UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2006 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, 2006

OR

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

For the transition period from                      to                     

Commission file number 1-12935

DENBURY RESOURCES INC.

Delaware		20-0467835
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)
5100 Tennyson Parkway,
Suite 1200, Plano, TX		75024
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code:		(972) 673-2000

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class:		Name of Each Exchange on Which Registered:
Common Stock $.001 Par Value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o      No þ

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

Indicate by check mark 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, or a non-accelerated filer. (See definition of “accelerated filer and large accelerated filer” in Rule 12-b2 of the Exchange Act). (Check one):

Large accelerated filer þ      Accelerated filer o      Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).
Yes o      No þ

The aggregate market value of the registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter was $3,417,875,900.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2007, was 120,470,488.

DOCUMENTS INCORPORATED BY REFERENCE

Document:		Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Shareholders to be held May 15, 2007.		1. Part III, Items 10, 11, 12, 13, 14

 

 

Denbury Resources Inc.
2006 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			20
Item 1B.	Unresolved Staff Comments			25
Item 2.	Properties			25
Item 3.	Legal Proceedings			25
Item 4.	Submission of Matters to a Vote of Security Holders			25
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			26
Item 6.	Selected Financial Data			28
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 7A.	Quantitive and Qualitive 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			90
Item 9A.	Controls and Procedures			90
Item 9B.	Other Information			91
PART III
Item 10.	Directors, Executive Officers and Corporate Governance			91
Item 11.	Executive Compensation			91
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			91
Item 13.	Certain Relationships and Related Transactions, and Director Independence			92
Item 14.	Principal Accountant Fees and Services			92
PART IV
Item 15.	Exhibits and Financial Statement Schedules			92
	Signatures			95
Amendment for Increased Commitment
Description of Equity and Other Long-term Award Grant Practices
Description of Non-Employee Directors' Compensation Arrangements
2007 Form of Restricted Stock Award
2007 Form of Performance Share Awards
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 & CFO Pursuant to Section 302
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.
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.
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% in accordance with the guidelines of the Securities and Exchange Commission.
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 Louisiana, Mississippi, Alabama, and Texas. 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, 2006, we had 596 employees, 390 of whom were employed in field operations or at the field offices. Our employee count does not include the approximately 190 employees of Genesis Energy, Inc. as of December 31, 2006, 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 2006, we concentrated on implementing new tertiary floods in our Phase II fields, Eucutta, Soso and Martinville Fields, while continuing to develop our Phase I fields Little Creek, Mallalieu, McComb and Brookhaven. We increased our potential tertiary flood candidates during 2006 with the acquisition of Tinsley Field (Phase III) and Delhi Field (Phase V), and an option to purchase Hastings Field, adding to our inventory of future tertiary floods. Our tertiary operations are our principal focus and our core assets. During the last seven years, we have learned a considerable amount about tertiary operations and working with carbon dioxide (“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, 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 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 projects 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 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.

     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 CO₂ pipeline that we acquired in 2001. The most significant fields in this area are Little Creek, Mallalieu, McComb and Brookhaven. Phase II, which we just started with the 2006 completion of our CO₂ pipeline to East Mississippi, includes Eucutta, Soso, Martinville and later, Heidelberg Fields. With the properties acquired in our January 2006 acquisition, we have labeled the planned operations at Tinsley Field, Northwest of Jackson Dome, as Phase III. Phase IV includes Cranfield and Lake St. John Fields, two fields near the Mississippi/ Louisiana border acquired in 2005 and which are located west of the Phase I fields. Phase V is Delhi Field, a Louisiana field we acquired in May 2006. We also plan to ultimately flood Citronelle Field, another field acquired in 2006, and Hastings Field, a field on which we recently acquired a purchase option. We have not yet labeled these two fields as a specific phase.

Denbury Resources Inc.

     Jackson Dome. In February 2001, we acquired approximately 800 Bcf of proved producing CO₂ reserves for $42.0 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 11 additional CO₂ producing wells, significantly increasing our estimated proved CO₂ reserves to approximately 5.5 Tcf as of December 31, 2006, which is more than enough for our existing and currently planned phases of operations. The estimate of 5.5 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 proven CO₂ reserves prepared by DeGolyer & 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 up to three additional wells during 2007.

     During the fourth quarter of 2006, we produced an average of 394 MMcf/d of CO₂. We sold an average of 78 MMcf/d of CO₂ to commercial users and we used an average of 316 MMcf/d for our tertiary activities. We estimate that our current daily CO₂ deliverability is around 470 MMcf/d. By year-end 2007, we estimate that our planned tertiary operations will require between 650 and 700 MMcf/d, but with our planned 2007 Jackson Dome projects, we expect to increase our CO₂ deliverability to between 700 MMcf/d and 800 MMcf/d by that time. Our geoscientists are using a 100 square mile 3-D seismic survey to locate additional structures that are expected to contain CO₂. We plan to continue our CO₂ drilling activity in 2007 and beyond, as our CO₂ deliverability needs will continue to grow as we expand our planned tertiary projects.

     Man-made CO₂ sources. We entered into an agreement and committed to purchase (if the plant is built) 100% of the CO₂ production from a man-made (anthropogenic) source of CO₂, a planned petroleum coke gasification project scheduled to be completed in 2010. This Faustina plant, proposed to be located near Donaldsonville, Louisiana, will convert petroleum coke into ammonia. As a byproduct of the combustion, large quantities of CO₂ will be produced, estimated to be around 200 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. The Faustina agreement allows us to add the potential equivalent volume of an additional one Tcf of CO₂ over the term of our contract. Construction of this plant has not yet begun, so we are not certain whether this plant will be built, although it appears likely. We are in discussions with several other entities that are considering other types of coal or petroleum coke gasification plants. These plants may convert petroleum coke or coal into a variety of products including ammonia, methanol, synthetic diesel fuel, or electrical power generation. The cost of this 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. 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 Donaldsville, Louisiana as part of the 2001 acquisition (see above). During the first quarter of 2006, we completed the 20”, 86-mile Free State Pipeline, which we are initially using to transport CO₂ to our three new Phase II fields in East Mississippi (Eucutta, Soso, and Martinville). Completion of this line was a significant accomplishment for our team and expands our CO₂ tertiary recovery technology to many potentially significant reservoirs in the eastern part of the state.

     During 2006, we reached agreement with Southern Natural Gas Company to acquire a natural gas pipeline that runs from Gwinville Field to near Lake St. John Field in Louisiana. This pipeline crosses our existing NEJD 20” CO₂ pipeline in Southwest Mississippi, and once converted to CO₂ service, will allow us to transport CO₂ from the NEJD pipeline to Lake St. John and Cranfield Fields, both acquired in 2005 (our planned Phase IV). We are in the process of building a small replacement natural gas pipeline to service certain communities currently supplied by

Denbury Resources Inc.

the acquired line, after which we can convert the acquired natural gas line to CO₂ service. We expect to have this completed by the fourth quarter of 2007.

     The 2006 acquisition of Tinsley Field included an eight-inch pipeline, previously being used for natural gas sales and storage, from our Jackson Dome area to the field. We converted the natural gas line to a CO₂ pipeline and in early 2007 began using it to transport CO₂ to Tinsley Field, albeit in limited volumes. During 2007, we plan to construct a 24”, 31 mile line from Jackson Dome to Tinsley Field, with completion anticipated in the third or fourth quarter of 2007. We plan to further extend this line by building a 68 mile 20” extension from Tinsley Field to Delhi Field with completion for this segment anticipated during the first half of 2008.

     In late 2006, we purchased an option to acquire Hasting Field, a potential tertiary flood located near Houston, Texas. We plan to build a pipeline to transport CO₂ to this field from the southern end of our existing CO₂ pipeline that terminates near Donaldsonville, Louisiana, estimated at between 280 and 300 miles. Based on very preliminary estimates, this pipeline is expected to cost between $450 million and $650 million, although this cost could vary significantly depending on the ultimate size of the pipeline, its pressure rating, its specific route, and other variables, all of which are unknown at this time. We are initiating studies related to construction of this line, with a goal of having it installed and operational during 2009. We anticipate initially transporting CO₂ from our natural source at Jackson Dome, but ultimately plan to use man-made (anthropogenic) sources of CO₂ for this tertiary operation.

     Overall economics. Initially, our tertiary operations were 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, 2006, was approximately $8.50 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 $13 to $15 per BOE over the life of each field (at today’s prices), again depending on the field itself.

     Oil quality is another significant factor that impacts the economics. In Phase I (Southwest Mississippi), the light sweet oil produced from our tertiary operations receives near NYMEX prices, while the average discount to NYMEX for the lower quality oil produced from the fields in Phase II (East Mississippi), some of which we started flooding during 2006, was $13.51 per BOE during 2006, a differential that is significantly higher than our historical corporate averages and one that appears to increase as oil prices increase.

     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 $70 million in 2007 in the Jackson Dome area with the intent to add additional CO₂ reserves and deliverability for future operations. Approximately $60 million in capital expenditures is budgeted in 2007 for our Phase II properties (East Mississippi) and approximately $200 million for Phase III properties (Tinsley), plus an additional $70 million for properties in other phases, making our combined CO₂ related expenditures just over 60% of our $650 million 2007 capital budget.

Our Tertiary Oil Fields with Proven Tertiary Reserves

     At December 31, 2006, we had total tertiary-related proved oil reserves of approximately 62.2 MMBbls, consisting of 3.7 MMBbls at Little Creek Field (and surrounding smaller fields), 13.6 MMBbls at Mallalieu Field, 12.7 MMBbls at McComb Field, 19.0 MMBbls at Brookhaven Field, 2.7 MMBbls at Smithdale Field, 10.3 MMBbls at Eucutta Field and 0.2 MMBbls at Martinville Field. Overall, our production from tertiary operations has

Denbury Resources Inc.

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 10,028 Bbls/d during the fourth quarter of 2006. We expect this production to continue to increase for several years as we expand our tertiary operations to additional fields.

     With regard to our proven tertiary reserves, 2006 was a transition year for us, as we added only 6.0 MMBbls of tertiary-related proved oil reserves during the year, primarily incremental oil reserves at McComb and Mallalieu Fields (both Phase I). Previously, we booked most 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. Since many of our Phase II projects were delayed during 2006, the production response needed to record any significant incremental tertiary oil reserves in this new area was delayed. We anticipate booking significant amounts of proven tertiary oil reserves during 2007 and beyond, although the magnitude will depend on our progress with Phases III and IV, two areas we plan to initiate development of during 2007, and the response from our new Phase II projects.

     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 in excess of 4,994 Bbls/d for the fourth quarter 2006. In contrast to many of our existing fields, West Mallalieu Field was not waterflooded prior to CO₂ injection. Therefore, we believe that the tertiary recovery of oil from West 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 $27.6 million was invested in this field during 2006 to drill, re-enter or recomplete wells in efforts to improve production. During 2007, we plan to expand the Mallalieu production facilities to accommodate the expected production growth. Reservoir modeling indicates the field may be producing in excess of 6,500 Bbls/d by the fourth quarter of 2007.

     From inception through December 31, 2006, we had net positive cash flow (revenue less operating expenses and capital expenditures) from Mallalieu Field of $139.3 million, plus the fields have a PV-10 Value of $457.2 million, using December 31, 2006, NYMEX pricing of $61.05 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 gradually increased since that time, averaging 1,463 Bbls/d in the fourth quarter of 2006. During 2006, we continued the expansion of our operations within McComb Field and further expanded the production facilities. Although we have encountered injection issues during 2006, which limited our CO₂ injections at McComb, by the second quarter of 2007 we expect to have all the necessary equipment installed, which we believe will eliminate the injection issues. In addition, we are injecting CO₂ at the nearby, much smaller, Smithdale Field utilizing the same CO₂ facilities. We started injecting CO₂ at Smithdale in the second quarter of 2005, although our production through December 31, 2006 has generally been less than 100 Bbls/day.

     From inception through December 31, 2006, we had not yet recovered our costs in these fields with net negative cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from these fields of $91.2 million, although the fields have a PV-10 Value of $370.7 million, using December 31, 2006, 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 as additional patterns were developed. Production during the fourth quarter of 2006 increased only slightly from third quarter 2006 rates, as CO₂ injection rates were less than initially planned. Incremental work on CO₂ injection wells was required to improve injection rates and to ensure the CO₂ was entering the proper intervals. Additional injection pumps were installed on certain wells to increase injection rates. Oil production during the fourth quarter of 2006 averaged 1,014 Bbls/d.

Denbury Resources Inc.

     Overall Tertiary Economics to Date. Through December 31, 2006, we spent a total of $665.4 million on tertiary oil fields (including the allocated acquisition costs), and received $472.2 million in net positive cash flow (revenue less operating expenses), or net unrecovered cash flow of $193.2 million, the deficit primarily due to the significant funds expended on acquisitions during 2006. Of our total spending, approximately $273.5 million was spent on fields that had little or no proved reserves at December 31, 2006 (i.e. significant incremental proved reserves are anticipated during 2007 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 $198.7 million as of December 31, 2006, including $54.6 million associated with the Free State CO₂ pipeline. At year-end 2006, the proved oil reserves in our tertiary recovery oil fields had a PV-10 Value of $1.46 billion, using December 31, 2006, NYMEX pricing of $61.05 per barrel. In addition, there is significant probable and potential reserves at several other fields for which tertiary operations are underway or planned.

Texas and the Barnett Shale

     We currently own approximately 74,700 gross acres and 53,800 net acres of leases in the Barnett Shale area in North Central Texas, of which approximately 22,100 gross acres and 19,600 net acres are in the more tested northern areas of Parker and Wise Counties, with the remainder in Erath 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, 2006, we have spent a total of $267.2 million on the Barnett Shale area and have received $90.1 million in net operating income (revenue less operating expenses), or net negative cash flow of $177.1 million. At December 31, 2006, we had approximately 252.4 Bcfe of proved reserves in the Barnett Shale area with a PV-10 Value of approximately $243.5 million, using December 31, 2006, Henry Hub indicative cash pricing of $5.63 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 feet. During 2006, we drilled an additional 46 horizontal wells, increasing our net Barnett Shale production from approximately 18.3 MMcfe/d in the fourth quarter of 2005 to approximately 35.4 MMcfe/d during the fourth quarter of 2006. During 2006, we finalized the acquisition and interpretation of our 3-D seismic data over our entire northern acreage position, 90 to 100 square miles, and initiated a 3-D shoot of the southern acreage. The 3-D seismic data helps us better locate our wells so that we encounter less faulting and underground sink holes, which have been associated with fracture stimulations into zones outside of the Barnett Shale that are typically water bearing. We expect production in this area to grow significantly during 2007 as we plan to drill approximately 35 to 40 horizontal wells, all of which are scheduled for Parker County. Including seismic costs and pipeline infrastructure costs, our planned 2007 capital expenditures in the Barnett Shale area are estimated to make up $122 million of our current $650 million capital budget.

     At this time we are still evaluating the 2006 drilling and completion work in our southern acreage, primarily Erath County. The initial results do not look very encouraging as we drilled five wells, completing three, none of which have been economic. We elected not to complete the last two wells pending a re-analysis of all of our results to date.

East Mississippi Fields Without Proven 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. For years, this has been our area with the highest production and most proved reserves, representing production of approximately 12,808 BOE/d during the fourth quarter of 2006 (35% of our Company total) and proved reserves of 52.7 MMBOE as of December 31, 2006 (30% 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 13,085 BOE/d in 2004, 12,072 BOE/d in 2005 and 12,743 BOE/d during 2006. For 2007, we expect our budget in this region for conventional operations to be around $50 million, about the same as in 2006, representing approximately 8% of our current 2006 exploration and development budget of $650 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 2006 produced an average of 7,444 BOE/d, 2% more than the 2005 average of 7,312 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. There are 11 producing formations in

Denbury Resources Inc.

Heidelberg Field containing 40 individual reservoirs, with the majority of the past and current production coming from the Eutaw, Selma Chalk and Christmas sands at depths of 3,500 to 5,000 feet. When we acquired the property in 1997, production was approximately 2,800 BOE/d.

     The majority of the oil production at Heidelberg is from six waterflood units that produce from the Eutaw formation (at approximately 4,400 feet). Most of our recent development at Heidelberg has been in the Selma Chalk, a natural gas reservoir at around 3,700 feet, 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 Heidelberg to a peak quarterly average of 15.8 MMcf/d in the fourth quarter of 2004, averaging 14.3 MMcf/d during 2006. During 2005 we drilled and completed our first horizontal well in the Selma Chalk. The well was drilled in an area of the field where prior vertical wells typically yielded lower than average production rates. The well was completed in two stages and the results were encouraging. During 2006, we drilled 12 Selma Chalk wells, four of which were horizontal wells, and we plan to drill 13 horizontal wells during 2007.

South Louisiana

     We own interests in the land and marshes of south Louisiana, a region that produces primarily natural gas. Production from this area averaged 39.4 MMcfe/d net to our interest in the fourth quarter of 2006, a slight increase from our 2005 average of 37.0 MMcfe/d. Production was as high as 51.7 MMcfe/d during the second quarter of 2006 following the completion of several new wells drilled in late 2005 and early 2006, but has declined significantly from that peak as a result of the relatively rapid depletion for wells in this area. During 2006, we spent approximately $64.7 million (excluding acquisitions) in this region, approximately 13% of our total exploration and development expenditures, drilling approximately 12 wells, primarily in Cameron, Jefferson Davis, and Terrebonne Parish areas. For 2007, our spending is expected to be approximately $40 million or 6% of our currently planned $650 million exploration and development budget, significantly less than our 2006 expenditures in this area.

     The majority of our onshore Louisiana fields lie in the Houma embayment area of Terrebonne Parish, including Lirette and South Chauvin Fields, and our recent shallow natural gas plays at Bayou Sauveur and Gibson Fields. We drilled four wells in Terrebonne Parish during 2006. In 2007, we plan to drill approximately three exploratory wells in Terrebonne Parish and four development wells.

     In late 2005 we spudded our Gumbo Prospect in Terrebonne Parish, the Westerfelt #2 well, a 19,000+ foot well testing the Rob L sands. We logged the well in January 2006, constructed production facilities and completed the well. The well produced approximately 645 MMcf and 26 MBbls of condensate (gross) during a two month period. In October 2006 the well logged-off and is presently being evaluated for sidetracking to another fault block. Based on the Westerfelt #2 production information and pressures, we believe that the Westerfelt #2 encountered an isolated reservoir area that is not in communication with the large feature it was intended to test. Based upon the results of the Westerfelt #2 and review of the seismic interpretation, we decided to drill an offset, the State Lease 18380 #1 well. We believe that this well should encounter a larger reservoir with greater reserve potential. The completion of drilling operations is expected late in the first quarter or early in the second quarter of 2007. Assuming the well logs are favorable, significant production history will be required to fully evaluate the potential reserves associated with this prospect.

Denbury Resources Inc.

Field Summaries

     Denbury operates in four primary areas: Louisiana, Eastern Mississippi, Western Mississippi and Texas. Our 16 largest fields (listed below) constitute approximately 93% of our total proved reserves on a BOE basis and on a PV-10 Value basis. Within these 16 fields, we own a weighted average 92% 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 five primary field offices located in Houma, Louisiana, Laurel, Mississippi; McComb, Mississippi; Brandon; Mississippi; and Cleburne, Texas.

		Proved Reserves as of December 31, 2006 (1)																				2006 Average Daily Production
																										Natural				Average Net
		Oil				Natural Gas								BOE				PV-10 Value				Oil				Gas				Revenue
		(MBbls)				(MMcf)				MBOEs				% of total				(000's)				(Bbls/d)				(Mcf/d)				Interest
Mississippi — CO2 floods
Brookhaven			18,987				—				18,987				10.9	%		$	353,406				833				—				82.0	%
Mallalieu (East & West)			13,582				—				13,582				7.8	%			457,200				5,210				—				76.6	%
McComb/Olive			12,717				—				12,717				7.3	%			297,449				1,177				—				77.0	%
Eucutta			10,313				—				10,313				5.9	%			186,229				47				—				83.5	%
Little Creek & Lazy Creek			3,696				—				3,696				2.1	%			90,592				2,739				—				83.3	%
Smithdale and other			2,872				—				2,872				1.7	%			71,560				64				—				79.3	%
Total Mississippi — CO2 floods			62,167				—				62,167				35.7	%			1,456,436				10,070				—				79.9	%
Other Mississippi
Heidelberg (East & West)			25,943				51,512				34,528				19.8	%			477,186				5,036				14,330				76.2	%
Tinsley			3,299				90				3,314				1.9	%			60,391				881				10				81.7	%
Eucutta			2,708				—				2,708				1.6	%			35,524				819				40				69.4	%
S. Cypress Creek			1,903				102				1,920				1.1	%			26,041				233				41				83.0	%
Summerland			1,662				—				1,662				0.9	%			20,556				445				—				74.4	%
King Bee			1,458				—				1,458				0.8	%			17,316				269				—				78.9	%
Other Mississippi			5,172				11,694				7,121				4.1	%			118,821				1,887				4,618				33.1	%
Total Other Mississippi			42,145				63,398				52,711				30.2	%			755,835				9,570				19,039				64.9	%
Louisiana
S. Chauvin			436				13,940				2,759				1.6	%			57,189				298				11,744				38.3	%
Thornwell			406				5,876				1,385				0.8	%			33,905				1,068				11,147				37.4	%
Other Louisiana			901				20,076				4,248				2.4	%			75,305				789				11,800				41.0	%
Total Louisiana			1,743				39,892				8,392				4.8	%			166,399				2,155				34,691				39.5	%
Texas
Newark (Barnett Shale)			11,606				182,812				42,075				24.1	%			243,474				106				28,525				75.0	%
Other Texas			179				669				290				0.2	%			1,552				8				—				79.9	%
Total Texas			11,785				183,481				42,365				24.3	%			245,026				114				28,525				75.1	%
Alabama
Citronelle			8,283				—				8,283				4.8	%			67,594				1,026				—				62.7	%
Other Alabama			7				1,978				337				0.2	%			3,165				1				727				30.5	%
Total Alabama			8,290				1,978				8,620				5.0	%			70,759				1,027				727				60.2	%
Other			55				77				67				0.0	%			744				—				93				0.1	%
Company Total			126,185				288,826				174,322				100.0	%		$	2,695,199				22,936				83,075				57.2	%

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 well or 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, 2006:

		Developed								Undeveloped								Total
		Gross				Net				Gross				Net				Gross				Net
Mississippi			107,930				86,143				276,809				54,303				384,739				140,446
Louisiana			56,393				49,126				21,517				15,002				77,910				64,128
Texas			20,256				18,119				56,454				37,487				76,710				55,606
Alabama			34,329				21,919				77,524				18,887				111,853				40,806
Other			5,429				1,503				38,710				9,687				44,139				11,190
Total			224,337				176,810				471,014				135,366				695,351				312,176

     Denbury’s net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 7% in 2007, 8% in 2008 and 4% in 2009.

Productive Wells

     The following table sets forth our gross and net productive oil and natural gas wells at December 31, 2006:

										Producing Natural
		Producing Oil Wells								Gas Wells								Total
		Gross				Net				Gross				Net				Gross				Net
Operated Wells:
Mississippi			492				474.9				176				161.8				668				636.7
Louisiana			30				24.7				47				39.2				77				63.9
Texas			3				3.0				96				94.2				99				97.2
Alabama			158				124.1				35				20.4				193				144.5
Other			—				—				—				—				—				—
Total			683				626.7				354				315.6				1,037				942.3
Non-Operated Wells:
Mississippi			37				3.4				17				3.9				54				7.3
Louisiana			—				—				17				3.7				17				3.7
Texas			—				—				4				0.5				4				0.5
Alabama			—				—				10				1.5				10				1.5
Other			1				—				—				—				1				—
Total			38				3.4				48				9.6				86				13.0
Total Wells:
Mississippi			529				478.3				193				165.7				722				644.0
Louisiana			30				24.7				64				42.9				94				67.6
Texas			3				3.0				100				94.7				103				97.7
Alabama			158				124.1				45				21.9				203				146.0
Other			1				—				—				—				1				—
Total			721				630.1				402				325.2				1,123				955.3

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,
		2006								2005								2004
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells:(1)
Productive(2)			10				8.5				12				7.1				8				5.8
Non-productive(3)			8				6.8				1				0.6				4				2.3
Development Wells:(1)
Productive(2)			90				82.7				81				74.3				68				53.8
Non-productive(3)(4)			—				—				—				—				1				0.6
Total			108				98.0				94				82.0				81				62.5

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, 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%). For the year ended December 31, 2004, two purchasers each accounted for 10% or more of our oil and natural gas revenues: Hunt Crude Oil Supply Co. (21%) and Genesis Energy, L.P. (14%).

Denbury Resources Inc.

     Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the proximity of our gas production to pipelines, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation. Our production is primarily from developed fields close to major pipelines or refineries and established infrastructure. As a result, we have not experienced any difficulty to date in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to market all of our production or obtain favorable prices.

Oil Marketing

     The quality of our crude oil varies by area as well as 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 current 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, 2006, the discount for our oil production from Heidelberg Field averaged $13.31 per Bbl and for our Eastern Mississippi properties as a whole the discount averaged $12.11 per Bbl relative to NYMEX oil prices. For Mallalieu Field, the largest producer during 2006 of our CO₂ properties in Western Mississippi, we averaged a premium of $0.20 per Bbl over NYMEX oil prices, and $0.30 per Bbl over NYMEX prices for our tertiary oil production in Western Mississippi taken as a whole. Our Louisiana properties averaged $13.82 per Bbl below NYMEX prices during 2006, 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, 2006, we averaged $0.77 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 $0.83 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 the regulation of the size of drilling and spacing units 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 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.

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.

Denbury Resources Inc.

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, 2006, 2005 and 2004. 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 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.

     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 in West Mississippi and our Heidelberg waterfloods in East Mississippi account for approximately 82% 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

Denbury Resources Inc.

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 96% of our proved undeveloped natural gas reserves. The remaining undeveloped natural gas reserves are spread over multiple fields. Our current plans for 2006 include drilling 45 to 55 new wells in these two primary natural gas plays.

		December 31,
		2006				2005				2004
ESTIMATED PROVED RESERVES:
Oil (MBbls)			126,185				106,173				101,287
Natural gas (MMcf)			288,826				278,367				168,484
Oil equivalent (MBOE)			174,322				152,568				129,369
PERCENTAGE OF TOTAL MBOE:
Proved producing			48	%			40	%			39	%
Proved non-producing			17	%			16	%			16	%
Proved undeveloped			35	%			44	%			45	%
REPRESENTATIVE OIL AND GAS PRICES:(1)
Oil — NYMEX		$	61.05			$	61.04			$	43.45
Natural gas — Henry Hub			5.63				10.08				6.18
PRESENT VALUES:(2)
Discounted estimated future net cash flow before income taxes (“PV-10 Value”) (thousands)		$	2,695,199			$	3,215,478			$	1,643,289
Standardized measure of discounted estimated future net cash flow after income taxes (thousands)			1,837,341				2,084,449				1,129,196

     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 12, “Supplemental Oil and Natural Gas Disclosures,” to the Consolidated Financial Statements.

Denbury Resources Inc.

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 60% of our 2007 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 and 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 72% of our December 31, 2006 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 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 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.

Denbury Resources Inc.

     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 2006, NYMEX oil prices were high throughout the year, averaging $66.27 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 has 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, averaging $6.33 per Bbl. Our 2006 differential was about the same as 2005, averaging $6.41 per Bbl. 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. During 2004 NYMEX natural gas prices averaged $6.23 per MMBtu, during 2005 NYMEX averaged $8.97 per MMBtu and during 2006, averaged $6.97 per MMBtu.

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 drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. 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.

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

Denbury Resources Inc.

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 2,569 BOE/d net to the acquired interests during the fourth quarter of 2006, and have proved reserves of approximately 13.5 million BOEs. 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;
	•		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.

Denbury Resources Inc.

     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, 2006, two purchasers each accounted for more than 10% of our oil and natural gas revenues and in the aggregate, for 46% 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 affect 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.

     As of December 31, 2006, approximately 35% 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.

Denbury Resources Inc.

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, 2007, we had approximately $150 million outstanding on our bank credit line with approximately $350 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, 2007. 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;
	•		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

Denbury Resources Inc.

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

     No matters were submitted for a vote of security holders during the fourth quarter of 2006.

Denbury Resources Inc.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock Trading Summary

     The following table summarizes the high and low reported sales prices on days in which there were trades of Denbury’s common stock on the New York Stock Exchange (NYSE), for each quarterly period for the last two fiscal years. The sales prices are adjusted to reflect the 2-for-1 stock split on October 31, 2005. On April 25, 2006, we closed the $125 million sale (net to Denbury) of 3,492,595 shares of common stock in a public offering. As of January 31, 2007, the number of record holders of Denbury’s common stock was 821. Management believes, after inquiry, that the number of beneficial owners of Denbury’s common stock is in excess of 10,500. On January 31, 2007, the last reported sales price of Denbury’s Common Stock, as reported on the NYSE, was $27.70 per share.

		2006								2005
		High				Low				High				Low
First Quarter		$	32.65			$	23.57			$	18.32			$	12.37
Second Quarter			36.60				25.91				20.53				14.02
Third Quarter			35.80				26.53				25.71				19.95
Fourth Quarter			30.93				25.95				25.50				19.36

     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 2006.

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, 2006, 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, 2001, and that dividends were reinvested.

Cumulative Total Return on $100 Investment
(December 31, 2001-December 31, 2006)

		December 31,
		2001				2002				2003				2004				2005				2006
Denbury		$	100			$	155			$	190			$	376			$	623			$	760
S&P 500			100				78				100				111				117				135
Dow Jones Exploration and Production			100				102				134				190				314				331

Denbury Resources Inc.

Item 6. Selected Financial Data

(In thousands, unless otherwise noted)		Year Ended December 31,
		2006				2005				2004(1)				2003				2002
Consolidated Statements of Operations Data:
Revenues		$	731,536			$	560,392			$	382,972			$	333,014			$	285,152
Net income			202,457	(2)			166,471				82,448				56,553	(3)			46,795
Net income per common share (4):
Basic			1.74	(2)			1.49				0.75				0.52	(3)			0.44
Diluted			1.64	(2)			1.39				0.72				0.51	(3)			0.43
Weighted average number of common shares outstanding (4):
Basic			116,550				111,743				109,741				107,763				106,487
Diluted			123,774				119,634				114,603				110,928				108,730
Consolidated Statements of Cash Flow Data:
Cash provided by (used by):
Operating activities		$	461,810			$	360,960			$	168,652			$	197,615			$	159,600
Investing activities			(856,627	)			(383,687	)			(93,550	)			(135,878	)			(171,161	)
Financing activities			283,601				154,777				(66,251	)			(61,489	)			12,005
Production (Daily):
Oil (Bbls)			22,936				20,013				19,247				18,894				18,833
Natural gas (Mcf)			83,075				58,696				82,224				94,858				100,443
BOE (6:1)			36,782				29,795				32,951				34,704				35,573
Unit Sales Price (excluding hedges):
Oil (per Bbl)		$	59.87			$	50.30			$	36.46			$	27.47			$	22.36
Natural gas (per Mcf)			7.10				8.48				6.24				5.66				3.31
Unit Sales Price (including hedges):
Oil (per Bbl)		$	59.23			$	50.30			$	27.36			$	24.52			$	22.27
Natural gas (per Mcf)			7.10				7.70				5.57				4.45				3.35
Costs per BOE:
Lease operating expenses		$	12.46			$	9.98			$	7.22			$	7.06			$	5.48
Production taxes and marketing expenses			2.71				2.54				1.55				1.17				0.92
General and administrative			3.20				2.62				1.78				1.20				0.96
Depletion, depreciation, and amortization			11.11				9.09				8.09				7.48				7.26
Proved Reserves:
Oil (MBbls)			126,185				106,173				101,287				91,266				97,203
Natural gas (MMcf)			288,826				278,367				168,484				221,887				200,947
MBOE (6:1)			174,322				152,568				129,369				128,247				130,694
Carbon Dioxide (MMcf) (5)			5,525,948				4,645,702				2,664,633				1,613,840				815,315
Consolidated Balance Sheet Data:
Total assets		$	2,139,837			$	1,505,069			$	992,706			$	982,621			$	895,292
Total long-term liabilities			833,380				617,343				368,128				434,845				432,616
Stockholders’ equity (6)			1,106,059				733,662				541,672				421,202				366,797

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 onshore Louisiana, Alabama, and in the Barnett Shale play near Fort Worth, 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 five primary field offices located in Houma, Louisiana; Laurel, Mississippi; McComb, Mississippi; Brandon, Mississippi; and Cleburne, Texas.

2006 Overview

     Operating results. During 2006, the combination of high commodity prices and record annual production resulted in record annual earnings and cash flow from operations. Production for 2006 averaged 36,782 BOE/d, 23% higher than our average production during 2005, with production increases in every operating area. Commodity prices, on a BOE basis net to us, increased 6% between the fiscal year-end 2005 and 2006. Virtually all expenses increased during 2006, on both an absolute and per BOE basis, as we experienced cost increases in almost every aspect of our business. Overall industry costs continue to increase, the primary reason for higher operating costs and depreciation and depletion rates per BOE in 2006. Operating expenses were also impacted by higher energy costs (electrical and fuel charges) and our continuing emphasis on tertiary operations. General and administrative expenses increased 51% between 2005 and 2006 primarily as a result of the adoption of SFAS No. 123(R) relating to stock compensation and continued growth in personnel and inflation in the industry. Interest expense increased 31% as a result of average debt levels that were 83% higher than in 2005, partially offset by $11.3 million of capitalized interest expense, primarily relating to the unevaluated properties included in our 2006 acquisitions. Our commodity derivative contract mark-to-market adjustments were the only positive trend in expenses during 2006, wherein we recognized a $19.8 million gain in 2006, as compared to a $29.0 million loss in 2005. Our derivative gain was primarily a result of our decision to enter into natural gas swaps in mid December 2006 covering between 80% and 90% of our forecasted 2007 natural gas production, followed by a decline in natural gas prices by year-end.

     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 2006, our proved reserves increased from 152.6 MMBOE as of December 31, 2005 to 174.3 MMBOE as of December 31, 2006, replacing approximately 260% of our 2006 production, over 60% of which was from internal organic growth, with the balance from acquisitions. The most significant reserve additions during 2006 were in the Barnett Shale. We did not recognize many tertiary oil reserve additions during 2006 because of delays in getting projects completed (and the related delays in associated production response) and because of a transition in how proved tertiary oil reserves were being recognized (see “Results of Operations – Depletion, Depreciation and Amortization” for a review of our reserve changes during 2006 and a discussion of our proved tertiary reserves).

     Net income for 2006 was $202.5 million as compared to $166.5 million for 2005 and $82.4 million for 2004. The incremental net income during the 2006 was attributable to most of the factors noted above, principally higher production, partially offset by higher costs. Continued high commodity prices during 2006 also played a significant role in the 2006 results.

     In addition to inflationary costs in our industry, we are experiencing more and more delays in obtaining goods and services. This industry trend has caused us to experience higher costs than originally forecasted and to periodically fall behind schedule with regard to the timing of planned activities. While there are preliminary signs that these trends are slowing as a result of the decline in commodity prices in late 2006, unless commodity prices remain flat or continue to decrease, we believe that we are likely to see a resumption of these trends. These rising costs, both for operating expenses and capital expenditures, and shortages of goods and services, contribute to delays in completing our planned projects and may cause delays and shortfalls in achieving our anticipated production and profitability targets. See “Results of Operations” for a more thorough discussion of our operating results.

     Continued expansion of our tertiary operations. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999, we have gradually increased our emphasis on these types of operations. We particularly like this

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

play because of its risk profile, rate of return and lack of competition in our operating area. Generally, from East Texas to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of CO₂ that we own drive the play. 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.

     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 2006 we increased our proved CO₂ reserve quantities by 19%, from 4.6 Tcf as of December 31, 2005, to approximately 5.5 Tcf as of December 31, 2006 (both of these quantities are on a working interest basis – see “CO₂ Operations – CO₂ Resources” for further information). We are continuing to buy additional oil fields that are tertiary flood candidates (See “2006 Acquisitions” below).

2006 Acquisitions.

     Tinsley and Citronelle Fields. On January 31, 2006, we completed an acquisition of three producing oil properties that are future potential CO₂ tertiary oil flood candidates: Tinsley Field approximately 40 miles northwest of Jackson, Mississippi, Citronelle Field in Southwest Alabama, and the smaller South Cypress Creek Field near the Company’s Eucutta Field in Eastern Mississippi. In 2006 we began our tertiary development work at Tinsley Field, consisting primarily of planning, land and engineering work, with more extensive development and facility construction planned for 2007. The timing of tertiary development at Citronelle Field is uncertain as we will need to build a 60-to-70 mile extension of our Free State pipeline (CO₂ pipeline from Jackson Dome to East Mississippi) before flooding can commence, and South Cypress Creek will probably be flooded following our initial development of our other East Mississippi properties. The adjusted purchase price for these three properties was approximately $250 million. The acquisition was funded with proceeds of the $150 million of senior subordinated notes issued in December 2005 and $100 million of bank financing under the Company’s existing credit facility (repaid in April 2006 with proceeds from our equity offering at that time). During the fourth quarter of 2006, these fields produced an average of 2,569 BOE/d, up slightly from the 2,200 BOE/d at the time of acquisition. As of December 31, 2006, these fields had proved reserves of approximately 13.5 million BOEs. We operate all three fields and own the majority of the working interests.

     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 have achieved $200 million in net operating revenue, as defined. Delhi is also a future potential CO₂ tertiary oil flood candidate that will require construction of a CO₂ pipeline before flooding can commence, with current plans to make such a line an extension of the larger, new CO₂ pipeline currently planned from Jackson Dome to Tinsley Field. Our goal is to have this CO₂ line installed by 2008, with initial oil production from tertiary operations currently anticipated during 2009. No significant oil production or proved oil reserves existed at Delhi Field at December 31, 2006.

     Hastings Field. During November 2006 we entered into an agreement with a subsidiary of Venoco, Inc. that gives us an option, between November 1, 2008 and November 1, 2009, 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 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, we made an upfront payment of $37.5 million and are required to make additional payments totaling $12.5 million over the next twenty months. 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 2,400 Bbls/d, although we currently have no economic interest in this production.

     We believe that Hastings Field has significant potential oil reserves from tertiary flooding. We plan to build a pipeline to transport CO₂ to this field, estimated at between 280 and 300 miles, from the southern end of our existing CO₂ pipeline which terminates near Donaldsonville, Louisiana. Based on very preliminary estimates, this pipeline is expected to cost between $450 million and $650 million, although this cost could vary significantly depending on the ultimate size of the pipeline, its pressure rating, its specific route, and other variables, all of which are unknown

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

at this time. We are initiating studies related to construction of this line, with a goal of having it installed and operational within the next few years. We anticipate initially transporting CO₂ to the Hastings Field from our natural CO₂ source at Jackson Dome, but ultimately plan to use manufactured (anthropogenic) sources of CO₂ for this tertiary operation. See “Results of Operations — CO₂ Resources” for a discussion of an agreement we entered into during 2006 to purchase a man-made source of CO₂ from a planned petroleum coke gasification project.

     April 2006 Equity Offering. On April 25, 2006, we closed the $125 million sale (net to Denbury) of 3,492,595 shares of common stock in a public offering. We used the net proceeds from the offering to repay then current borrowings under our bank credit facility, which were $120 million as of that date, principally incurred to partially fund our $250 million acquisition of three properties in January 2006.

Capital Resources and Liquidity

     Our current 2007 capital budget is $650 million, excluding any potential acquisitions. Approximately 60% of our 2007 budget is expected to be spent on tertiary related operations, approximately 20% in the Barnett Shale area, and less than 10% on exploration projects, with the balance spent on our conventional properties in Mississippi or Louisiana. This capital program includes an estimated $80 million to $100 million for a CO₂ pipeline from our CO₂ source at Jackson Dome to Tinsley and Delhi Fields, two oil fields acquired during 2006. Based on futures commodity prices as of the end of January 2007, this budget is $200 million to $250 million greater than our anticipated cash flow from operations, a much greater shortfall than we have had in recent years. Currently, we plan to fund the majority of this shortfall by refinancing our two existing CO₂ pipelines with Genesis Energy, L.P. (“Genesis”) by entering into some type of long-term financing or sale transaction, effectively paying for the cost of the pipeline over an extended period of time and recouping our cash previously spent. We would anticipate a similar financing with Genesis for the new CO₂ pipeline from Jackson Dome to Tinsley and Delhi Fields once it is completed, forecasted at this time to be during the first half of 2008. We have discussed with Genesis that any such financings are conditioned upon Genesis achieving certain goals, primarily the acquisition of other economic projects that are not related to Denbury, based upon acquisition by Genesis of $1.50 of non-Denbury-related acquisitions for every $1.00 of financings or sales with Denbury. If Genesis is not successful in acquiring properties from third parties or we cannot reach mutually agreeable terms with Genesis to sell them these CO₂ pipeline assets, we would plan to fund the shortfall with conventional debt and could potentially reduce our capital budget later in the year. As of February 16, 2007, we had $150 million of bank debt outstanding on a $500 million borrowing base (see “Revised bank credit agreement” below), leaving us significant incremental borrowing capacity, more than we currently plan or desire to use.

     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 the recent cost inflation in our industry, many of our recent budget increases have related to escalating costs rather than additional projects. In this inflationary environment, we often have to either increase our capital budget or consider the elimination of a portion of our planned projects.

     We also 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 in the fields of existing production and 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.

     Revised bank credit agreement. On September 14, 2006, we entered into a Sixth Amended and Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative agent. The new agreement (i) improved the credit pricing under the agreement, (ii) extended the term of the credit arrangements by two and one-half years to September 14, 2011, (iii) increased the borrowing base from $300 million to $500 million, (iv) increased the maximum facility size from $300 million to $800 million, and (v) made other minor modifications. Under the new agreement, the commitment amount remained at $150 million, an amount increased in December 2006 to $250 million. 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

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

any borrowing request by us in excess of the commitment amount ($250 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 December 31, 2006, we had outstanding $375.0 million (principal amount) of 7.5% subordinated notes, approximately $10.0 million of capital lease commitments, $134.0 million of bank debt, and a working capital deficit of approximately $17.1 million.

Sources and Uses of Capital Resources

     During 2006, we spent $507.3 million on oil and natural gas exploration and development, $63.6 million on CO₂ exploration and development, and approximately $319.0 million on property acquisitions, for total capital expenditures of approximately $889.9 million. Our oil and natural gas exploration and development expenditures included approximately $245.3 million spent on drilling, $31.6 million spent on geological, geophysical and acreage expenditures and $230.4 million incurred on facilities and recompletion costs. We funded our total capital expenditures with $461.8 million of cash flow from operations, $125 million of equity, $134 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. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed below under “Results of Operations-Operating Results”) was $448.4 million for 2006, while cash flow from operations for the same period, the GAAP measure, was $461.8 million.

     During 2005, we spent $292.8 million on oil and natural gas exploration and development expenditures, $76.8 million on CO₂ exploration and development expenditures (including approximately $46.0 million for our CO₂ pipeline to East Mississippi), and approximately $70.9 million on property acquisitions, for total capital expenditures of approximately $440.5 million. Our exploration and development expenditures included approximately $147.8 million spent on drilling, $25.5 million of geological, geophysical and acreage expenditures and $135.1 million spent on facilities and recompletion costs. Our 2005 acquisition expenditures include the purchase of additional interest and acreage in the Barnett Shale area and purchase of two oil fields, Cranfield and Lake St. John Fields, which may be potential tertiary flood candidates in the future. Our $440.5 million of capital expenditures included an increase of $18.2 million in our accrued capital expenditures, with the remaining cash portion of our capital expenditures funded primarily with $361.0 million of cash flow from operations and approximately $57 million of short-term investments remaining at December 31, 2004, from the sale of our offshore properties during 2004. Additionally, we issued $150 million of subordinated debt in December 2005 and raised $14.4 million during 2005 from the sale of another volumetric production payment of CO₂ to Genesis, along with a related long-term CO₂ supply agreement with an industrial customer. All of these sources not only funded our capital expenditures, but also increased our cash balance at year-end 2005 to $165.1 million, with a portion of such funds used in January 2006 to partially fund our $250 million acquisition. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed below under “Results of Operations – Operating Results” below) was $343.4 million for 2005, while cash flow from operations for the same period, the GAAP measure, was $361.0 million.

     During 2004, we spent $167.0 million on oil and natural gas exploration and development expenditures, $42.4 million on CO₂ exploration and development expenditures, and approximately $18.9 million on property acquisitions, for total capital expenditures of approximately $228.3 million. Our exploration and development expenditures included approximately $138.9 million spent on drilling, $18.9 million of geological, geophysical and acreage expenditures and $51.6 million spent on facilities and recompletion costs. We funded these expenditures with $168.7 million of cash flow from operations, with the balance funded with net proceeds from the sale of our offshore properties. We paid back all of our bank debt during the third quarter of 2004 with the offshore sale proceeds, leaving us with approximately $33.0 million of cash and $57.2 million of short-term investments as of December 31, 2004. We also raised $4.8 million during the third quarter of 2004 from the sale of another volumetric production payment of CO₂ to Genesis, along with a related long-term CO₂ supply agreement with an industrial customer. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed below under “Results of Operations-Operating Results”) was $200.2 million for 2004, while cash flow from operations, the GAAP measure, was $168.7 million.

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

Off-Balance Sheet Arrangements

Commitments and Obligations

     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 2006 totaled $101.4 million (including $71.4 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, 2006, 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 $8.0 million in debt and $4.6 million in letters of credit at December 31, 2006. 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, 2006. We do not have any material transactions with related parties other than sales of production, transportation arrangements, and 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.

     A summary of our obligations at December 31, 2006, is presented in the following table:

		Payments Due by Period
Amounts in Thousands		Total				2007				2008				2009				2010				2011				Thereafter
Contractual Obligations:
Subordinated debt (a)		$	375,000			$	—			$	—			$	—			$	—			$	—			$	375,000
Senior Bank Loan (a)			134,000				—				—				—				—				134,000				—
Estimated interest payments on subordinated debt and Senior Bank Loan (a)			246,164				36,634				36,634				36,634				36,634				34,116				65,512
Operating lease obligations			101,378				13,056				12,667				11,857				11,527				10,967				41,304
Capital lease obligations (b)			10,028				1,291				1,291				1,529				1,291				1,291				3,335
Capital expenditure obligations (c)			102,660				66,386				20,284				14,235				1,755				—				—
Derivative contracts (receipt) payment (d)			(14,726	)			(22,125	)			7,399				—				—				—				—
Hastings field purchase option			12,500				7,500				5,000				—				—				—				—
Other Cash Commitments:
Future development costs on proved oil and gas reserves, net of capital obligations (e)			463,707				180,000				141,523				85,490				19,367				9,442				27,885
Future development cost on proved CO2 reserves, net of capital obligations (f)			149,367				31,267				20,000				—				—				11,000				87,100
Asset retirement obligations (g)			91,338				1,940				1,130				2,428				5,351				1,509				78,980
Total		$	1,671,416			$	315,949			$	245,928			$	152,173			$	75,925			$	202,325			$	679,116

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

     The above table does not include the commitment to purchase CO₂ from the proposed Faustina plant, if built (see “Results of Operations — CO₂ Resources — Man-made CO₂ sources” below) and does not include the commitments related to Hastings Field if the purchase option is exercised by us (see “2006 Acquisitions” above), as both obligations are contingent on certain events. The above table does include the remaining $12.5 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 391 Bcf of CO₂ to these customers over the next 17 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, currently we project that our commitment would likely be reduced to approximately 255 Bcf. The maximum volume required in any given year is approximately 105 MMcf/d, although based on our current level of deliveries, this would likely be reduced to approximately 69 MMcf/d. Given the size of our proven CO₂ reserves at December 31, 2006 (approximately 5.5 Tcf before deducting approximately 210.5 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. Our interest in tertiary operations has increased to the point that approximately 60% of our 2007 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 carbon dioxide 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 CO₂ pipeline that we acquired in 2001. The

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

most significant fields in this area are Little Creek, Mallalieu, McComb and Brookhaven. Phase II, which began with the early 2006 completion of our CO₂ pipeline to East Mississippi, includes Eucutta, Soso, Martinville and Heidelberg Fields. With the properties acquired in our January 2006 acquisition (see “2006 Acquisitions” above), we have labeled the planned operations at Tinsley Field, Northwest of Jackson Dome, as Phase III. 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 (see “2006 Acquisitions”). Ultimately, we also plan to ultimately flood Citronelle Field, another field acquired in 2006, and Hastings Field, a field on which we acquired a purchase option in late 2006. We have not yet labeled these two fields as a specific phase.

     CO₂ Resources. In February 2001, we acquired the CO₂ source field located near Jackson, Mississippi, and a 183-mile pipeline to transport it to our oil fields. Since February 2001, we have acquired two producing wells and drilled 11 additional CO₂ producing wells, significantly increasing our estimated proved CO₂ reserves from approximately 800 Bcf at the time of the 2001 acquisition to approximately 5.5 Tcf as of December 31, 2006, approximately 250 Bcf more than we estimate we need for our existing and currently planned phases of tertiary operations. During 2006, our proven CO₂ reserves increased approximately 19%, or 900 Bcf, from 4.6 Tcf to 5.5 Tcf. The estimate of 5.5 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 & 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 both for Denbury’s tertiary recovery programs 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 850 Bcf of CO₂ to develop and produce the proved tertiary recovery reserves we have recorded at December 31, 2006.

     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 January 2007, we estimate that we are capable of producing approximately 470 MMcf/d of CO₂, over seven times the rate that we were capable of producing at the time of our initial acquisition in 2001. We continue to drill additional CO₂ wells, with three more wells planned for 2007, in order to further increase our production capacity and potentially increase our proven CO₂ reserves. Our drilling activity at Jackson Dome will continue beyond 2007 as our current forecasts for the five phases which are specifically planned to date suggest that we will need approximately 1,000 MMcf/d of CO₂ production by 2011.

     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 2004, 2005 and 2006 was approximately 218 million, 242 million, and 342 million cubic feet per day, of which approximately 73% in 2004, 73% in 2005, and 75% in 2006 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 $0.19 per Mcf in operating expenses to produce our CO₂ during 2006, more than our 2005 average of $0.16 per Mcf, principally as a result of higher oil commodity prices, which results in higher royalty payments, and higher labor, utilities and equipment rental expense. During 2004, we spent approximately $0.12 per Mcf to produce our CO_2. Our estimated total cost per thousand cubic feet of CO₂ during 2006 was approximately $0.28, after inclusion of depreciation and amortization expense related to the CO₂ production, as compared to approximately $0.25 during 2005.

     Man-Made CO₂ sources. We entered into an agreement and committed to purchase (if the plant is built) 100% of the CO₂ production from a man-made (anthropogenic) source of CO₂, a planned petroleum coke gasification project scheduled to be completed in 2010. This Faustina plant, proposed to be located near Donaldsonville, LA, will convert petroleum coke into ammonia. As a byproduct of the combustion, large quantities of CO₂ will be produced, estimated to be around 200 MMcf/d. We plan to use this CO₂ in our tertiary operations program to recover oil. The Faustina agreement allows us to add the potential equivalent volume of an additional one Tcf of CO₂ over the term of our contract. Construction of this plant has not yet begun, so we are not certain whether this plant will be built, although it currently appears likely. We are in discussions with several other entities that are considering other types of coal or petroleum coke gasification plants. The cost of this man-made CO₂ will

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

likely be higher than CO₂ from our natural source, but the location of these plants could mitigate some of the incremental cost of transporting CO₂ from Jackson Dome. Further, we see these sources as a possible expansion of natural sources, 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 in acquiring these future potential man-made sources of CO_2.

     Overview of Tertiary Economics. Initially, our tertiary operations were 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, 2006, are approximately $8.50 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 $13 to $15 per BOE over the life of each field (at today’s prices), again depending on the field itself, however, our 2006 operating costs were in excess of this range.

     Oil quality is another significant factor that impacts the economics. In Phase I (Southwest Mississippi), the light sweet oil produced from our tertiary operations receives near NYMEX prices, while the average discount to NYMEX for the lower quality oil produced from the fields in Phase II (East Mississippi), some of which we started flooding during 2006, was $13.51 per BOE during 2006, a differential that is significantly higher than our corporate historical averages and one that appears to increase as oil prices increase. See “Oil and Natural Gas Revenues” below for a further discussion of our NYMEX differentials.

     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 on our financial results and certain operating statistics.

     First, there is a significant delay between the initial capital expenditures and operating expenses 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) to the injection of CO₂. Further, we may spend significant amounts of capital before we can recognize any proven reserves from fields we flood (See “Analysis of Tertiary Recovery Operations” below). Even after a field has proven reserves, there will usually be significant amounts of additional capital required to fully develop the field.

     Secondly, 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. Our operating cost during 2006 for our tertiary operations averaged $17.69 per Bbl for our producing tertiary fields, as compared to an estimated cost of around $12 to $15 per BOE for a more traditional oil property. We allocate the cost to produce and transport the CO₂ between CO₂ used in our own oil fields and CO₂ sold to commercial users (including obligations covered by the volumetric production payments sold to Genesis). 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 before oil production is realized in a particular field. 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).

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

     Third, our net oil price relative to NYMEX prices may be affected by the oil produced from our tertiary operations (see “Overview of Tertiary Operations” above). Currently, all of our current oil production from tertiary operations is from fields that produce light sweet oil and receive oil prices close to, and sometimes actually higher than, NYMEX prices. However, the oil produced from fields that we recently commenced flooding as part of Phase II generally sell at a significant discount to NYMEX because of the quality of the crude oil there. The relative mix of this production, coupled with changing market conditions for the various types of crude, can cause our NYMEX differentials to fluctuate widely.

     Analysis of CO₂ Tertiary Recovery Operating Activities. We currently have tertiary operations ongoing at Little Creek, Mallalieu, McComb and Brookhaven Fields in Phase I and Soso, Martinville and Eucutta Fields in Phase II, as well as in various smaller adjacent fields. We project that our oil production from these 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, 2006, we had approximately 62.2 MMBbls of proven oil reserves related to tertiary operations (51.7 MMBbls of which was 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 initiated CO₂ injections at Tinsley Field (Phase III) in January 2007, although in very limited amounts, with more significant development expected there when the CO₂ pipeline to Tinsley is completed, which we currently anticipate in the third or fourth quarter of 2007. We also expect to initiate flooding at Cranfield and Lockhart Crossing Fields in the second half of 2007 (Phase IV).

     With regard to our proven tertiary reserves, 2006 was a transition year for us, as we added only 6.0 MMBbls of tertiary-related proved oil reserves during the year, primarily incremental oil reserves at McComb and Mallalieu Fields (both Phase I). Previously, we booked most 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. Since many of our Phase II projects were delayed during 2006, the production response needed to record any significant incremental tertiary oil reserves in this new area did not take place. We anticipate booking significant amounts of proven tertiary oil reserves during 2007 and beyond, although the magnitude will depend on our progress with Phases III and IV, two areas we plan to initiate during 2007, and the response from our new Phase II projects.

     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 10,070 Bbls/d during 2006. Tertiary oil production represented approximately 44% of our total corporate oil production during 2006 and approximately 27% 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. During 2006, our CO₂ injections were less than we forecasted due to a series of different types of delays in obtaining equipment or completing facilities, resulting in a corresponding shortfall between our forecasted and actual tertiary oil production. These delays are caused by various factors: difficulties reentering certain injection wells, which has required that some wells be redrilled; delays in getting certain permits and right-of-ways; and a general tightening of available materials and equipment in the industry. This temporary fluctuation in oil production does not indicate any issue with the proved and potential oil reserves recoverable with CO₂, because the historical correlation between oil production and CO₂ injections remains high. For our tertiary oil production, we anticipate a 40% to 50% increase in our average production rates for 2007 as compared to 2006 levels. A detailed discussion of each of our tertiary oil fields and the development of each is included on pages 7 – 9 under “Our Tertiary Oil Fields with Proven Tertiary Reserves.” Following is a chart with our tertiary oil production by field for 2004, 2005 and by quarter for 2006.

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

		Average Daily Production (BOE/d)
		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter					Year Ended December 31,
Tertiary Oil Field		2006				2006				2006				2006					2006				2005				2004
Brookhaven			547				798				965				1,014					833				31				—
Little Creek & Lazy Creek			3,006				3,056				2,623				2,279					2,739				3,529				3,148
Mallalieu (East and West)			5,219				5,385				5,243				4,994					5,210				4,739				3,351
McComb & Olive			932				1,062				1,242				1,467					1,177				908				285
Smithdale			54				74				41				63					58				8				—
Martinville			—				—				—				24					6				—				—
Eucutta			—				—				—				187					47				—				—
Total tertiary oil production			9,758				10,375				10,114				10,028					10,070				9,215				6,784

     In addition to higher energy costs to operate our tertiary recycling facilities caused by higher commodity prices, we have experienced general cost inflation during the last few years. We also lease a portion of our recycling and plant equipment used in our tertiary operations, which further increases operating expenses. Over the last four years we have leased certain equipment that qualifies for operating lease treatment representing an underlying aggregate cost of approximately $71.4 million as of December 31, 2006. We expect to enter into new leases for equipment during 2007 and 2008 representing additional underlying costs of approximately $44 million. These leases have been an attractive cost of financing due to their low imputed interest rates, which are fixed for seven to ten years. During 2006, the cost to produce our CO₂ also increased (see “CO₂ Resources” above), all of which resulted in an increase in our tertiary operating cost per BOE from $12.00 per BOE in 2005 to $17.69 per BOE during 2006. Included in the 2006 amount is approximately $7.5 million, or approximately $2.04 per BOE, for operating expenses at three new tertiary floods in Phase II where we commenced operations but have had only a very limited or no production response to date (initial response is expected late in 2007). The absolute amount of operating expenses related to tertiary operations increased from $24.6 million during 2004 to $40.4 million during 2005 to $65.0 million during 2006.

     Through December 31, 2006, we spent a total of $665.4 million on fields currently being flooded (including allocated acquisition costs) and received $472.2 million in net cash flow (revenue less operating expenses and capital expenditures). Of this total, approximately $273.5 million was spent on fields which had little or no proved reserves at December 31, 2006 (i.e., significant incremental proved reserves are anticipated during 2007 and beyond). The proved oil reserves in our CO₂ fields have a PV-10 Value of $1.46 billion, using December 31, 2006 constant NYMEX pricing of $61.05 per Bbl. These amounts do not include the capital costs or related depreciation and amortization of our CO₂ producing properties, but do include CO₂ source field lease operating costs and transportation costs. Through December 31, 2006, we had a balance of approximately $198.7 million of unrecovered net cash flows for our CO₂ assets.

     CO₂ Related Capital Budget for 2007. Tentatively, we plan to spend approximately $70 million in 2007 in the Jackson Dome area with the intent to add additional CO₂ reserves and deliverability for future operations. Approximately $60 million in capital expenditures is budgeted in 2007 for our Phase II properties (East Mississippi) and approximately $200 million for Phase III properties (Tinsley), plus an additional $70 million for properties in other phases, making our combined CO₂ related expenditures just over 60% of our $650 million 2007 capital budget.

Operating Results

     Adjusted cash flow from operations (see discussion below regarding this non-GAAP measure) and net income have increased each year during the last three years, along with rising commodity prices. Production declined 10% from 2004 to 2005, primarily related to the sale of our offshore properties in July 2004 and to a lesser extent due to the hurricanes during 2005, but the effect of this deferred production was more than offset by higher commodity prices in 2005. Production increased 23% between 2005 and 2006, which, coupled with high prices, resulted in record annual net income and cash flow. Included in our 2006 net income is the effect of approximately $7.5 million of non-cash charges related to the adoption of SFAS No. 123(R) as of January 1, 2006, relating to certain stock-based compensation that was previously only reflected as a footnote disclosure and not recorded in the financial statements (See Note 9 to the Consolidated Financial Statements) and approximately $6.0 million of other

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

non-cash stock charges associated with the departure of a senior vice president and retirement of another vice president, both during 2006.

		Year Ended December 31,
Amounts in Thousands Except Per Share Amounts		2006				2005				2004
Net income		$	202,457			$	166,471			$	82,448
Net income per common share:
Basic		$	1.74			$	1.49			$	0.75
Diluted			1.64				1.39				0.72
Adjusted cash flow from operations		$	448,414			$	343,383			$	200,193
Net change in assets and liabilities relating to operations			13,396				17,577				(31,541	)
Cash flow from operations (GAAP measure)		$	461,810			$	360,960			$	168,652

     Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by operations before changes in assets and liabilities, as calculated from our Consolidated Statements of Cash Flows. Cash flow from operations is the GAAP measure as presented in our Consolidated Statements of Cash Flows. In our discussion herein, we have elected to discuss these two components of cash flow provided by operations.

     Adjusted cash flow from operations, the non-GAAP measure, measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe that it is important to consider adjusted cash flow from operations separately, as we believe it can often be a better way to discuss changes in operating trends in our business caused by changes in production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during that year. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices or significant changes in drilling activity.

     The net change in assets and liabilities relating to operations is also important as it does require or provide additional cash for use in our business; however, we prefer to discuss its effect separately. For instance, during 2004, we had a $31.5 million difference between our adjusted cash flow from operations and our GAAP cash flow from operations. The most significant factor was the transfer of approximately $12.5 million of accrued production receivables relating to our offshore properties that existed as of the closing date to the offshore property purchaser. This reduction in accrued production receivables during 2004 was not considered a collection of receivables for our GAAP cash flow from operations. In addition to the effect of transferred receivables, our other accrued production receivables increased during the year due to the increase in commodity prices, and we reduced our accounts payable and accrued liabilities by approximately $10.5 million as a result of less overall activity as of year-end. During 2005, we had a $17.6 million increase to our GAAP cash flow from operations resulting from the net change in assets and liabilities relating to operations. This is primarily due to higher accounts payable and accrued liabilities associated with increased capital spending levels as compared to the prior year. Our accrual for production receivables was higher at the end of 2006 than a year earlier, due to higher oil and natural gas prices, partially offsetting the benefit of higher accounts payable and accrued liabilities. During 2006, we also had a $13.4 million increase to our GAAP cash flow from operations resulting from the same items as in 2005; namely higher accounts payable and accrued liabilities due to the higher spending levels, partially offset by an increase in our accrued production receivable as a result of the higher production levels in 2006.

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

     Certain of our operating statistics for each of the last three years are set forth in the following chart:

		Year Ended December 31,
		2006				2005				2004
AVERAGE DAILY PRODUCTION VOLUMES
Bbls/d			22,936				20,013				19,247
Mcf/d			83,075				58,696				82,224
BOE/d (1)			36,782				29,795				32,951
OPERATING REVENUES (in thousands)
Oil sales		$	501,176			$	367,414			$	256,843
Natural gas sales			215,381				181,641				187,934
Total oil and natural gas sales		$	716,557			$	549,055			$	444,777
OIL AND GAS DERIVATIVE CONTRACTS (in thousands) (2)
Cash expense on settlements of derivative contracts		$	(5,302	)		$	(16,761	)		$	(84,557	)
Non-cash derivative (expense) income			25,130				(12,201	)			(1,270	)
Total income (expense) from oil and gas derivative contracts		$	19,828			$	(28,962	)		$	(85,827	)
OPERATING EXPENSES (in thousands)
Lease operating expenses		$	167,271			$	108,550			$	87,107
Production taxes and marketing expenses (3)			36,351				27,582				18,737
Total production expenses		$	203,622			$	136,132			$	105,844
NON-TERTIARY CO2 OPERATING MARGIN (in thousands)
CO2 sales and transportation fees (4)		$	9,376			$	8,119			$	6,276
CO2 operating expenses			3,190				2,251				1,338
Non-tertiary CO2 operating margin		$	6,186			$	5,868			$	4,938
UNIT PRICES-INCLUDING IMPACT OF DERIVATIVE SETTLEMENTS (2)
Oil price per Bbl		$	59.23			$	50.30			$	27.36
Gas price per Mcf			7.10				7.70				5.57
UNIT PRICES-EXCLUDING IMPACT OF DERIVATIVE SETTLEMENTS (2)
Oil price per Bbl		$	59.87			$	50.30			$	36.46
Gas price per Mcf			7.10				8.48				6.24
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1)
Oil and natural gas revenues		$	53.37			$	50.49			$	36.88
Oil and gas lease operating expenses		$	12.46			$	9.98			$	7.22
Oil and gas production taxes and marketing expenses			2.71				2.54				1.55
Total oil and natural gas production expenses		$	15.17			$	12.52			$	8.77