UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2009 FORM 10-K

     (Mark One)

þ

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

o

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.

Delaware		20-0467835
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)
5100 Tennyson Parkway,
Suite 1200, Plano, TX		75024
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:		(972) 673-2000

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class:		Name of Each Exchange on Which Registered:
Common Stock $.001 Par Value		New York Stock Exchange

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 registrant’s 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 registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter was $2,625,591,935.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2010, was 262,364,085.

DOCUMENTS INCORPORATED BY REFERENCE

Document:		Incorporated as to:
1.   Notice and Proxy Statement for the Annual Meeting of Shareholders to be held May 19, 2010.		1. Part III, Items 10, 11, 12, 13, 14

Denbury Resources Inc.
2009 Annual Report on Form 10-K
Table of Contents

		Page
Glossary and Selected Abbreviations			3
PART I
Item 1. Business			4
Item 1A. Risk Factors			25
Item 1B. Unresolved Staff Comments			33
Item 2. Properties			33
Item 3. Legal Proceedings			33
Item 4. Reserved			34
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			35
Item 6. Selected Financial Data			37
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			39
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			69
Item 8. Financial Statements and Supplementary Data			69
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			116
Item 9A. Controls and Procedures			116
Item 9B. Other Information			117
PART III
Item 10. Directors, Executive Officers and Corporate Governance			117
Item 11. Executive Compensation			117
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			117
Item 13. Certain Relationships and Related Transactions, and Director Independence			117
Item 14. Principal Accountant Fees and Services			117
PART IV
Item 15. Exhibits and Financial Statement Schedules			118
Signatures			122
EX-4.C
EX-4.F
EX-4.H
EX-10.G
EX-10.H
EX-21
EX-23.A
EX-23.B
EX-31.A
EX-31.B
EX-32
EX-99
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

Denbury Resources Inc.

Glossary and Selected Abbreviations

Bbl		One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bbls/d		Barrels of oil produced per day.
Bcf		One billion cubic feet of natural gas or CO2.
Bcfe		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.
BOE		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.
BOE/d		BOEs produced per day.
Btu		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.
CO2		Carbon dioxide.
Finding and Development Cost		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.
MBbls		One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE		One thousand BOEs.
Mbtu		One thousand Btus.
Mcf		One thousand cubic feet of natural gas or CO2.
Mcf/d		One thousand cubic feet of natural gas or CO2 produced per day.
Mcfe		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.
Mcfe/d		Mcfes produced per day.
MMBbls		One million barrels of crude oil or other liquid hydrocarbons.
MMBOE		One million BOEs.
MMBtu		One million Btus.
MMcf		One million cubic feet of natural gas or CO2.
MMcf/d		One million cubic feet of natural gas or CO2 per day.
MMcfe		One thousand Mcfe.
MMcfe/d		MMcfes produced per day.
PV-10 Value		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.
Proved Developed Reserves*		Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves*		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.
Proved Undeveloped Reserves*		Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
Tcf		One trillion cubic feet of natural gas or CO2.

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;

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 Denbury’s 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. Encore’s 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 Denbury’s 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 company’s 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 Denbury’s 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 Encore’s 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 Encore’s 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 Encore’s 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

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 Encore’s 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 Encore’s existing revolving credit facility which had $155 million outstanding as of February 15, 2010, pay Encore’s 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.

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 Encore’s 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

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. Mississippi’s first enhanced oil recovery project began in the mid 1980s in Little Creek Field following the installation of Shell Oil Company’s 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.

	•		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.
	•		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.
	•		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.
	•		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.
	•		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.
	•		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

Denbury Resources Inc.

			commence this project, the timing of which is uncertain at this time.
	•		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.
	•		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 Denbury’s 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 Denbury’s 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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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 Company’s growth for the foreseeable future. Although we believe that our plans and projections are reasonable and achievable,

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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 team’s 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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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, Denbury’s 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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     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), 15^o 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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Heidelberg’s 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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     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 Encore’s 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

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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 Encore’s 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.

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				(000’s)				(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	%

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 Denbury’s 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 Denbury’s 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

     Denbury’s 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

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

Production and Unit Prices

     Information regarding average production rates, unit sale prices and unit costs per BOE are set forth under “Management’s 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%).

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

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 FERC’s 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.

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 Company’s 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. Denbury’s 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 Company’s internal reserve engineering team consists of qualified petroleum engineers who both provide data to the

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 Company’s Board of Directors’ Reserves Committee, on behalf of the Board of Directors, oversees the qualifications, independence, performance and hiring of the Company’s independent petroleum engineering firm and reviews the final report and subsequent reporting of the Company’s 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 MacNaughton’s 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 31^st 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.

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

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;

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 Denbury’s 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 Denbury’s 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 company’s 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.

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

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 “Management’s Discussion and Analysis of

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

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.

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 31^st 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.

Denbury Resources Inc.

     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 President’s 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 Encore’s 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

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 “Management’s 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) Encore’s 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 Encore’s directors in breaching their fiduciary duties. The Teamsters complaint also alleges that Encore’s 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 Denbury’s 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 plaintiff’s 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 plaintiff’s 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.

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

Denbury Resources Inc.

PART II

Item 5. Market for Registrant’s 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 Denbury’s 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 Company’s transfer agent, American Stock Transfer and Trust Company, the number of holders of record of Denbury’s common stock was 1,341. On February 26, 2010, the last reported sale price of Denbury’s 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.

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

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

Denbury Resources Inc.

Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7. Management’s 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 Encore’s 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 company’s 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

Denbury Resources Inc.

Management’s 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 Founder’s 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 Denbury’s 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

Denbury Resources Inc.

Management’s 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 Encore’s 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 Encore’s existing revolving credit facility which had $155 million outstanding as of February 15, 2010, pay Encore’s 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 Encore’s 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 subsidiary’s 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 Denbury’s 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

Denbury Resources Inc.

Management’s 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 Codification^TM (“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 Denbury’s 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 Company’s 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 Company’s 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 Founder’s 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 Company’s 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

Denbury Resources Inc.

Management’s 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.

     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 Encore’s Rocky Mountain legacy oil fields; and (4) approximately $74 million on drilling and completion activities in Encore’s 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.

Denbury Resources Inc.

Management’s 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.

Denbury Resources Inc.

Management’s 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

Denbury Resources Inc.

Management’s 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 field’s 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.

Denbury Resources Inc.

Management’s 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