UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2007 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, 2007

o		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                      to                     

DENBURY RESOURCES INC.

Delaware		20-0467835
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer 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 N 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. o

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
		(Do not check if a smaller reporting company)

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 $3,233,003,475.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2008, was 245,193,057.

DOCUMENTS INCORPORATED BY REFERENCE

Document:					Incorporated as to:
1.		Notice and Proxy Statement for the Annual Meeting of Shareholders to be held May 15, 2008.			1.			Part III, Items 10, 11, 12, 13, 14

 

 

Denbury Resources Inc.
2007 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			21
Item 1B. Unresolved Staff Comments			26
Item 2. Properties			26
Item 3. Legal Proceedings			26
Item 4. Submission of Matters to a Vote of Security Holders			26
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			27
Item 6. Selected Financial Data			29
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			53
Item 8. Financial Statements and Supplementary Data			53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			93
Item 9A. Controls and Procedures			93
Item 9B. Other Information			93
PART III
Item 10. Directors, Executive Officers and Corporate Governance			94
Item 11. Executive Compensation			94
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			94
Item 13. Certain Relationships and Related Transactions, and Director Independence			94
Item 14. Principal Accountant Fees and Services			94
PART IV
Item 15. Exhibits and Financial Statement Schedules			94
Signatures			98
Certificate of Amendment of Restated Certificate of Incorporation
2007 Form of Restricted Stock Award
List of Subsidiaries
Consent of PricewaterhouseCoopers LLP
Consent of DeGolyer and MacNaughton
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906
The Summary of DeGolyer and MacNaughton's Report

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 production and future development costs and abandonment, using prices and costs in effect at the determination date, and before income taxes, discounted to a present value using an annual discount rate of 10%. PV-10 Value is a non-GAAP measure and its use is further discussed in footnote 3 to the table on page 20.
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, 2007, we had 686 employees, 420 of whom were employed in field operations or at the field offices. Our employee count does not include the approximately 660 employees of Genesis Energy, Inc. as of December 31, 2007, as its employees exclusively carry out the business activities of Genesis Energy, L.P., which we do not consolidate in our financial statements (see Note 1 to the Consolidated Financial Statements).

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. (new entity). Stockholders’ ownership interests in the business did not change as a result of the new structure and shares of the Company remain publicly traded 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;

	•		acquire properties where we believe additional value can be created through a combination of exploitation, development, exploration and marketing, including secondary and tertiary operations;
	•		acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it;
	•		maximize the value of our properties by increasing production and reserves while reducing cost; and
	•		maintain a highly competitive team of experienced and incentivized personnel.

Denbury Resources Inc.

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 Gas Operations

Our CO₂ Assets

     During 2007, we continued to focus on carbon dioxide (“CO₂”) enhanced oil recovery. We continued the expansion of our Phase I and Phase II tertiary floods and initiated tertiary projects at Lockhart Crossing, our first Louisiana field in Phase I (see description of the various phases below), Tinsley Field in Phase III, and Cranfield Field in Phase IV. We increased our potential tertiary flood candidates during 2007 with the acquisition of significant positions in Oyster Bayou, Fig Ridge and Gillock Fields, Phases VII and VIII, adding to our inventory of future tertiary floods. In addition to our development, expansion and acquisition of new floods, we also made the strategic decision to divest our natural gas assets in South Louisiana that did not contain future CO₂ potential in order to further narrow our focus on CO₂ enhanced oil recovery and our core assets. During the last eight years, we have learned a considerable amount about tertiary operations and working with CO₂, and our knowledge continues to grow. We like these tertiary operations because (i) CO₂ investments provide a reasonable rate of return, even at relatively low oil prices, (ii) tertiary flooding exhibits a lower risk profile, and (iii) to date, in our region of the United States, we have not encountered any industry competition. Generally, from the Texas Gulf Coast to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of CO₂ are the foundation for our entire tertiary program.

     CO₂ 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. Further, 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 3% 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 initially proved to be 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 (“EOR”) 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 in Mississippi, followed by our acquisition of Jackson Dome CO₂ reserves and 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 niche play.

Tertiary Recovery Phases

     We talk about our tertiary operations by labeling operating areas or groups of fields as phases. Phase I is in Southwest Mississippi and includes several fields along our 183-mile NEJD CO₂ Pipeline that we acquired in 2001. The most significant fields in this area are Little Creek, Mallalieu, McComb and Brookhaven. We further expanded our Phase I area by developing Lockhart Crossing Field in South Louisiana during 2007. Lockhart Crossing, although a relatively small field, is the first of three fields to be CO₂ flooded in Louisiana and our first flood outside the state of Mississippi. Phase II, which began with the early 2006 completion of the Free State CO₂ Pipeline to East Mississippi, includes Eucutta, Soso, Martinville and Heidelberg Fields. Tinsley Field, located northwest of

Denbury Resources Inc.

Jackson, Mississippi, acquired in January 2006, is our Phase III and is serviced by that portion of the Delta CO₂ Pipeline completed in January 2008. Phase IV includes Cranfield and Lake St. John Fields, two fields near the Mississippi/Louisiana border located west of the Phase I fields, and Phase V is Delhi Field, a Louisiana field we acquired in 2006, located southwest of Tinsley Field. Flooding in Phase V will begin in 2009 upon completion of the Delta CO₂ Pipeline from Tinsley to Delhi. Citronelle Field in Southwest Alabama, another field acquired in 2006, is our Phase VI which will require an extension to the Free State CO₂ Pipeline, the timing of which is uncertain at this time. Our last two currently existing phases will require completion of our proposed 300-mile Green Pipeline, which will run from Southern Louisiana to near Houston, Texas, and is scheduled for completion in late 2009 or 2010. Hastings Field, a field on which we acquired a purchase option in late 2006, is our Phase VII and the Seabreeze Complex, acquired in 2007, will be our Phase VIII.

     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 additional wells and drilled 15 additional CO₂ producing wells, significantly increasing our estimated proved CO₂ reserves to approximately 5.6 Tcf as of December 31, 2007, which is almost enough for our existing and currently planned phases of operations. The estimate of 5.6 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 4.5 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 for both of these uses. Today, we own every producing CO₂ well in the region. Although our current proven 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 needed. In order to obtain additional CO₂ deliverability, we plan to drill several additional CO₂ wells in the future, including four development wells and one exploratory well during 2008.

     During the fourth quarter of 2007, we produced an average of 533 MMcf/d of CO₂, a 35% increase over one year ago. We sold an average of 99 MMcf/d of CO₂ to commercial users, and we used an average of 434 MMcf/d for our tertiary activities. We estimate that our current daily CO₂ deliverability is around 700 MMcf/d. By year-end 2008, we estimate that our planned tertiary operations will require approximately 800 MMcf/d, which we believe we can attain with our planned 2008 Jackson Dome projects. Our geoscientists are using a 100-square-mile 3-D seismic survey to locate additional structures that are expected to contain CO₂. During 2007, we drilled our first previously undrilled structure based on our 100-square-mile seismic survey and re-entered a previously drilled well on another structure. The successful testing of this undrilled structure and our successful re-entry and testing of this previously drilled well, along with our development work at DRI Ice Field, increased our confidence that significant volumes of additional CO₂ can be developed in the Jackson Dome area beyond our proved reserve base. We plan to continue our CO₂ drilling activity in 2008 and beyond, with additional development of DRI Ice Field to increase our deliverability of CO₂ and additional testing of undrilled structures to potentially increase our proved reserves, as our CO₂ deliverability and reserves requirements will continue to grow as we expand our planned tertiary projects and acquire additional tertiary projects.

     Man-made CO₂ sources. We entered into two additional agreements and committed to purchase (if the plants are built) 100% of the man-made (anthropogenic) CO₂ production, from two proposed solid carbon gasification projects scheduled to be completed in 2011 and 2012. These projects are in addition to our 2006 agreement for the Faustina plant, proposed to be located near Donaldsonville, Louisiana, that will convert petroleum coke into ammonia. As a by-product of the gasification of solid carbon, large quantities of CO₂ are produced. Assuming these three projects are built, the total volume of CO₂ expected to be produced is estimated to be between 750 and 850 MMcf/d. We plan to use this CO₂ in our tertiary operations to recover oil that may otherwise not be produced. In addition, our use of this CO₂ will also eliminate the release of this greenhouse gas into the earth’s atmosphere. These agreements potentially allow us to add the equivalent volume of an additional three to four Tcf of CO₂ over the terms of our contracts. Construction of these plants has not yet begun, so we are not certain whether these plants will be built, although it appears likely that some gasification plants will be built in this area, if not these particular three. We are in discussions with several other entities that are considering other types of solid carbon gasification plants. These plants may convert petroleum coke, coal, biomass or combinations of all three into a variety of products including ammonia, methanol, synthetic diesel fuel or for electrical power generation. The cost

Denbury Resources Inc.

of man-made CO₂ will likely be higher than CO₂ from our natural source, but the location of these plants could mitigate some of the incremental cost of transportation, and we believe that there could potentially be a type of carbon credit in the United States that could significantly lower our cost for this CO₂. Further, we see these sources as a possible expansion of our natural Jackson Dome source, assuming they are economical, and we believe that our potential ability to tie these sources together with pipelines will give us a significant advantage over our competitors in our geographic area in acquiring additional oil fields and future potential man-made sources of CO_2.

     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 three existing Phase II tertiary fields in East Mississippi (Eucutta, Soso and Martinville) and will also be used for our proposed projects at Heidelberg, South Cypress Creek and other fields in Phase II. 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 2008, and the reconditioning and conversion of the natural gas pipeline we acquired from Southern Natural Gas Company in 2006 to CO₂ service which we will use to transport CO₂ to our Phase IV fields, Cranfield and Lake St. John Fields. Although neither of these pipeline projects were completed during 2007, during January 2008 we placed the Delta Pipeline in service between Jackson Dome and Tinsley Field and expect to make our first deliveries of CO₂ to Cranfield during the second quarter of 2008. During 2008, we plan to further extend our Delta Pipeline by building a 24” 68-mile extension from Tinsley Field to Delhi Field with completion of this segment anticipated around year-end 2008.

     In late 2006, we purchased an option to acquire Hastings Field, a potential tertiary flood located near Houston, Texas. We plan to build a 24” pipeline, named the Green Pipeline, to transport CO₂ to Hastings Field and our 2007 Southeast Texas acquisitions, Oyster Bayou, Fig Ridge and Gillock Fields. The Green Pipeline will go from the southern end of our existing NEJD CO₂ pipeline that terminates near Donaldsonville, Louisiana, to Hastings Field, near Houston, Texas, estimated to be between 300 and 320 miles. Based on our latest estimates, this pipeline is expected to cost between $700 million and $750 million. Our efforts in 2007 were focused on engineering design and right-of-way acquisitions. We acquired approximately 100-plus miles of the necessary 300-plus miles of right-of-way in 2007 and completed a substantial portion of our engineering design. In addition, we signed a letter of intent with a steel mill to manufacture the 24” pipe and thereby locked-in the pipe purchase price. Although our definitive schedules are still in flux, our goal is to begin construction of the Green Pipeline around year-end 2008 and hope to have it completed around year-end 2009. 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 economics. Initially, our tertiary operations were generally economic at oil prices below $20 per Bbl, although the economics have always varied by field. Our costs have escalated during the last few years due to general cost inflation in the industry, raising our current economic oil price to around $30 per Bbl, again dependent on the specific field. Our inception to date finding and development costs (including future development and abandonment costs but excluding expenditures on fields without proven reserves) for our tertiary oil fields through December 31, 2007, was approximately $9.75 per BOE. Currently, we forecast that these costs will range from $5 to $10 per BOE over the life of each field, depending on the state of a particular field at the time we begin operations, the amount of potential oil, the proximity to a pipeline or other facilities, etc. Our operating costs for tertiary operations are expected to range from $15.00 to $20.00 per BOE over the life of each field (at today’s prices), again depending on the field itself.

     While these economic factors have wide ranges, our rate of return from these operations has generally been better than the rate of return on our traditional oil and gas operations and entail less risk, 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 and reserve 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, 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 spend approximately $90 million in 2008 in the Jackson Dome area with the intent to add additional CO₂ reserves and deliverability for future operations. Approximately $27 million in capital

Denbury Resources Inc.

expenditures is budgeted in 2008 for our Phase II properties (East Mississippi) and approximately $27 million for Phase III properties (Tinsley), plus an additional $180 million for properties in other phases, plus an additional $235 million for our Delta and Green CO₂ Pipelines, making our combined CO₂ related expenditures just over 72% of our $900 million 2008 capital budget.

Our Tertiary Oil Fields With Proved Tertiary Reserves

     At December 31, 2007, we had total tertiary-related proved oil reserves of approximately 69.5 MMBbls, consisting of 2.7 MMBbls at Little Creek Field (and surrounding smaller fields), 11.5 MMBbls at Mallalieu Field, 15.3 MMBbls at McComb and Smithdale Fields, 18.7 MMBbls at Brookhaven Field, 10.2 MMBbls at Eucutta Field, 9.8 MMBbls at Soso Field, and 1.3 MMBbls at Martinville Field. 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 17,428 Bbls/d during the fourth quarter of 2007. We expect this production to continue to increase for several years as we expand our tertiary operations to additional fields.

     With regard to our proved tertiary reserves, we added 12.7 MMBbls of tertiary-related proved oil reserves during the year, primarily oil reserves at Soso, Martinville and minor incremental barrels at various fields in the Phase I area. Previously, we booked most proved tertiary oil reserves near the start of a project as almost all the oil fields in Phase I were analogous to Little Creek Field (our first flood) and thus it was not necessary to have an oil production response to the CO₂ injections before they were considered proved. Conversely, our new floods (after Phase I) are not analogous (for the most part), as the tertiary floods will be in different geological formations. Therefore, for these new phases, there must be an oil production response to the CO₂ injections before we can recognize proved oil reserves, even though we believe that these formations have a similar risk profile. We anticipate booking significant amounts of proven tertiary oil reserves during 2008 with initial response expected at Tinsley and Lockhart Crossing Fields and possibly at Cranfield Field.

     Mallalieu Field. The Mallalieu Field consists of two fields, West Mallalieu and the smaller East Mallalieu Fields. Combined they are our most prolific tertiary flood, producing 6,304 Bbls/d for the fourth quarter 2007. In contrast to many of our existing fields, Mallalieu Field was not waterflooded prior to CO₂ injection. Therefore, we believe that the tertiary recovery of oil from Mallalieu Field as a result of CO₂ injection could approach 25% of the original oil in place. During 2006, we increased our proved reserves in this area, raising our estimated recovery factor from 17% to 20% for these fields, based on production performance to date. A total of $16.6 million was invested in this field during 2007 to drill, re-enter or recomplete wells in efforts to improve production.

     From inception through December 31, 2007, we had net positive cash flow (revenue less operating expenses and capital expenditures) from Mallalieu Field of $253.2 million, plus the fields have a PV-10 Value of $719.8 million, using December 31, 2007, NYMEX pricing of $95.98 per barrel.

     McComb and Smithdale Fields. We commenced tertiary recovery operations in 2003 at McComb Field and started injecting CO₂ late that year. Significant development occurred during 2004 and 2005 as we expanded the nearby Olive Field CO₂ facility to handle the processing of McComb’s produced oil, water and CO₂, and developed an additional four injection patterns. The first production response occurred in the second quarter of 2004 and has increased since that time, averaging 1,388 Bbls/d in the fourth quarter of 2007. During 2007, we continued the expansion of our operations within McComb Field, expanding the production facilities, and completing our installation of the facilities necessary to raise the injection pressure throughout the field. Although we encountered injection issues, which initially limited our CO₂ injections at McComb, the increased injection pressure has resulted in significant increases in CO₂ injections at McComb Field. Since we increased the CO₂ injections, we have seen increased amounts of water production which is generally the precursor for increasing oil production. During 2007, nearby Smithdale Field saw significant production increases. Oil production increased from less than 100 Bbls/d in 2006 to an average of 708 Bbls/d in the fourth quarter of 2007. Smithdale development was slower than expected due to a larger percentage of re-entry failures than we have experienced in our other fields. The reservoir at Smithdale is very channelized and thus the drilling of replacement wells for the re-entry failures was postponed until we were able to complete our evaluation of a 2007 3-D seismic survey covering McComb and Smithdale Fields. By utilizing the 3-D seismic data, our geoscientists are able to locate wells in optimal positions within the channels at Smithdale to maximize the aerial coverage and sweep of the CO₂ project.

     From inception through December 31, 2007, 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

Denbury Resources Inc.

these fields of $113.3 million, although the fields have a PV-10 Value of $713.1 million, using December 31, 2007, NYMEX pricing.

     Brookhaven Field. Our first tertiary CO₂ production response at Brookhaven Field occurred during the fourth quarter of 2005, with oil production rates averaging 125 Bbls/d during the fourth quarter of 2005. Production rates continued to increase throughout 2006 and 2007 as additional patterns have been developed. Brookhaven Field has three discrete reservoirs that are being simultaneously CO₂ flooded. Significant incremental work on CO₂ injection wells is required to improve injection rates and to ensure the CO₂ is entering the proper intervals. Injection of CO₂ in certain wells has been less than originally anticipated and thus additional injection pumps were installed on certain wells to increase injection rates. Our oil production here during the fourth quarter of 2007 averaged 2,507 Bbls/d.

     From inception through December 31, 2007, 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 Brookhaven of $44.8 million, although the field has a PV-10 Value of $793.8 million attributed to the tertiary recovery reserves, using December 31, 2007, NYMEX pricing.

     Little Creek Area. During the fourth quarter of 2007, production averaged 1,957 Bbls/d from the Little Creek area, which includes Lazy Creek. Production at Little Creek Field began declining in 2006 and is expected to continue to decline over the next several years. 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. From inception through December 31, 2007, 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 $153.9 million, plus the fields have a PV-10 Value of $132.3 million, using December 31, 2007, NYMEX pricing.

     Eucutta Field. The oil response we have experienced in Eucutta has confirmed the results of the pilot project that was performed in the early 1980s. The Eutaw formation at Eucutta was unitized for water flooding in 1966 and has gone through several stages of development. 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, with the first minor tertiary oil production during the fourth quarter of 2006. Our plans for 2008 include the development of the remaining patterns and expansion of our CO₂ facilities. At December 31, 2007, we had 10.2 MMBbls of proved reserves in the Eucutta Field attributable to the CO₂ flood with a corresponding PV-10 Value of $456.0 million using year-end prices. The proved reserve estimate is based on a 13% recovery factor, which is lower than was achieved in the pilot program in the 1980s, and therefore we expect upward reserve revisions here in the future. Eucutta is analogous to Heidelberg Field in that the majority of its historical production was produced from the Eutaw formation.

     From inception through December 31, 2007, 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 Eucutta of $40.3 million, although the field has a PV-10 Value of $456.0 million attributed to the tertiary recovery reserves, using December 31, 2007, NYMEX pricing.

     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. The Bailey sand exhibits comparable reservoir characteristics to our West Mississippi floods, and we expect the Bailey tertiary flood to perform in a similar manner. We elected to co-develop the Bailey sand and Rodessa sand to accelerate the development of the potential tertiary oil reserves at Soso. Although we began initial development of the Bailey sand very late in 2005, the majority of our capital investment to date occurred in 2006, which involved the construction of CO₂ facilities and the establishment of the two tertiary injection projects. 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, although injections in the Bailey formation were initially limited because of delays in getting the well work done and limited CO₂ supplies. As expected, we saw our first tertiary production in Soso Field during early 2007 from the Bailey.

Denbury Resources Inc.

     In 2007 we continued the development of additional patterns in both the Rodessa and Bailey intervals, and by the fourth quarter of 2007 response in the Bailey continued to increase, and initial response from the Rodessa was also achieved. During the fourth quarter of 2007, production at Soso had increased to 1,109 Bbls/d. From inception through December 31, 2007, 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 $93.2 million, although the field has a PV-10 Value of $363.5 million attributed to the tertiary recovery reserves, using December 31, 2007, NYMEX pricing.

     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 essentially completed the development of the Mooringsport sand during 2006. During the fourth quarter of 2006, the first Mooringsport well responded, although the average rate for the quarter was only 24 Bbls/d. The tertiary oil rate has increased to approximately 883 Bbls/d during the fourth quarter of 2007 including initial response in the Rodessa. Although we booked minimal proved reserves in 2006 from the one responding well in the Mooringsport, we booked additional reserves, approximately 1.5 MMBbls at December 31, 2007, in the Mooringsport and the Rodessa IX reservoir. 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, 2007, 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 $10.8 million, although the field has a PV-10 Value of $65.8 million attributed to the tertiary recovery reserves, using December 31, 2007, NYMEX pricing.

     The Wash Fred 8500’ reservoir in the Martinville Field 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 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 initiated CO₂ injection during the first quarter of 2006 at the crest of the structure. Although we will not achieve miscibility, the injection of CO₂ is expected to swell the oil, decrease the oil viscosity, and displace the water and oil downward in the reservoir to the adjacent producing wells and result in incremental oil production. Well bore issues delayed the implementation of this flood during 2006, and fluid handling and processing of the CO₂ and this heavy crude have continued to hamper the development of this flood. Although we have seen indications of CO₂ response, the ability to produce and process this heavy crude with the associated CO₂ production is proving very difficult. We are evaluating various ideas and scenarios to address the processing issues we are experiencing. If we can resolve these issues, this field could provide the impetus to look at a whole new array of fields that have historically not been considered for CO₂ injection, although there can be no assurance that this technique will be successful or economic.

Our Tertiary Oil Fields Without Proved Tertiary Reserves

     During 2007, we commenced tertiary operations at a small field, Lockhart Crossing (Phase I), our first Louisiana flood, reconditioned the pipeline necessary to transport CO₂ to Cranfield Field in West Mississippi (Phase IV), and initiated CO₂ injections at Tinsley Field (Phase III).

     Tinsley Field. Tinsley Field was acquired in January 2006 and is one of the largest oil fields in the state of Mississippi. As is the case with the majority of fields in Mississippi, Tinsley produces from multiple reservoirs. While we are working the other reservoirs in an attempt to increase current conventional production and reserves, our primary target in Tinsley for CO₂ enhanced oil recovery operations is the Woodruff formation. One of the prior operators performed a pilot CO₂ project at Tinsley in the Perry sandstone. The CO₂ was successful at mobilizing oil but the operator decided not to expand the flood due to low oil prices. The acquisition of the field included an 8” pipeline that was installed to deliver CO₂ to the pilot project but was converted to natural gas service some time ago. We have reconditioned the pipeline for CO₂ service and initiated limited CO₂ injection in Tinsley Field in January 2007. Although injections were limited throughout 2007, we completed unitization of the entire field, constructed a substantial portion of our CO₂ recycling facilities, and expanded the CO₂ flood throughout the west fault block of the field. Construction of the first segment of our larger Delta Pipeline was completed in January 2008 with a resultant increase in injection rates thereafter. Although we only had limited injections during 2007, we did observe increasing reservoir pressures, and we plan to continue that re-pressuring process during 2008 with the higher

Denbury Resources Inc.

injection rates. Once the reservoir pressure increases to our target amount, we expect to see our initial tertiary oil production, most likely in the third or fourth quarter of 2008. If the production response is significant and occurs before year-end, we anticipate booking a portion of the forecasted proved reserves at Tinsley in 2008.

     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 revenue, as defined. Delhi is also a planned future CO₂ tertiary oil flood that will require construction of a CO₂ pipeline before flooding can commence, an extension of the larger, Delta Pipeline constructed from Jackson Dome to Tinsley Field. Our goal is to have this segment of the Delta Pipeline installed by around year-end 2008, with initial oil production from tertiary operations currently anticipated during 2009. As of December 31, 2007, there was no significant oil production nor proved oil reserves at Delhi Field.

     Hastings Field. During November 2006, we entered into an agreement with a subsidiary of Venoco, Inc. that gives us an option on September 1, 2008, or September 1, 2009, with an effective date of January 1 of the following year, to purchase their interest in Hastings Field, a strategically significant potential tertiary flood candidate located near Houston, Texas. The agreement provides for the parties to agree upon a purchase price for the conventional proved reserves at the time of the exercise of the option, which may be paid in cash or through a volumetric production payment; failing agreement as to price, the price will be determined by a pre-designated independent petroleum engineering firm using specified criteria for calculation of the discounted present value of proved reserves at that time. As consideration for the option agreement, we made an upfront payment of $37.5 million upon execution of the agreement and made an additional $7.5 million payment in 2007, and are required to make an additional payment of $5 million by November 2008. We can extend the option period beyond November 2009 for up to seven additional years at an incremental cost of $30 million per year. None of the option payment amounts will be credited against the purchase price if we exercise the option. If we exercise the option, we will be committed to make aggregate net capital expenditures in the field of approximately $175 million over the subsequent five years to develop the field for tertiary operations, with an obligation to commence CO₂ injections in the field within three years following the option exercise. Hastings Field is currently producing approximately 2,800 Bbls/d gross, although we currently have no economic interest in this production.

     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, more reserve potential than any other single field in our inventory. We plan to build the Green Pipeline 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 additional 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 very close to the planned route of the Green Pipeline. We acquired the majority interest in Oyster Bayou Field and a significant interest in Fig Ridge Field. We plan to start the unitization hearings required at Oyster Bayou Field during 2008. 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, and we have initiated those discussions. Our acquisitions in Gillock Field include an acquisition of 99+% (subject to a 20% preferential right election) of the South Gillock Unit, 99+% of 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 other potential acquisition candidates in Southeast Texas and in Louisiana in proximity to our proposed Green Pipeline.

     Overall Tertiary Economics to Date. Through December 31, 2007, we have invested a total of $1.0 billion on tertiary oil fields (including the allocated acquisition costs), and received $758.9 million in net operating income (revenue less operating expenses), or net unrecovered cash flow of $250.8 million, the deficit primarily due to the significant funds expended on acquisitions during 2006. Of our total spending, approximately $351.3 million was spent to date on fields that had little or no proved reserves at December 31, 2007 (i.e., significant incremental proved reserves are anticipated during 2008 and beyond). 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 $371.0 million as of December 31, 2007, including $180.3 million associated with CO₂ pipelines. At year-end 2007, the proved oil reserves in our tertiary recovery oil fields had a PV-10 Value of $3.2 billion, using December 31, 2007, NYMEX pricing of $95.98 per barrel. In addition, there are significant probable and potential reserves at several other fields for which tertiary operations are under way or planned.

Denbury Resources Inc.

Texas Barnett Shale

     We currently own approximately 55,649 gross acres and 40,240 net acres of leases in the Barnett Shale area in North Central Texas, of which approximately 19,984 gross acres and 19,398 net acres are in the more tested northern areas of Parker and Wise counties, with the remainder in Erath County and adjoining more southern and untested counties. We acquired our initial acreage in this area in 2001 and did only limited development until 2005. Through December 31, 2007, we have invested a total of $423.9 million on the Barnett Shale area (including acquisition costs) and have received $204.8 million in net operating income (revenue less operating expenses), or net negative cash flow of $219.1 million. At December 31, 2007, we had approximately 368.5 Bcfe of proved reserves in the Barnett Shale area with a PV-10 Value of approximately $717.2 million, using December 31, 2007, Henry Hub indicative cash pricing of $6.80 per MMBtu.

     We continue to refine our completion and fracturing techniques, including an analysis of the best number of fracture treatments to adequately stimulate the entire length of the lateral sections of our horizontal wells, which can exceed 4,000’. During 2007, we drilled and completed 45 horizontal wells, increasing our net Barnett Shale production from approximately 35.4 MMcfe/d in the fourth quarter of 2006 to approximately 76.4 MMcfe/d during the fourth quarter of 2007. Horizontal wells in the Barnett Shale were initially drilled by spacing horizontal wells approximately 1,500’ apart and drilling 3,000’ to 4,500’ laterals. As our development progressed we began testing wells at various spacings of 750’ and subsequently 500’ along with other operators in the Barnett. Initial production rates and early production data indicated that we are not efficiently draining the reservoir on the larger initial well spacing, and thus we began developing our acreage position on 500’ well spacing which significantly increased the number of future well locations that we can drill. Our year-end reserves included 85 proved undeveloped locations and an additional 88 probable undeveloped locations based on 500’ well spacing. We have recently begun testing well spacings less than 500’ but the results of this additional downspacing is inconclusive at this time. If our testing of the Barnett Shale on tighter well spacing is successful, it would significantly increase our number of future locations. We expect production in this area to grow modestly during 2008 as we plan to drill approximately 45 to 50 horizontal wells, all of which are scheduled for Parker and Wise Counties. Including seismic costs and pipeline infrastructure costs, our planned 2008 capital expenditures in the Barnett Shale area are estimated to make up $157 million of our current $900 million capital budget for 2008.

     We have completed a review of our 2006 drilling and completion work in our southern acreage, primarily Erath County. As a result of this review, we have determined to no longer pursue the development of this southern acreage position and will seek to divest these 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. Historically, this was our area with the highest production and most proved reserves, and while still significant, it is no longer our largest. Production during the fourth quarter of 2007 averaged approximately 12,530 BOE/d from this area (25% of our Company total), and we had proved reserves of 50.6 MMBOE as of December 31, 2007 (26% 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 three currently have tertiary operations (Soso, Martinville and Eucutta Fields). Production from our East Mississippi fields has been relatively consistent over the last three years, averaging 12,072 BOE/d in 2005, 12,743 BOE/d in 2006 and 12,479 BOE/d during 2007. For 2008, we expect our budget in this region for conventional operations to be around $60 million, about the same as in 2007, representing approximately 7% of our current 2008 exploration and development budget of $900 million.

     Heidelberg Field. The largest field in the region and one of our largest fields corporately is Heidelberg Field, which for the fourth quarter of 2007 produced an average of 7,770 BOE/d, 4% more than the 2006 fourth quarter average of 7,444 BOE/d. 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, and most of the past and current production comes from the Eutaw, Selma Chalk and Christmas sands at depths of 3,500’ to 5,000’.

     The majority of the oil production at Heidelberg is from six waterflood units that produce from the Eutaw formation (at approximately 4,400’). Most of our recent development at Heidelberg has been in the Selma Chalk, a natural gas reservoir at around 3,700’, making Heidelberg our second largest gas field. We have steadily developed the Selma Chalk since 2001, drilling from 13 to 20 wells per year, increasing the natural gas production at

Denbury Resources Inc.

Heidelberg to a peak quarterly average of 17.3 MMcf/d in the fourth quarter of 2007, averaging 16.3 MMcf/d during 2007. 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 very well and thus we expect to be able to expand our Selma Chalk development throughout West Heidelberg Field. During 2007, we drilled 13 horizontal Selma Chalk wells, two of which were located in West Heidelberg, and we plan to drill 12 horizontal wells during 2008.

     Our capital program for 2008 includes $39 million for construction of the pipeline necessary to transport CO₂ from the Free State Pipeline to Heidelberg Field, construction of the initial phase of the CO₂ recycle facilities and initial development of a CO₂ flood in West Heidelberg Field. The initial phase of our CO₂ project in Heidelberg will be conducted in the WHEOUP Unit in West Heidelberg. The reservoir associated with the WHEOUP unit is the Eutaw formation, the same formation we are CO₂ flooding at Eucutta Field. Thus we expect the results at Heidelberg to be very similar to the results 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 at Eucutta. Our forecasts do not include any production response from the CO₂ project at Heidelberg in 2008, but we do expect to see a production response in 2009.

Sale of Louisiana Natural Gas Assets

     In October 2007 we entered into an agreement to sell our Louisiana natural gas assets to a privately held company for approximately $180 million (before closing adjustments) plus any amounts received in the future from a net profits interest. In late December 2007, we closed on approximately 70% of that sale with net proceeds of approximately $108.6 million (including estimated final purchase price adjustments), and closed on the remaining 30% on February 20, 2008, with net proceeds at the second closing of approximately $48.9 million. The operating net revenue, net of capital expenditures, between the August 1, 2007, effective date and the respective closing dates were adjustments to the purchase price, along with other minor closing adjustments. The potential net profits interest relates to a well in the South Chauvin Field and is only earned if operating income from that well exceeds certain levels, which we believe could potentially increase the ultimate sales price by up to 10%.

     Production attributable to the sold properties averaged approximately 30.6 MMcfe/d (82% natural gas) during the fourth quarter of 2007, representing approximately 10% of our total fourth quarter production and approximately 4% of our total proved reserve quantities as of December 31, 2006.

Denbury Resources Inc.

Field Summaries

     Denbury operates in five primary areas: Eastern Mississippi, Western Mississippi, Texas, Alabama and Louisiana. Our 14 largest fields (listed below) constitute approximately 94% of our total proved reserves on a BOE basis and on a PV-10 Value basis. Within these 14 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; McComb, Mississippi; Brandon, Mississippi; and Cleburne, Texas.

		Proved Reserves as of December 31, 2007 (1)																			2007 Avg. Daily Production
																										Natural				Average Net
		Oil				Natural Gas								BOE			PV-10 Value(2)					Oil				Gas				Revenue
		(MBbls)				(MMcf)				MBOEs				% of total				(000’s)				(Bbls/d)				(Mcf/d)				Interest
Mississippi — CO2 Floods
Brookhaven			18,700				—				18,700				9.6	%		$	793,813				2,048				—				81.2	%
McComb Area			15,275				—				15,275				7.9	%			713,080				1,912				—				78.8	%
Mallalieu Area			11,547				—				11,547				5.9	%			719,778				5,852				—				76.7	%
Eucutta			10,172				—				10,172				5.2	%			456,003				1,646				—				83.5	%
Soso			9,798				—				9,798				5.0	%			363,542				586				—				77.2	%
Little Creek Area			2,749				—				2,749				1.4	%			132,311				2,014				—				83.2	%
Martinville			1,282				—				1,282				0.7	%			65,827				709				—				78.1	%
Total Mississippi — CO2 Floods			69,523				—				69,523				35.7	%			3,244,354				14,767				—				79.6	%
Other Mississippi
Heidelberg (East & West)			24,666				59,087				34,514				17.7	%			728,126				4,942				16,286				80.6	%
Tinsley			2,632				—				2,632				1.4	%			81,029				1,042				15				67.6	%
Sharon			—				11,842				1,974				1.0	%			32,057				4				4,491				94.3	%
S. Cypress Creek			1,850				654				1,959				1.0	%			45,050				247				39				86.6	%
Eucutta			1,854				—				1,854				1.0	%			47,367				444				22				64.4	%
Other Mississippi			7,047				3,641				7,654				3.9	%			199,488				2,117				1,246				37.4	%
Total Other Mississippi			38,049				75,224				50,587				26.0	%			1,133,117				8,796				22,099				63.7	%
Texas
Newark (Barnett Shale)			17,160				265,575				61,423				31.5	%			717,213				1,758				46,751				80.5	%
Other Texas			340				1,407				574				0.3	%			23,943				270				1,527				72.9	%
Total Texas			17,500				266,982				61,997				31.8	%			741,156				2,028				48,278				80.4	%
Louisiana
Louisiana			634				2,238				1,007				0.5	%			42,378				380				1,303				70.8	%
Louisiana sold (3)			422				12,434				2,494				1.3	%			59,556				801				24,861				45.6	%
Total Louisiana			1,056				14,672				3,501				1.8	%			101,934				1,181				26,164				48.6	%
Alabama & Other
Citronelle			8,784				—				8,784				4.5	%			159,796				1,150				—				62.7	%
Other Alabama			66				1,730				354				0.2	%			4,766				3				600				2.5	%
Total Alabama and other			8,850				1,730				9,138				4.7	%			164,562				1,153				600				11.2	%
Company Total			134,978				358,608				194,746				100.0	%		$	5,385,123				27,925				97,141				67.1	%

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, 2007:

		Developed								Undeveloped								Total
		Gross				Net				Gross				Net				Gross				Net
Mississippi			109,630				88,911				266,204				46,046				375,834				134,957
Louisiana			36,805				35,212				4,560				3,881				41,365				39,093
Texas			39,190				34,186				41,200				24,790				80,390				58,976
Alabama			35,209				21,860				72,113				14,638				107,322				36,498
Other			2,680				816				38,710				9,687				41,390				10,503
Total			223,514				180,985				422,787				99,042				646,301				280,027

     Denbury’s net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 22% in 2008, 26% in 2009 and 14% in 2010.

Productive Wells

     The following table sets forth our gross and net productive oil and natural gas wells at December 31, 2007:

										Producing Natural
		Producing Oil Wells								Gas Wells								Total
		Gross				Net				Gross				Net				Gross				Net
Operated Wells:
Mississippi			553				530.6				187				171.0				740				701.6
Louisiana			19				15.1				7				6.0				26				21.1
Texas			14				12.3				159				152.1				173				164.4
Alabama			155				122.0				32				19.2				187				141.2
Total			741				680.0				385				348.3				1,126				1,028.3
Non-Operated Wells:
Mississippi			37				3.4				18				4.2				55				7.6
Louisiana			—				—				—				—				—				—
Texas			—				—				4				0.3				4				0.3
Alabama			—				—				11				1.7				11				1.7
Other			3				—				—				—				3				—
Total			40				3.4				33				6.2				73				9.6
Total Wells:
Mississippi			590				534.0				205				175.2				795				709.2
Louisiana			19				15.1				7				6.0				26				21.1
Texas			14				12.3				163				152.4				177				164.7
Alabama			155				122.0				43				20.9				198				142.9
Other			3				—				—				—				3				—
Total			781				683.4				418				354.5				1,199				1,037.9

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,
		2007								2006								2005
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells:(1)
Productive(2)			9				6.2				10				8.5				12				7.1
Non-productive(3)			4				3.4				8				6.8				1				0.6
Development Wells:(1)
Productive(2)			101				96.8				90				82.7				81				74.3
Non-productive(3)(4)			—				—				—				—				—				—
Total			114				106.4				108				98.0				94				82.0

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 Income” included herein.

Title to Properties

     Customarily in the oil and 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, 2007, we had three purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon Ashland Petroleum LLC (43%), Hunt Crude Oil Supply Co. (19%) and Crosstex Energy Field Services Inc. (16%). For the

Denbury Resources Inc.

year ended December 31, 2006, we had two purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon Ashland Petroleum LLC (28%) and Hunt Crude Oil Supply Co. (18%). For the year ended December 31, 2005, three purchasers each accounted for more than 10% of our total oil and natural gas revenues: Marathon Ashland Petroleum LLC (28%), Hunt Crude Oil Supply Co. (20%) and Sunoco, Inc. (13%).

     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. In Heidelberg Field, one of our larger fields, and our other Eastern Mississippi 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 I CO₂ 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, 2007, the discount for our oil production from Heidelberg Field averaged $11.10 per Bbl and for our Eastern Mississippi properties as a whole the discount averaged $9.46 per Bbl relative to NYMEX oil prices. For our Phase I fields in Southwest Mississippi, we averaged a premium of $4.36 per Bbl over NYMEX oil prices during 2007. Our Texas Barnett Shale properties averaged $20.79 per Bbl below NYMEX prices during 2007, largely because the reported oil sales include a significant amount of natural gas liquids, which typically sell at a lower price than crude oil.

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 due to our proximity to Henry Hub and the high Btu content of our natural gas. For the year ended December 31, 2007, we averaged $0.36 above NYMEX prices for our Louisiana natural gas production. However, in the Barnett Shale area in Texas, due primarily to its location, the price we received averaged $0.78 below NYMEX prices. We expect our overall differential to NYMEX prices to gradually increase in the future due to our increasing emphasis in the Barnett Shale area.

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 funds, 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

Denbury Resources Inc.

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 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 costs 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 Legislation

     The Energy Independence and Security Act of 2007 (Public Law No. 110-140) became law on December 19, 2007. Among other provisions, the Act supports research and development in alternative and renewable fuels sources, energy storage for transportation and electric power, and carbon capture and sequestration. The Act does not repeal certain tax incentives for expenditures by companies engaged in the exploration and production of oil, gas and other

Denbury Resources Inc.

minerals, nor does it impose new excise taxes specifically on certain companies engaged in the exploration and production of oil, gas and other minerals, both of which had been proposed in earlier versions of the legislation. As a result of this new legislation, in 2008 Congress may decide to revisit legislation 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 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.

Natural Gas Gathering Regulations

     State regulation of natural gas gathering facilities generally include 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; (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. To date, we have not expended any material amounts to comply with such regulations, and 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 Gas Reserves and Present Value of Estimated Future Net Revenues

     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, 2007, 2006 and 2005. The reserve estimates were prepared using constant prices and costs in accordance with the guidelines of the Securities and Exchange Commission (“SEC”). The prices used in preparation of the reserve estimates were based on the market prices in

Denbury Resources Inc.

effect as of December 31 of each year, with the appropriate adjustments (transportation, gravity, basic sediment and water (“BS&W”), purchasers’ bonuses, Btu, etc.) applied to each field. The 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 interests in our properties. During 2007, we provided oil and gas reserve estimates for 2006 to the United States Energy Information Agency. The information provided was substantially the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2006.

     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 in East Mississippi account for approximately 78% 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. Our proved undeveloped natural gas reserves associated with our Selma Chalk play at Heidelberg and the Barnett Shale play account for approximately 97% of our proved undeveloped natural gas reserves. Our current plans for 2008 include drilling 55 to 65 new wells in these two primary natural gas plays.

		December 31,
		2007				2006				2005
ESTIMATED PROVED RESERVES:
Oil (MBbls)			134,978				126,185				106,173
Natural gas (MMcf)			358,608				288,826				278,367
Oil equivalent (MBOE)			194,746				174,322				152,568
PERCENTAGE OF TOTAL MBOE:
Proved producing			56	%			48	%			40	%
Proved non-producing			13	%			17	%			16	%
Proved undeveloped			31	%			35	%			44	%
REPRESENTATIVE OIL AND GAS PRICES:(1)
Oil — NYMEX		$	95.98			$	61.05			$	61.04
Natural gas — Henry Hub			6.80				5.63				10.08
PRESENT VALUES: (thousands)(2)
Discounted estimated future net cash flow before income taxes (“PV-10 Value”)(3)		$	5,385,123			$	2,695,199			$	3,215,478
Standardized measure of discounted estimated future net cash flow after income taxes			3,539,617				1,837,341				2,084,449

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 “Risk Factors — Estimating our reserves, production and future net cash flow is difficult to do with any certainty.” See also Note 15, “Supplemental Oil and Natural Gas Disclosures,” to the Consolidated Financial Statements.

Item 1A. Risk Factors

Risks Related To Our Business

Our production will decline if our access to sufficient amounts of carbon dioxide is limited.

     Our current long-term growth strategy is focused on our CO₂ tertiary recovery operations, and we expect approximately 72% of our 2008 capital expenditures to be in this area. 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.

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 and likely will continue to be volatile in the future, especially given current world geopolitical conditions. 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 69% of our December 31, 2007 proved reserves are oil, with oil being an even larger percentage of our future potential reserves and projects due to our focus on tertiary operations. 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 with any certainty. 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

Denbury Resources Inc.

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 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 2007, NYMEX oil prices were high throughout the year, averaging approximately $72.45 per Bbl. During 2004, 2005 and 2006, the price we received for our heavier, sour crude oil did not correlate as well with NYMEX prices as it had historically. During 2002 and 2003, our average discount to NYMEX was $3.73 per Bbl and $3.60 per Bbl, respectively. During 2004, this differential increased to $4.91 per Bbl for the year as a result of the price deterioration for heavier, sour crudes, and was even higher during 2005 and 2006, averaging $6.33 per Bbl and $6.41 per Bbl, respectively. In 2007, our differential improved to $2.65 per Bbl, as a large portion of our oil production was sold at markets that were priced favorably to the West Texas Intermediate NYMEX price, due to lack of available storage capacity in the mid-continent area, an oversupply of crude from Canada, capacity/transportation issues moving the crude out of the Cushing, Oklahoma area and unanticipated refinery outages. This positive trend in 2007 began to reverse in the fourth quarter of 2007, when our NYMEX differential averaged $7.27 per Bbl due to the significant increase in liquids extracted from our Barnett Shale production, which is recorded as oil production but is sold at a significant discount to the NYMEX oil price. While we attempt to obtain the best price for our crude in our marketing efforts, we cannot control these market price swings and are subject to the market volatility for this type of oil. These price differentials relative to NYMEX prices can significantly impact our profitability.

     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, have generally trended upward since that time, although with significant fluctuations along the way. NYMEX natural gas prices averaged $8.97 per MMBtu during 2005, $6.97 per MMBtu during 2006, and $7.09 per MMBtu during 2007.

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 Financial Condition and Results of Operations — Market Risk Management,” and in Note 10, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements.

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. Due to the recent record 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.

Denbury Resources Inc.

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 drilling and acquisitions. 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, often one to two 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 drilling activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves will be encountered. Exploratory drilling involves more risk than development drilling because exploratory drilling is designed to test formations for which proved reserves have not been discovered.

     In January 2006, we purchased three oil fields for $250 million that we believe have significant potential oil reserves that can be recovered through the use of tertiary flooding: Tinsley Field approximately 40 miles northwest of Jackson, Mississippi; Citronelle Field in Southwest Alabama, and the smaller South Cypress Creek Field near our Eucutta Field in Eastern Mississippi. These three fields produced approximately 2,392 BOE/d net to the acquired interests during the fourth quarter of 2007, and have proved reserves of approximately 13.4 MMBOEs. We purchased these fields 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 to this specific acquisition, we have, and 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;

Denbury Resources Inc.

	•		compliance with environmental and other governmental requirements; and
	•		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.

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, 2007, three purchasers each accounted for more than 10% of our oil and natural gas revenues and in the aggregate, for 78% 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.

Estimating our reserves, production and future net cash flow 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 therefrom 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. In accordance with requirements of the SEC, the estimates of present values are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and cost as of the date of the estimate.

Denbury Resources Inc.

     As of December 31, 2007, approximately 31% 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.

Our level of indebtedness may adversely affect operations and limit our growth.

     As of February 28, 2008, we had outstanding $525 million (principal amount) of 7.5% subordinated notes and $111 million of bank debt. Our bank credit line has approximately $379 million available on our borrowing base. The next semi-annual redetermination of the borrowing base for our bank credit facility will be on April 1, 2008. 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 in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties. 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 were to decline significantly, particularly 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;
	•		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;
	•		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 increase, potentially restricting us from making acquisitions, introducing new technologies or exploiting business opportunities;

Denbury Resources Inc.

	•		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.

     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 bank credit facility, we would be in default. This default would permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause defaults under other indebtedness, including the subordinated notes, 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 and to financial, business and other factors, including factors beyond our control.

Item 1B. Unresolved Staff Comments

     None.

Item 2. Properties

     See Item 1. Business — Oil and 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 11, “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

     We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position or overall trends in results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a 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. Submission of Matters to a Vote of Security Holders

     A special meeting of the stockholders was held on November 19, 2007, for the purposes of: (i) approving an amendment to our Restated Certificate of Incorporation to increase the number of shares of our authorized common stock from 250,000,000 shares to 600,000,000 shares; (ii) approving an amendment to our Restated Certificate of Incorporation to split our common shares 2-for-1; and (iii) granting authority to the Company to extend the solicitation period in the event that the special meeting is postponed or adjourned for any reason. At the record date, October 8, 2007, 122,094,117 shares of common stock were outstanding and entitled to one vote per share upon all matters submitted at the meeting. Holders of 111,215,370 shares of common stock, representing approximately 91% of the total issued and outstanding shares of common stock, were present in person or by proxy at the meeting to cast their vote. All matters were approved as listed below.

     With respect to the amendment to our Restated Certificate of Incorporation to increase the number of shares of our authorized common stock from 250,000,000 shares to 600,000,000 shares, the votes were cast as follows:

For		Against				Abstentions
81,736,700			29,443,451				35,219

Denbury Resources Inc.

     With respect to approving an amendment to our Restated Certificate of Incorporation to split our common shares 2-for-1, the votes were cast as follows:

For		Against				Abstentions
111,049,257			138,146				27,967

     With respect to approving an amendment to grant authority to extend the solicitation period in the event that the special meeting is postponed or adjourned for any reason, the votes were cast as follows:

For		Against				Abstentions
61,637,858			48,565,777				1,011,735

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. The sale prices are adjusted to reflect the 2-for-1 stock split on December 5, 2007. On April 25, 2006, we closed the $125 million sale (net to Denbury) of 6,985,190 shares (3,492,595 pre-split basis) of common stock in a public offering. As of January 31, 2008, the number of record holders of Denbury’s common stock was 943. Management believes, after inquiry, that the number of beneficial owners of Denbury’s common stock is in excess of 10,500. On January 31, 2008, the last reported sale price of Denbury’s common stock, as reported on the NYSE, was $25.30 per share.

		2007								2006
		High				Low				High				Low
First Quarter		$	15.310			$	12.980			$	16.325			$	11.785
Second Quarter			19.380				14.835				18.300				12.955
Third Quarter			23.380				18.275				17.900				13.265
Fourth Quarter			30.560				22.405				15.465				12.975

     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. No unregistered securities were sold by the Company during 2007.

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, 2007, 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, 2002, and that dividends were reinvested.

Cumulative Total Return on $100 Investment
(December 31, 2002 — December 31, 2007)

Denbury Resources Inc.

Item 6. Selected Financial Data

		Year Ended December 31,
(In thousands, unless otherwise noted)		2007				2006				2005				2004(1)				2003
Consolidated Statements of Operations Data:
Revenues		$	971,950			$	732,312			$	560,706			$	382,836			$	333,270
Net income			253,147				202,457	(2)			166,471				82,448				56,553	(3)
Net income per common share (4):
Basic			1.05				0.87	(2)			0.74				0.38				0.26	(3)
Diluted			1.00				0.82	(2)			0.70				0.36				0.25	(3)
Weighted average number of common shares outstanding (4):
Basic			240,065				233,101				223,485				219,482				215,525
Diluted			252,101				247,547				239,267				229,206				221,856
Consolidated Statements of Cash Flow Data:
Cash provided by (used by):
Operating activities		$	570,214			$	461,810			$	360,960			$	168,652			$	197,615
Investing activities			(762,513	)			(856,627	)			(383,687	)			(93,550	)			(135,878	)
Financing activities			198,533				283,601				154,777				(66,251	)			(61,489	)
Production (Daily):
Oil (Bbls)			27,925				22,936				20,013				19,247				18,894
Natural gas (Mcf)			97,141				83,075				58,696				82,224				94,858
BOE (6:1)			44,115				36,782				29,795				32,951				34,704
Unit Sales Price (excluding impact of derivative settlements):
Oil (per Bbl)		$	69.80			$	59.87			$	50.30			$	36.46			$	27.47
Natural gas (per Mcf)			6.81				7.10				8.48				6.24				5.66
Unit Sales Price (including impact of derivative settlements):
Oil (per Bbl)		$	68.84			$	59.23			$	50.30			$	27.36			$	24.52
Natural gas (per Mcf)			7.66				7.10				7.70				5.57				4.45
Costs per BOE:
Lease operating expenses		$	14.34			$	12.46			$	9.98			$	7.22			$	7.06
Production taxes and marketing expenses			3.05				2.71				2.54				1.55				1.17
General and administrative			3.04				3.20				2.62				1.78				1.20
Depletion, depreciation and amortization			12.17				11.11				9.09				8.09				7.48
Proved Reserves:
Oil (MBbls)			134,978				126,185				106,173				101,287				91,266
Natural gas (MMcf)			358,608				288,826				278,367				168,484				221,887
MBOE (6:1)			194,746				174,322				152,568				129,369				128,247
Carbon dioxide (MMcf) (5)			5,641,054				5,525,948				4,645,702				2,664,633				1,613,840
Consolidated Balance Sheet Data:
Total assets		$	2,771,077			$	2,139,837			$	1,505,069			$	992,706			$	982,621
Total long-term liabilities			1,102,066				833,380				617,343				368,128				434,845
Stockholders’ equity (6)			1,404,378				1,106,059				733,662				541,672				421,202

Denbury Resources Inc.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     We are a growing independent oil and 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 the Barnett Shale play near Fort Worth, Texas, onshore Louisiana and Alabama, and properties in Southeast Texas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, including secondary and 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; McComb, Mississippi; Brandon, Mississippi; and Cleburne, Texas.

2007 Overview

     Operating Results. During 2007, we set a corporate record for annual cash flow from operations of $570.2 million, a 23% increase over the $461.8 million of cash flow from operations generated during 2006. Our 2007 net income of $253.1 million was 25% higher than our $202.5 million of net income during 2006, even after including a $64.2 million decrease in pre-tax income between the respective periods from non-cash fair value adjustments associated with our commodity derivative contracts. Record high production levels, higher oil prices, and $25.8 million of incremental net cash receipts on our derivative contracts contributed to the positive results, partially offset by higher overall expenses, lower natural gas prices, and the effect of the $64.2 million differential in non-cash fair value adjustments associated with our commodity derivative contracts (see “Results of Operations – Oil and Natural Gas Revenues”).

     Our fourth quarter 2007 average production rate of 50,371 BOE/d and our 2007 average production of 44,115 BOE/d were Company quarterly and annual production records, with significant increases in our tertiary oil and Barnett Shale production, partially offset by production declines in our Louisiana onshore properties. Higher oil prices further improved 2007 results, as our average realized per BOE commodity price was 11% higher than during 2006, resulting in 13% higher revenues in 2007, together with 20% higher revenues due to higher production levels.

     Excluding any impact of our commodity derivative income and expense items, our aggregate expenses increased 33% during 2007 as compared to expenses during 2006 due to (i) higher overall industry costs, (ii) a higher percentage of operations related to tertiary operations, which generally have higher operating costs per BOE (see “Results of Operations — CO₂ Operations” for a more thorough discussion), (iii) higher average debt levels to finance our $42 million acquisition on March 31, 2007 (see “2007 Acquisitions” below) and continued spending in excess of cash flow from operations (see “Capital Resources and Liquidity”), and (iv) higher compensation expense resulting from additional employees and increased salaries which we consider necessary in order to remain competitive in the industry, partially offset by approximately $6.0 million of non-recurring charges to earnings in 2006 related to the departure and retirement of two vice presidents.

     As has been our practice for several years, we are reinvesting virtually all of our cash flow in new projects, with a desire to further increase our production and reserves. During 2007, our proved reserves increased from 174.3 MMBOE as of December 31, 2006, to 194.7 MMBOE as of December 31, 2007, replacing approximately 250% of our 2007 production, almost entirely from organic growth. The most significant reserve additions during 2007 were in the Barnett Shale (22.8 MMBOE) and in our tertiary operations (12.7 MMBOE). While we booked more proved tertiary reserves in 2007 than in 2006 (6.0 MMBOE), these reserve quantity additions were less than we expect to recognize during the next few years, presuming we have a production response from the tertiary floods we started in 2007 and expect to start in 2008 and 2009 (see “Results of Operations – Depletion, Depreciation and Amortization” for a review of our reserve changes during 2007 and a discussion of our proved tertiary reserves).

     While overall costs were higher in the 2007 periods than in the comparable 2006 periods, during 2007 the rate of inflation in our industry appears to have moderated, and in some cases, we are beginning to see modest cost reductions. Likewise, although oilfield goods and services are still in tight supply, there have been signs of improvement in overall availability; but some supply issues persist, including long lead times for certain goods and services, such as compressors used in our tertiary recycling facilities and construction services for pipelines. It is difficult to forecast price trends and supply and service availability, which if adverse, can significantly impact both operating costs and capital expenditures, as well as cause delays in achieving our anticipated production targets.

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

     Tertiary Operations. Having enough CO₂ to flood our tertiary oil fields is one of the most important ingredients, if not the key ingredient, to our tertiary operations. During 2007, we replaced 164% of our CO₂ production, increasing our proved CO₂ reserves slightly, from approximately 5.5 Tcf as of December 31, 2006 to approximately 5.6 Tcf as of December 31, 2007 (quantities are on a 100% working interest basis – see “CO₂ Operations – CO₂ Resources” for further information).

     Oil production from our tertiary operations increased to an average of 14,767 BOE/d in 2007, a 47% increase over 2006 tertiary production level of 10,070 BOE/d, with fourth quarter 2007 tertiary production averaging 17,428 BOE/d. Production from our Phase II operations in Eastern Mississippi (Soso, Eucutta and Martinville Fields) contributed 2,888 BOE/d (approximately 61%) to the increase over the prior year’s tertiary production level, with the balance of the increase coming from our Phase I fields, except for Little Creek Field which is on a gradual decline. In addition to further development of oil fields we already own and which are slated for tertiary flooding, we are continuing to buy additional oil fields that are candidates for future tertiary flood activity (see “2007 Acquisitions” below).

     Please refer to the section entitled “CO₂ Operations” below for a discussion of these operations, their potential, and the ramifications of our continuing emphasis on these operations.

     Sale of Louisiana Natural Gas Assets. In October 2007, we entered into an agreement to sell our Louisiana natural gas assets to a privately held company for approximately $180 million (before closing adjustments) plus any amounts received in the future from a net profits interest in a well. In late December 2007, we closed on approximately 70% of that sale with net proceeds of approximately $108.6 million (including estimated final purchase price adjustments), and closed on the remaining 30% on February 20, 2008, with net proceeds at the second closing of approximately $48.9 million. The operating net revenue, net of capital expenditures, between the August 1, 2007, effective date and the respective closing dates was an adjustment to the purchase price, along with other minor closing adjustments. The potential net profits interest relates to a well in the South Chauvin Field and is only earned if operating income from that well exceeds certain levels, which we believe could potentially increase the ultimate sales price by up to 10%.

     Production attributable to the sold properties averaged approximately 30.6 MMcfe/d (82% natural gas) during the fourth quarter of 2007, representing approximately 10% of our total fourth quarter production and approximately 4% of our total proved reserve quantities as of December 31, 2006.

     Genesis Transactions. On July 25, 2007, Genesis Energy, L.P. (“Genesis”), a master limited partnership of which Denbury is the general partner, closed on a previously announced acquisition in which they acquired several energy related businesses from the Davison family of Ruston, Louisiana, for total consideration of approximately $623 million (net of cash acquired at closing and subject to final purchase price adjustments). The acquisition agreement provided that Genesis deliver $560 million of consideration, half in common units at an agreed value of $20.8036 per unit (as compared to a value of $24.52 per unit for accounting purposes) and half in cash, subject to specified purchase price adjustments. In conjunction with that acquisition, we exercised our right to maintain our pro rata (7.4%) ownership of common units, acquiring 1,074,882 additional common units for approximately $22.4 million, in addition to our capital contribution of an additional $6.2 million as general partner to maintain our 2% general partner’s interest.

     In order to maintain our pro rata (7.4%) common unit ownership interest in Genesis, we acquired an additional 734,732 common units in a December 2007 Genesis public offering at $21.29 per unit, the public offering price of $22.00 per unit, less the underwriting discount. Our total cost for the units, including the 2% general partner portion of the offering, was $20.0 million.

     The Company has reached substantial agreement and is in the process of finalizing the business issues with Genesis and its lenders as to the terms of the transactions with Genesis involving the Company’s NEJD and Free State CO₂ Pipelines, including a long-term transportation service arrangement for the Free State line and a 20-year financing lease for the NEJD system. In these transactions, Denbury expects to receive from Genesis $225 million in cash and $25 million of Genesis common limited partnership units at the average closing price of the units on the thirty days prior to closing. The Company anticipates capitalizing these transactions for accounting purposes and currently projects that it will initially pay Genesis approximately $30 million per annum under the financing lease and transportation services agreement (and a lesser pro-rated amount for 2008), with future payments for the NEJD pipeline payments fixed at $20.7 million per year during the term of the financing lease, and the payments relating to

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

the Free State Pipeline dependant on the volumes of CO₂ transported therein. While the business terms of the transactions have been substantially completed, closing remains subject to finalization of legal issues and completion and delivery of closing documentation. Currently, we will also consider similar transactions with Genesis for the new CO₂ pipeline we have constructed from Jackson Dome to Tinsley Field and are constructing from Tinsley Field to Delhi Field (the “Delta Pipeline”), once that pipeline is completed, forecasted at this time to be completed in late 2008 or early 2009, or potentially we could divide that pipeline into two segments and two separate transactions. If in future periods Genesis is able to complete additional acquisitions of non-Denbury related assets of sufficient size and with acceptable returns, we would consider additional dropdowns with Genesis of certain of our existing or planned assets provided that such transactions can generate “qualified income” for a master limited partnership, which may depend in part on the degree to which we ship man-made CO₂ on such lines and the status of man-made CO2 as “qualified income.”

     2007 Acquisitions. On March 30, 2007, we completed an acquisition of six producing oil and natural gas fields, two of which are future potential CO₂ tertiary oil flood candidates, collectively called the Seabreeze Complex, located near Houston, Texas, at a cost of approximately $39.4 million. Tertiary operations are not expected to commence at these fields until 2010 or 2011, following anticipated completion of the 300 mile CO₂ pipeline from Louisiana to Hastings Field (also near Houston). The acquisition was funded with bank financing under our existing credit facility. At the time of acquisition, these fields had estimated proved conventional reserves of approximately 525 MBOE and produced an average of 759 BOE/d during the fourth quarter of 2007. We operate all of these fields and own the majority of the working interests.

     We also purchased East and South Gillock Fields in 2007, small future CO₂ tertiary oil flood candidates, also located near Houston, Texas, at a cost of approximately $3.5 million. The conventional reserves and production associated with these fields was negligible at the time of the acquisition.

     April 2007 Debt Issuance. On April 3, 2007, we issued $150 million of 7.5% Senior Subordinated Notes due 2015 as an additional issuance under our existing indenture governing our December 2005 sale of $150 million of 7.5% Senior Subordinated Notes due 2015. The notes were issued at 100.5% of par, which equates to an effective yield to maturity of 7.4%. The net proceeds from the issuance were approximately $149.2 million, which we used to repay a portion of the outstanding borrowings under our bank credit facility.

Capital Resources and Liquidity

     Our current 2008 capital exploration and development budget is approximately $900 million, excluding any potential acquisitions. The current 2008 program includes an estimated $245 million to acquire pipe and right-of-ways for our proposed CO₂ pipeline from Louisiana to Texas (the “Green Pipeline”) and another $80 million for the segment of the Delta CO₂ Pipeline from Tinsley to Delhi Fields. We expect to spend an additional $450 million constructing the Green Pipeline during 2009, making our current anticipated total cost for that line approximately $700 million. Currently, over 50% of the remaining portion of our 2008 budget is expected to be spent on other tertiary related operations, over 25% in the Barnett Shale area, and the balance in other areas. Based on oil and natural gas commodity futures prices as of late February 2008 and our current 2008 production forecasts, our 2008 capital budget is forecasted to be $125 million to $175 million greater than our anticipated cash flow from operations. We plan to fund most of this deficit with cash generated by the anticipated “drop-down” transaction with Genesis (see “2007 Overview – Genesis Transactions”) and our recently completed sale of Louisiana natural gas assets (see “2007 Overview – Sale of Louisiana Natural Gas Assets”). We could potentially also generate additional funds of up to $150 million through transactions with Genesis whereby we could “drop-down” our Delta CO₂ Pipeline, or portions thereof, to Genesis (see “2007 Overview – Genesis Transactions”).

     If the Delta Pipeline “drop-down” to Genesis is not consummated, or if there is still a shortfall in excess of the cash generated by our recently completed Louisiana property sale and proposed “drop-down” of pipelines to Genesis described above, we would likely fund the deficit with bank debt. In addition, if commodity prices were to significantly decrease from current levels, we could also reduce our capital spending during 2008 commensurately, in addition to using bank debt to fund the deficit.

     As of February 28, 2008, we had $111 million of bank debt outstanding on a $500 million borrowing base, leaving us significant incremental borrowing capacity, more than we currently plan or desire to use. Further, we believe that we could significantly increase our bank borrowing base if desired, and anticipate increasing it at our April 1, 2008 redetermination.

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

     We monitor our capital expenditures on a regular basis, adjusting them up or down depending on commodity prices and the resultant cash flow. Therefore, during the last few years as commodity prices have increased, we have increased our capital budget throughout the year. As a result of cost inflation in our industry in recent years, many of our recent year budget increases have related to escalating costs rather than additional projects. Even though there are signs that the rate of this inflationary trend is subsiding, if costs do rise or we spend more than our estimated amounts, we will either have to increase our capital budget or consider deferring a portion of our planned projects.

     We continue to pursue additional acquisitions of mature oil fields that we believe have potential as future tertiary flood candidates. These possible acquisitions are difficult to forecast and the purchase price can vary widely depending on the levels of existing production, conventional proved reserves and commodity prices. Any additional acquisitions would be funded, at least temporarily, with bank or other debt, although if significant, the acquisition would likely be ultimately funded with more permanent capital such as subordinated debt and/or additional equity.

     Amendment to our bank credit facility. On March 31, 2007, we amended our Sixth Amended and Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative agent. The amendment (i) increased the commitment amount that the banks are committed to fund from $250 million to $350 million, (ii) reconfirmed the borrowing base of $500 million, (iii) authorized last spring’s $150 million subordinated debt offering (see “2007 Overview – April 2007 Debt Issuance”), and (iv) authorized us to enter into a sale-leaseback type transaction for our CO₂ pipelines, not to exceed $300 million, with Genesis, in the type of transaction contemplated and discussed above (see “2007 Overview – Genesis Transactions”). With regard to our bank credit facility, the borrowing base represents the amount that can be borrowed from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request by us in excess of the commitment amount ($350 million), up to the borrowing base limit ($500 million), although the banks are not obligated to fund any amount in excess of the commitment amount. At February 28, 2008, we had outstanding $525 million (principal amount) of 7.5% subordinated notes and $111 million of bank debt.

Sources and Uses of Capital Resources

Capital Expenditure Summary

		Year Ended December 31,
Amounts in thousands		2007				2006				2005
Oil and gas exploration and development
Drilling		$	313,258			$	245,350			$	147,773
Geological, geophysical and acreage			22,829				31,590				25,519
Facilities			118,003				98,890				65,018
Recompletions			141,264				120,438				70,056
Capitalized interest			18,305				11,059				—
Total oil and gas exploration and development expenditures			613,659				507,327				308,366
Oil and gas property acquisitions			49,077				319,000				70,870
Total oil and natural gas capital expenditures			662,736				826,327				379,236
CO2 source field capital expenditures, including capitalized interest			171,182				63,586				78,726
Total		$	833,918			$	889,913			$	457,962

     Our 2007 capital expenditures have been funded with $570.2 million of cash flow from operations, $150.0 million from our issuance of subordinated debt in April, $135.8 million from sales proceeds, and $16.0 million of net bank borrowings, with the excess proceeds used for other purposes, including the $48.5 million incremental investment in Genesis.

     Our 2006 expenditures were funded with $461.8 million of cash flow from operations, $139.8 million of equity issued and $134.0 million of net bank borrowings, and a $13.2 million increase in our accrued capital expenditures, with the balance funded with working capital, predominately cash from the December 2005 issuance of $150 million of subordinated debt.

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Off-Balance Sheet Arrangements

Commitments and Obligations

     At December 31, 2007, we have no off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees, other than as disclosed in this section. We have no debt or equity triggers based upon our stock or commodity prices. Our dollar denominated payment obligations that are not on our balance sheet include our operating leases, which at year-end 2007 totaled $143.8 million (including $98.5 million of 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. Additionally, we have dollar related 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 “Results of Operations – Depletion, Depreciation and Amortization” below.

     At December 31, 2007, we had a total of $10.5 million outstanding in letters of credit. Genesis Energy, Inc., our 100% owned subsidiary that is the general partner of Genesis, may, as general partner, be a potential guarantor of the bank debt of Genesis, which consists of $80.0 million in debt and $5.3 million in letters of credit at December 31, 2007. There were no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. at December 31, 2007. We do not have any material transactions with related parties other than sales of production, transportation arrangements, capital leases with Genesis made in the ordinary course of business, and volumetric production payments of CO₂ (“VPP”) sold to Genesis as discussed in Note 3 to our Consolidated Financial Statements. The anticipated conveyance of our CO₂ pipelines to Genesis would require payments over a minimum of 20 years and is not included in the commitment table below (see “2007 Overview – Genesis Transactions”). If consummated, we anticipate capitalizing these transactions for accounting purposes, and currently project that we will initially pay Genesis approximately $30 million per annum under the lease financing and transportation agreement (and a lesser pro-rated amount for 2008), with future payments for the NEJD Pipeline fixed at $20.7 million per year during the 20-year service term of the financing lease, and the payments relating to the Free State Pipeline dependant on the volumes of CO₂ transported thereon, with a minimum annual payment for the Free State Pipeline of $1.2 million.

     We currently have long-term commitments to purchase manufactured CO₂ from three proposed gasification plants, if these plants are built, two proposed by the developers of Faustina Hydrogen Products LLC and another by Rentech Inc. If all three plants are built, these synthetic sources are currently anticipated to provide us with an aggregate of 750 MMcf/d to 850 MMcf/d of CO₂ by 2013. The base price of CO₂ per Mcf from these synthetic sources is currently expected to be 1.5 to 2.0 times higher than our most recent all-in cost of CO₂ from our natural sources (Jackson Dome) using current oil prices and assuming comparable compression levels. These predicted synthetic CO₂ prices are expected to be competitive with the cost of our natural CO₂ after adjusting for our share of potential carbon emissions credits using estimated current prices of CO₂ carbon credit futures. If all three plants are built, the aggregate purchase obligation for this CO₂ would be around $190 million per year, assuming a $90 per barrel oil price and comparable compression levels, before any potential savings from our share of carbon emissions 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; although based on their public representations, the initial Faustina plant is currently scheduled to begin construction during 2008, with completion scheduled in late 2010 or 2011. These amounts are not included in the table below as these payments are contingent on the plants being built.

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

     A summary of our obligations at December 31, 2007, is presented in the following table:

		Payments Due by Period
Amounts in Thousands		Total				2008				2009				2010				2011				2012				Thereafter
Contractual Obligations:
Subordinated debt (a)		$	525,000			$	—			$	—			$	—			$	—			$	—			$	525,000
Senior Bank Loan (a)			150,000				—				—				—				150,000				—				—
Estimated interest payments on subordinated debt and Senior Bank Loan (a)			301,705				48,613				48,612				48,613				45,879				39,375				70,613
Operating lease obligations			143,768				17,580				17,128				16,745				16,185				14,957				61,173
Capital lease obligations (b)			8,738				1,291				1,529				1,291				1,291				1,242				2,094
Capital expenditure obligations (c)			166,041				113,628				50,658				1,755				—				—				—
Derivative contracts payment (d)			23,914				23,914				—				—				—				—				—
Hastings Field purchase option			5,000				5,000				—				—				—				—				—
Other Cash Commitments:
Future development costs on proved oil and gas reserves, net of capital obligations (e)			530,778				179,033				143,053				103,168				41,940				21,250				42,334
Future development cost on proved CO2 reserves, net of capital obligations (f)			133,894				46,794				11,000				—				—				—				76,100
Asset retirement obligations (g)			100,530				2,685				2,251				3,762				1,285				747				89,800
Total		$	2,089,368			$	438,538			$	274,231			$	175,334			$	256,580			$	77,571			$	867,114

     During November 2006 we entered into an agreement that gives us an option on September 1, 2008, and September 1, 2009, to be effective on the following January 1^st, to purchase an interest in Hastings Field, a strategically significant potential tertiary flood candidate located near Houston, Texas. The agreement provides for the parties to agree upon a purchase price for the conventional proved reserves at the time of the exercise of the

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

option, which may be paid in cash or through a volumetric production payment; failing an agreement as to price, the price will be determined by a pre-designated independent petroleum engineering firm using specified criteria for calculation of the discounted present value of proved reserves at that time. As consideration for the option agreement, to date we have paid $45 million under this option and have a remaining payment due in November 2008 of $5.0 million. We can extend the option period beyond November 2009 for up to seven additional years at an incremental cost of $30 million per year. None of the option payment amounts will be credited against the purchase price if we exercise the option. If we exercise the option, we will be committed to make aggregate net capital expenditures in the field totaling approximately $175 million over the subsequent five years to develop the field for tertiary operations, with an obligation to commence CO₂ injections in the field within three years following the option exercise. The above table does not include the commitments related to Hastings Field if the purchase option is exercised by us, as the obligation is at our option. The above table does include the remaining $5.0 million due on the Hastings option payment.

     Long-term contracts require us to deliver CO₂ to our industrial CO₂ customers at various contracted prices, plus we have a CO₂ delivery obligation to Genesis pursuant to three volumetric production payments (“VPP”) entered into during 2003 through 2005. Based upon the maximum amounts deliverable as stated in the industrial contracts and the volumetric production payments, we estimate that we may be obligated to deliver up to 562 Bcf of CO₂ to these customers over the next 20 years; however, since the group as a whole has historically taken less CO₂ than the maximum allowed in their contracts, based on the current level of deliveries, we project that our commitment would likely be reduced to approximately 268 Bcf. The maximum volume required in any given year is approximately 142 MMcf/d, although based on our current level of deliveries this would likely be reduced to approximately 72 MMcf/d. Given the size of our proven CO₂ reserves at December 31, 2007 (approximately 5.6 Tcf before deducting approximately 182.3 Bcf for the three VPPs), our current production capabilities and our projected levels of CO₂ usage for our own tertiary flooding program, we believe that we will be able to meet these delivery obligations.

Results of Operations

CO₂ Operations

     Overview. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999, our interest in tertiary operations has increased to the point that approximately 72% of our current 2008 capital budget is dedicated to tertiary related operations. We particularly like this play as (i) it has a lower risk and is more predictable than most traditional exploration and development activities, (ii) it provides a reasonable rate of return at relatively low oil prices (generally around $30 a barrel at today’s cost levels, depending on the specific field and area), and (iii) we have virtually no competition for this type of activity in our geographic area. Generally, from East Texas to Florida, there are no known significant natural sources of CO₂ except our own, and these large volumes of CO₂ that we own drive the play.

     We talk about our tertiary operations by labeling operating areas or groups of fields as phases. Phase I is in Southwest Mississippi and includes several fields along our 183-mile NEJD CO₂ Pipeline that we acquired in 2001. The most significant fields in this area are Little Creek, Mallalieu, McComb and Brookhaven. Phase II, which began with the early 2006 completion of the Free State CO₂ Pipeline to East Mississippi, includes Eucutta, Soso, Martinville and Heidelberg Fields. Tinsley Field located northwest of Jackson, Mississippi, acquired in January 2006, is our Phase III and is serviced by that portion of the Delta CO₂ Pipeline completed in January 2008. Phase IV includes Cranfield and Lake St. John Fields, two fields near the Mississippi/Louisiana border located west of the Phase I fields, and Phase V is Delhi Field, a Louisiana field we acquired in 2006, located southwest of Tinsley Field. Flooding in Phase V will begin in 2009 upon completion of the Delta CO₂ Pipeline from Tinsley to Delhi. Citronelle Field in Southwest Alabama, another field acquired in 2006, is our Phase VI which will require an extension to the Free State CO₂ Pipeline, the timing of which is uncertain at this time. Our last two currently existing phases will require completion of our proposed Green Pipeline, a 300-mile CO₂ pipeline which will run from Southern Louisiana to near Houston, Texas, and is scheduled for completion in late 2009 or 2010. Hastings Field, a field on which we acquired a purchase option in late 2006 (see “Commitments and Contingencies”), is our Phase VII, and the Seabreeze Complex, acquired in 2007, will be our Phase VIII (see “2007 Overview – 2007 Acquisitions”).

     CO₂ Resources. Since we acquired the CO₂ source field located near Jackson, Mississippi, in 2001, we have continued to develop the field and have increased the proven CO₂ reserves from approximately 800 Bcf at the time

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

of the acquisition to approximately 5.6 Tcf as of December 31, 2007. During 2007, our proven CO₂ reserves increased approximately 5%, or 295 Bcf (excluding 2007 production). The estimate of 5.6 Tcf of proved CO₂ reserves is based on 100% ownership of the CO₂ reserves, of which Denbury’s net revenue interest ownership is approximately 4.5 Tcf. Both reserve estimates are included in the evaluation of proven CO₂ reserves prepared by DeGolyer and MacNaughton. In discussing the available CO₂ reserves, we make reference to the gross amount of proved reserves, as this is the amount that is available for Denbury’s tertiary recovery programs, Genesis, and industrial users, as Denbury is responsible for distributing the entire CO₂ production stream for both of these uses. We currently estimate that it will take approximately 2.4 Tcf of CO₂ to develop and produce the proved tertiary recovery reserves we have recorded at December 31, 2007, in Phases I and II.

     Today, we own every known producing CO₂ well in the region, providing us a significant strategic advantage in the acquisition of other properties in Mississippi and Louisiana that could be further exploited through tertiary recovery. As of February 20, 2008, we estimate that we are capable of producing approximately 700 MMcf/d of CO₂, over six times the rate that we were capable of producing at the time of our initial acquisition in 2001. We continue to drill additional CO₂ wells, with five more wells planned for 2008, in order to further increase our production capacity and potentially increase our proven CO₂ reserves. Our drilling activity at Jackson Dome will continue beyond 2008 as our current forecasts for the existing eight phases suggest that we will need approximately 1.4 Bcf/d of CO₂ production by 2012.

     In addition to using CO₂ for our tertiary operations, we sell CO₂ to third party industrial users under long-term contracts. Most of these industrial contracts have been sold to Genesis along with the sale of a volumetric production payment for the CO_2. Our average daily CO₂ production during 2005, 2006 and 2007 was approximately 242 million, 342 million and 493 million cubic feet per day, respectively, of which approximately 73% in 2005, 75% in 2006 and 81% in 2007 was used in our tertiary recovery operations, with the balance delivered to Genesis under the volumetric production payments or sold to third party industrial users.

     We spent approximately $0.21 per Mcf in operating expenses to produce our CO₂ during 2007, more than our 2006 average of $0.19 per Mcf and our 2005 average of $0.16 per Mcf, with the higher costs each year primarily due to higher oil costs, which impacts the amount we pay royalty owners for the CO₂, and higher operating costs. Our estimated total cost per thousand cubic feet of CO₂ during 2007 was approximately $0.29, after inclusion of depreciation and amortization expense related to the CO₂ production, as compared to approximately $0.28 during 2006 and $0.25 during 2005.

     Man-Made CO₂ Sources. In addition to our natural source of CO₂, we are in discussions with the owners of several possible gasification plants which, if built, will convert coal or petroleum coke into various other fuels, with CO₂ being a significant by-product of the process. We expect these plants to provide us with significant additional sources of CO₂ in the future which would enable us to further expand our tertiary operations, although the earliest source of this manufactured CO₂ is not expected to be available to us until late 2010 or 2011. We have entered into long-term commitments to purchase manufactured CO₂ from three proposed plants (see “Commitments and Obligations”), which, if all three plants are built, are currently anticipated to provide us with an aggregate of 750 MMcf/d to 850 MMcf/d of CO₂ by 2013. While we are uncertain as to whether these three specific plants will be built, we anticipate that some gasification plants will be built within the next several years. If correct in our assumptions, we believe that we are a likely purchaser of CO₂ produced from such plants built in our area of operations because of the scale of our tertiary operations, the CO₂ pipeline infrastructure that we are continuing to develop, and the large natural source of CO₂ (Jackson Dome), which can act as a swing CO₂ producer if needed.

     Overview of Tertiary Economics. When we began our tertiary operations several years ago, they were generally economic at oil prices below $20 per Bbl, although the economics varied by field. Our costs have escalated during the last few years due to general cost inflation in the industry, raising our current economic oil price to around $30 per Bbl, again dependent on the specific field. Our inception-to-date finding and development costs (including future development and abandonment costs but excluding expenditures on fields without proven reserves) for our tertiary oil fields through December 31, 2007, are approximately $9.75 per BOE. Currently, we forecast that these costs will range from $5 to $10 per BOE over the life of each field, depending on the state of a particular field at the time we begin operations, the amount of potential oil, the proximity to a pipeline or other facilities, etc. Our operating costs for tertiary operations are expected to range from $15.00 to $20.00 per BOE over the life of each field (at today’s prices), again depending on the field itself.

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

     While these economic factors have wide ranges, our rate of return from these operations has generally been better than our rate of return on traditional oil and gas operations, and thus our tertiary operations have become our single most important focus area. While it is extremely difficult to accurately forecast future production, we do believe that our tertiary recovery operations provide significant long-term production growth potential at reasonable rates of return, with relatively low risk, and thus will be the backbone of our Company’s growth for the foreseeable future. Although we believe that our plans and projections are reasonable and achievable, there could be delays or unforeseen problems in the future that could delay or affect the economics of our overall tertiary development program. We believe that such delays or price effects, if any, should only be temporary.

     Financial Statement Impact of CO₂ Operations. Our increasing emphasis on CO₂ tertiary recovery projects has significantly impacted and will continue to impact our financial results and certain operating statistics.

     First, there is a significant delay between the initial capital expenditures on these fields and the resulting production increases, as we must build facilities before CO₂ flooding can commence, and it usually takes six to 12 months before the field responds to the injection of CO₂ (i.e., oil production commences). Further, we may spend significant amounts of capital before we can recognize any proven reserves from fields we flood (see “Analysis of CO₂ Tertiary Recovery Operating Activities” below). Even after a field has proven reserves, there will usually be significant amounts of additional capital required to fully develop the field.

     Second, these tertiary projects are usually more expensive to operate than our other oil fields because of the cost of injecting and recycling the CO₂ (primarily due to the significant energy requirements to re-compress the CO₂ back into a near-liquid state for re-injection purposes). As commodity and energy prices increase, so do our operating expenses in these fields. Most of our CO₂ operating expenses are allocated to our oil fields and recorded as lease operating expenses on those fields at the time the CO₂ is injected. Since we expense all of the operating costs to produce and inject our CO₂, the operating costs per barrel will be higher at the inception of CO₂ injection projects because of little or minimal related oil production at that time. Commencing in 2008, we plan to capitalize the cost of CO₂ and related operating costs until production commences, which may slightly reduce our cost per BOE (see Note 1 to the Consolidated Financial Statements, “Significant Accounting Policies – Tertiary Injection Costs”). Our total corporate operating expenses on a per BOE basis will likely continue to increase as these operations constitute an increasingly larger percentage of our operations. Generally, these higher operating costs are somewhat offset by lower finding and development costs which helps to lower our overall depreciation and depletion rate (see also “Overview of Tertiary Economics” above and “Analysis of CO₂ Tertiary Recovery Operating Activities” below).

     Analysis of CO₂ Tertiary Recovery Operating Activities. We currently have tertiary operations ongoing at almost all Phase I fields, and Soso, Martinville and Eucutta Fields in Phase II, and we are currently injecting CO₂ at Tinsley Field in Phase III. We project that our oil production from our CO₂ operations will increase substantially over the next several years as we continue to expand this program by adding additional projects and phases. As of December 31, 2007, we had approximately 69.5 MMBbls of proven oil reserves related to tertiary operations (48.3 MMBbls in Phase I and the balance in Phase II) and have identified and estimate significant additional oil potential in other fields that we own in this region.

     We added 12.7 MMBbls of tertiary-related proved oil reserves during 2007, primarily initial proven tertiary oil reserves at Soso and Martinville Fields (Phase II). Prior to 2006, we booked most of our proven tertiary oil reserves near the start of a project as almost all the oil fields in Phase I were analogous to Little Creek Field (our first flood) and thus it was not necessary to have an oil production response to the CO₂ injections before they were considered proven. Conversely, our new floods (after Phase I) are not analogous (for the most part), as the tertiary floods will be in different geological formations. Therefore, for these new phases, there must be an oil production response to the CO₂ injections before we can recognize proven oil reserves, even though we believe that these formations have a similar risk profile. The magnitude of proven reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.

     Our average annual oil production from our CO₂ tertiary recovery activities has increased during the last few years, from 3,970 Bbls/d in 2002 to 14,767 Bbls/d during 2007. Tertiary oil production represented approximately 53% of our total corporate oil production during 2007 and approximately 33% of our total corporate production of both oil and natural gas during the same period on a BOE basis. We expect that this tertiary related oil production will continue to increase, although the increases are not always predictable or consistent. While we may have temporary fluctuation in oil production related to tertiary operations, this does not indicate any issue with the proved

Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

and potential oil reserves recoverable with CO₂, because the historical correlation between oil production and CO₂ injections remains high. A detailed discussion of each of our tertiary oil fields and the development of each is included on pages 8 — 10 under “Our Tertiary Oil Fields With Proved Tertiary Reserves.” Following is a chart with our tertiary oil production by field for 2005 and 2006, and by quarter for 2007. In 2007, we saw continued improved response from our newer Phase II floods at Martinville, Eucutta and Soso Fields, most of which were initiated during 2006. In addition, we continue to see improved response at most of our other floods in Phase I, except for Little Creek Field, which is a mature flood and is expected to continue to gradually decline over the next several years.

		Average Daily Production (BOE/d)
		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter					Year Ended December 31,
Tertiary Oil Field		2007				2007				2007				2007					2007				2006				2005
Phase I:
Brookhaven			1,422				1,794				2,452				2,507					2,048				833				31
Little Creek area			2,117				1,974				2,011				1,957					2,014				2,739				3,529
Mallalieu area			5,470				5,802				5,823				6,304					5,852				5,210				4,739
McComb area			1,811				1,884				1,853				2,096					1,912				1,235				916
Phase II:
Martinville			320				521				1,101				883					709				6				—
Eucutta			614				1,338				2,035				2,572					1,646				47				—
Soso			25				370				826				1,109					586				—				—
Total tertiary oil production			11,779				13,683				16,101				17,428					14,767				10,070				9,215