the soundness
of our systems, the possibility of human error, and the risk of fraud. Moreover, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions and the risk that the degree of compliance with
policies or procedures may deteriorate over time. Because of these limitations, there can be no
assurance that any system of disclosure controls and procedures or internal control over financial
reporting will be successful in preventing all
116
Denbury Resources Inc.
errors or fraud or in making all material information known in a timely manner to the
appropriate levels of management.
Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and Corporate Governance
Except as disclosed below, information as to Item 10 will be set forth in the Proxy Statement
(Proxy Statement) for the Annual Meeting of Shareholders to be held May 19, 2010, (Annual
Meeting) and is incorporated herein by reference.
Code of Ethics
We have adopted a Code of Ethics for Senior Financial Officers and the Principal Executive
Officer. This Code of Ethics, including any amendments or waivers, is posted on our website at
www.denbury.com.
Item 11. Executive Compensation
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and
is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and
is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and
is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and
is incorporated herein by reference.
117
Denbury Resources Inc.
PART IV
Item 15. Exhibits and Financial Statement Schedules
Financial Statements and Schedules. Financial statements and schedules filed as a part of this
report are presented on page 69. All financial statement schedules have been omitted because they are
not applicable or the required information is presented in the financial statements or the notes to
consolidated financial statements.
Exhibits. The following exhibits are filed as part of this report.
|
|
|
Exhibit |
|
|
No. |
|
Exhibit |
2
|
|
Agreement and Plan of Merger by and between Encore Acquisition Company and Denbury Resources
Inc. Executed on October 31, 2009 (incorporated by reference as Exhibit 2.1 of our Form 8-K
filed November 5, 2009). |
|
|
|
3(a)
|
|
Restated Certificate of Incorporation of Denbury Resources Inc. filed with the Delaware
Secretary of State on December 29, 2003 (incorporated by reference as Exhibit 3.1 of our Form
8-K filed December 29, 2003). |
|
|
|
3(b)
|
|
Certificate of Amendment of Restated Certificate of Incorporation of Denbury Resources Inc.
filed
with the Delaware Secretary of State on October 20, 2006 (incorporated by reference as Exhibit
3(a) of our Form 10-Q filed November 8, 2005). |
|
|
|
3(c)
|
|
Certificate of Amendment of Restated Certificate of Incorporation of Denbury Resources Inc.
filed
with the Delaware Secretary of State on November 21, 2007 (incorporated by reference as
Exhibit 3(c) of our Form 10-K filed February 29, 2008). |
|
|
|
3(d)
|
|
Bylaws of Denbury Resources Inc., a Delaware corporation, adopted December 29, 2003
(incorporated by reference as Exhibit 3.2 of our Form 8-K filed December 29, 2003). |
|
|
|
4(a)
|
|
Indenture for $225 million of 7.5% Senior Subordinated Notes due 2013 among Denbury
Resources Inc., certain of its subsidiaries and JP Morgan Chase Bank as trustee, dated March
25,
2003 (incorporated by reference as Exhibit 4(a) of our Registration Statement No. 333-105233-
04 on Form S-4, filed May 14, 2003). |
|
|
|
4(b)
|
|
First Supplemental Indenture to
Indenture for $225 million of 7.5% Senior Subordinated Notes due 2013 dated
as of December 29, 2003, among Denbury Resources Inc., certain of its subsidiaries, and JP
Morgan Chase Bank, as trustee (incorporated by reference as Exhibit 4.1 of our Form 8-K filed
December 29, 2003). |
|
|
|
4(c)*
|
|
Second Supplemental Indenture to
Indenture for $225 million of 7.5% Senior Subordinated Notes due 2013
dated as of July 24, 2009, among Denbury Resources Inc., certain of
its subsidiaries, and JP Morgan Chase Bank, as trustee. |
|
4(d)
|
|
Indenture for $150 million of 7.5% Senior Subordinated Notes due 2015 among Denbury
Resources Inc., certain of its subsidiaries, and JP Morgan Chase Bank, as trustee
(incorporated by reference as Exhibit 4.1 of our Form 8-K filed December 9, 2005). |
|
|
|
4(e)
|
|
First Supplemental Indenture for $150 million of 7.5% Senior Subordinated Notes due 2015,
dated April 3, 2008, between Denbury Resources Inc., as issuer, and The Bank of New York Trust
Company, N.A., as Trustee (incorporated by reference as Exhibit 4.1 of our Form 8-K filed
April 3, 2007). |
|
|
|
4(f)*
|
|
Second Supplemental Indenture to Indenture for $150 million of 7.5% Senior Subordinated Notes due 2015, dated July 24, 2009, between Denbury Resources Inc., as issuer, and The Bank of New York Trust Company, N.A., as Trustee. |
|
|
|
4(g)
|
|
Indenture for $420 million of 9.75% Senior Subordinated Notes due 2016 among Denbury Resources
Inc., certain of its subsidiaries, and The Bank of New York Mellon Trust Company, N.A., as
Trustee (incorporated by reference as Exhibit 4.1 of our Form 8-K filed February 17, 2009). |
|
|
|
4(h)*
|
|
First Supplemental Indenture to
Indenture for
$420 million of 9.75% Senior Subordinated Notes due 2016,
dated June 30, 2009, between Denbury Resources Inc., as issuer,
and The Bank of New York Mellon Trust
Company, N.A., as Trustee. |
|
|
|
4(i)
|
|
Indenture for $1 billion of 81/4% Senior Subordinated Notes due 2020 among Denbury Resources
Inc., certain of its subsidiaries, and Wells Fargo, National Association, as Trustee
(incorporated by reference as Exhibit 4.1 of our Form 8-K filed February 12, 2010). |
|
|
|
4(j)
|
|
Registration Rights Agreement dated as of December 18, 2009 (incorporated by reference as
Exhibit 4.1 of our Form 8-K filed December 23, 2009). |
|
|
|
10(a)
|
|
Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower,
Denbury Resources Inc., as Parent Guarantor and JPMorgan Chase Bank, N.A., as Administrative
Agent, and certain other financial institutions, dated September 14, 2007 (incorporated by
reference as Exhibit 10.1 of our Form 8-K filed September 19, 2006). |
|
|
|
10(b)
|
|
First Amendment to Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as
Borrower, Denbury Resources Inc., as Parent Guarantor, JPMorgan Chase Bank, N.A., as |
118
Denbury Resources Inc.
|
|
|
Exhibit |
|
|
No. |
|
Exhibit |
|
|
Administrative Agent and certain other financial institutions effective March 31, 2008
(incorporated by reference as Exhibit 10 of our Form 10-Q for the quarter ended March 31,
2007). |
|
|
|
10(c)
|
|
Second Amendment to Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as
Borrower, Denbury Resources Inc., as Parent Guarantor, JPMorgan Chase Bank, N.A., as
Administrative Agent, and certain other financial institutions dated as of October 7, 2008
(incorporated by reference as Exhibit 10(a) of our Form 10-Q for the quarter ended September
30, 2008). |
|
|
|
10(d)
|
|
Third Amendment to Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as
Borrower, Denbury Resources Inc., as Parent Guarantor, JPMorgan Chase Bank, N.A., as
Administrative Agent, and certain other financial institutions dated
as of February 6, 2009 (incorporated by reference as Exhibit
10(d) of our Form 10-K for the year ended December 31, 2008). |
|
|
|
10(e)
|
|
Amendment for Increased Borrowing Base from $500 million to $1.0 billion to Sixth Amended and
Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, and JPMorgan Chase Bank,
N.A., as Administrative Agent, and certain other financial institutions dated as of March 28,
2008 (incorporated by reference as Exhibit 10(a) of our Form 10-Q for the quarter ended March
31, 2008). |
|
|
|
10(f)
|
|
Fourth Amendment to Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as
Borrower, Denbury Resources Inc., as Parent Guarantor, JPMorgan Chase Bank, N.A., as
Administrative Agent, and certain other financial institutions, dated as of December 16, 2009
(incorporated by reference as Exhibit 99.1 of our Form 8-K filed December 23, 2009). |
|
|
|
10(g)*
|
|
Fifth Amendment to Sixth Amended
and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower,
Denbury Resources Inc., as Parent Guarantor, JPMorgan Chase Bank,
N.A., as Administrative Agent, and certain other financial
institutions, dated as of January 22, 2010. |
|
|
|
10(h)*
|
|
Sixth Amendment to Sixth Amended
and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower,
Denbury Resources Inc., as Parent Guarantor, JPMorgan Chase Bank,
N.A., as Administrative Agent, and certain other financial
institutions, dated as of January 29, 2010. |
|
|
|
10(i)
|
|
Pipeline Financing Lease Agreement by and between Genesis NEJD Pipeline, LLC as Lessor, and
Denbury Onshore, LLC, as Lessee, dated May 30, 2008 (incorporated by reference as Exhibit 99.1
of our Form 8-K filed on June 5, 2008). |
|
|
|
10(j)
|
|
Transportation Services Agreement by and between Genesis Free State Pipeline, LLC and Denbury
Onshore, LLC, dated May 30, 2008 (incorporated by reference as Exhibit 99.2 of our Form 8-K
filed on June 5, 2008). |
|
|
|
10(k)**
|
|
Denbury Resources Inc. Amended and Restated Stock Option Plan as of December 5, 2007
(incorporated by reference as Exhibit 99.2 of our Form 8-K, filed December 11, 2007). |
|
|
|
10(l)**
|
|
Denbury Resources Inc. Stock Purchase Plan, as amended and restated December 5, 2007
(incorporated by reference as Exhibit 99.4 of our Form 8-K, filed December 11, 2007). |
|
|
|
10(m)**
|
|
Form of indemnification agreement between Denbury Resources Inc. and its officers and
directors (incorporated by reference as Exhibit 10 of our Form 10-Q for the quarter ended June
30, 1999). |
|
|
|
10(n)**
|
|
Denbury Resources Inc. Directors Compensation Plan (incorporated by reference as Exhibit 4 of
our Registration Statement on Form S-8, No. 333-39172, filed June 13, 2000, amended March
2, 2001 and May 11, 2006). |
|
|
|
10(o)**
|
|
Denbury Resources Severance Protection Plan, as amended and restated effective December 30,
2008 (incorporated by reference as Exhibit 10(n) of our Form 10-K for the year ended December
31, 2008). |
|
|
|
10(p)**
|
|
Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated
effective December 30, 2008 (incorporated by reference as Exhibit 10(o) of our Form 10-K for
the year ended December 31, 2008). |
|
|
|
10(q)**
|
|
2006 Form of stock appreciation rights agreement that vests 100% four years from the date of
grant, for grants to employees and officers pursuant to 2004 Omnibus Stock and Incentive Plan
for Denbury Resources Inc. (incorporated by reference as Exhibit 10(w) of our Form 10-K for
the year ended December 31, 2006). |
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10(r)**
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|
2006 Form of stock appreciation rights agreement that cliff vests 100% four years from the
date of grant, for grants to directors pursuant to 2004 Omnibus Stock and Incentive Plan for
Denbury Resources Inc. (incorporated by reference as Exhibit 10(x) of our Form 10-K for the
year ended December 31, 2006). |
119
Denbury Resources Inc.
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Exhibit |
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No. |
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Exhibit |
10(s)**
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|
2006 Form of restricted stock award that vests 25% per annum, for grants to new employees and
officers on their hire date pursuant to 2004 Omnibus and Incentive Plan for Denbury Resources
Inc. (incorporated by reference as Exhibit 10(y) of our Form 10-K for the year ended December
31, 2006). |
|
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10(t)**
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|
2006 Form of restricted stock award that cliff vests 100% four years from the date of grant
for grants to employees and officers pursuant to 2004 Omnibus Stock and Incentive Plan for
Denbury Resources Inc. (incorporated by reference as Exhibit 10(z) of our Form 10-K for the
year ended December 31, 2006). |
|
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10(u)**
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|
2007 Form of restricted stock award to officers that cliff vests on March 31, 2010 pursuant to
2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference as
Exhibit 10(y) of our Form 10-K for the year ended December 31, 2008). |
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10(v)**
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|
2007 Form of performance share awards to officers pursuant to 2004 Omnibus Stock and Incentive
Plan for Denbury Resources Inc. (incorporated by reference as Exhibit 10(z) of our Form 10-K
for the year Ended December 31, 2007). |
|
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10(w)**
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|
2007 Form of restricted stock award to directors that cliff vests after three years pursuant
to 2004 Omnibus Stock and Incentive Plan (incorporated by reference as Exhibit 10(cc) of our
Form 10-K for the year ended December 31, 2007). |
|
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10(x)**
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2007 Form of restricted stock award to new directors that vest 20% per annum (incorporated by
reference as Exhibit 10(z) of our Form 10-K for the year ended December 31, 2007). |
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10(y)**
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Form of deferred payment cash award that cliff vests 100% four years from the date of grant
for grants to employees and officers (incorporated by reference as exhibit 10(bb) of our Form
10-K for the year ended December 31, 2005). |
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10(z)**
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2008 Form of restricted stock award to certain officers that cliff vests on March 31, 2011
(incorporated by reference as Exhibit 10(b) of our Form 10-Q for the first quarter ended March
31, 2008). |
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10(aa)**
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2008 Form of restricted stock award without change of control vesting to certain officers that
cliff vests on March 31, 2011 (incorporated by reference as Exhibit 10(c) of our Form 10-Q for
the first quarter ended March 31, 2008). |
|
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10(bb)**
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2008 Form of performance share awards to certain officers with change of control vesting
(incorporated by reference as Exhibit 10(d) of our Form 10-Q for the first quarter ended March
31, 2008). |
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10(cc)**
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2008 Form of performance share awards to certain officers without change of control vesting
(incorporated by reference as Exhibit 10(e) of our Form 10-Q for the first quarter ended March
31, 2008). |
|
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10(dd)**
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|
2004 Form of restricted stock award that vests 20% per annum, for grants to officers pursuant
to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference
as Exhibit 10(k) of our Form 10-K for the year ended December 31, 2004). |
|
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10(ee)**
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|
2004 Form of restricted stock award that vests on retirement, for grants to officers pursuant
to 2004
Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference as
Exhibit 10(l) of our Form 10-K for the year ended December 31, 2004). |
|
|
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10(ff)**
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|
2004 Form of restricted stock award that vests 20% per annum, for grants to directors pursuant
to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference
as Exhibit 10(m) of our Form 10-K for the year ended December 31, 2004). |
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10(gg)**
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|
2009 form of restricted stock award to certain officers that cliff vests on March 31, 2012 pursuant to 2004 Omnibus Stock and
Incentive Plan for Denbury Resources Inc. (incorporated by reference as Exhibit 10(b) of our Form 10-Q for the quarter ended March 31, 2009). |
|
10(hh)**
|
|
2009 form of restricted stock award without change of control vesting to certain officers that cliff vests on March 31, 2012
pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference as Exhibit 10(c) of our Form 10-Q for the quarter ended
March 31, 2009). |
|
10(ii)**
|
|
2009 form of performance share awards to certain officers pursuant to 2004 Omnibus Stock and
Incentive Plan for Denbury Resources Inc. (incorporated by reference as Exhibit 10(d) of our Form 10-Q for the quarter ended March 31, 2009). |
|
|
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10(jj)**
|
|
2009 form of performance share awards without change of control vesting to certain officers
pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference as Exhibit 10(e) of our Form 10-Q for the
quarter ended March 31, 2009). |
|
10(kk)**
|
|
2009 form stock appreciation rights
to certain officers that cliff vests on March 31, 2012 pursuant to
2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
(incorporated by reference as Exhibit 10(f) of our Form 10-Q for the
quarter ended March 31, 2009). |
|
10(ll)**
|
|
2009 form of stock appreciation
rights without change of control vesting pursuant to 2004 Omnibus
Stock and Incentive Plan for Denbury Resources Inc. (incorporated by
reference as Exhibit 10(g) of our Form 10-Q for the quarter ended
March 31, 2009). |
|
10(mm)**
|
|
Founders Retirement Agreement
by and between Denbury Resources Inc. and Gareth Roberts effective
June 30, 2009 (incorporated by reference as Exhibit 10.1 of our Form
8-K filed July 7, 2009). |
|
10(nn)**
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|
$6.350 million 9.75% Senior
Subordinated Note due 2016 issued on June 30, 2009 to Gareth Roberts
(incorporated by reference as Exhibit 10.2 of our Form 8-K filed July
7, 2009.) |
21*
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|
List of subsidiaries of Denbury Resources Inc. |
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23(a)*
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Consent of PricewaterhouseCoopers LLP. |
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23(b)*
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Consent of DeGolyer and MacNaughton. |
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31(a)*
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Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002. |
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31(b)*
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Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002. |
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32*
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Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. |
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99*
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|
The summary of DeGolyer and MacNaughtons Report as of December 31, 2009, on oil and gas
reserves (SEC Case) dated January 26, 2010. |
120
Denbury Resources Inc.
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Exhibit |
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No. |
|
Exhibit |
101*
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|
The following financial statements from the Companys Annual Report on Form 10-K for the year
ended December 31, 2009, formatted in XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated
Statements of Operations, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated
Statements of Changes in Stockholders Equity, (v) Consolidated Statements of Comprehensive
Operations. |
|
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|
* |
|
Filed herewith. |
|
** |
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Compensation arrangements. |
121
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, Denbury Resources Inc. has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
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DENBURY RESOURCES INC.
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February 26, 2010 |
/s/ Mark C. Allen
|
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Mark C. Allen |
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|
Sr. Vice President and Chief Financial Officer |
|
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February 26, 2010 |
/s/ Alan Rhoades
|
|
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Alan Rhoades |
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|
Vice President, Accounting |
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of Denbury Resources Inc. and in the capacities and
on the dates indicated.
|
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February 26, 2010 |
/s/ Phil Rykhoek
|
|
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Phil Rykhoek |
|
|
Chief Executive Officer
(Principal Executive Officer) |
|
|
|
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|
February 26, 2010 |
/s/ Mark C. Allen
|
|
|
Mark C. Allen |
|
|
Sr. Vice President and Chief
Financial Officer
(Principal Financial Officer) |
|
|
|
February 26, 2010 |
/s/ Alan Rhoades
|
|
|
Alan Rhoades
Vice President, Accounting
(Principal Accounting Officer) |
|
|
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February 26, 2010 |
/s/ Gareth Roberts
|
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Gareth Roberts |
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Director |
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February 26, 2010 |
|
|
|
Wieland Wettstein |
|
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Director |
|
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February 26, 2010 |
/s/ Michael Beatty
|
|
|
Michael Beatty |
|
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Director |
|
122
|
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|
|
|
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|
February 26, 2010 |
/s/ Michael Decker
|
|
|
Michael Decker |
|
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Director |
|
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February 26, 2010 |
/s/ Ron Greene
|
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Ron Greene |
|
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Director |
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February 26, 2010 |
/s/ David I. Heather
|
|
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David I. Heather |
|
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Director |
|
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February 26, 2010 |
/s/ Greg McMichael
|
|
|
Greg McMichael |
|
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Director |
|
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February 26, 2010 |
/s/ Randy Stein
|
|
|
Randy Stein |
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|
Director |
|
|
123