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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2005 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, 2005


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.

(Exact name of Registrant as specified in its charter)


Delaware		20-0467835
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

5100 Tennyson Parkway,
Suite 3000, 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. þ

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 $2,158,311,895.

The number of shares outstanding of the registrant’s Common Stock as of February 28, 2006, was 115,339,261.

DOCUMENTS INCORPORATED BY REFERENCE


Document:		Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Shareholders to be held May 10, 2006.		1. Part III, Items 10, 11, 12, 13, 14

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 Farenheit.

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.


*		This definition is an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X. See www.sec.gov/divisions/corpfin/forms/regsx.htm#gas for the complete definition.

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 3000, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2005, we had 460 employees, 293 of whom were employed in field operations or at the field offices. Our employee count does not include the approximately 185 employees of Genesis Energy, Inc. as of December 31, 2005, 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;

Denbury Resources Inc.

	•		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.

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 CO₂Assets

Just over six years ago, we started a new focus area through an acquisition of a carbon dioxide (CO₂) tertiary flood in an area very familiar to us, Mississippi. We have subsequently acquired other related assets and are making CO₂flooding the largest part of our business. We particularly like this tertiary play as (i) it is lower risk and more predictable than most traditional exploration and development activities, (ii) it provides a reasonable rate of return at relatively low oil prices (generally in the twenties), and (iii) we have virtually no competition for this type of activity in our current geographic area. Generally, from East Texas to Florida, there are no known natural sources of carbon dioxide except our own, and these large volumes of CO₂ that we own drive the play. Our CO₂reserves originated from an old underground volcano located near Jackson, Mississippi, discovered in the 1960s while companies were drilling for oil and natural gas. These CO₂ reserves are found in structural traps in the Haynesville, Buckner, Smackover and Norphlet formations at depths from 15,000 to 16,000 feet.

CO₂ injection is one of the most efficient tertiary recovery mechanisms for producing crude oil; however, because it requires large quantities of CO₂, its use has been restricted to West Texas, Mississippi and other isolated areas where large quantities of CO₂ are available. The CO₂ (in liquid form) acts as a type of solvent for the oil, causing the oil to expand and become mobile, allowing the oil to be recovered along with the CO₂ as it is produced. The CO₂ is then extracted from the oil, compressed back into a liquid state, and re-injected into the reservoir, with this recycling process occurring several times during the life of the tertiary operation. In a typical oil field up to 50% of the oil in place can be extracted during primary and secondary (waterflooding) recovery operations. Through the use of CO₂ in tertiary operations, it is possible to recover additional oil (for example, 17.5% based on historical results at Little Creek Field), almost as much oil as initially recovered during the primary production phase.

We began our CO₂ operations in August 1999, when we acquired our first CO₂ tertiary recovery project, Little Creek Field in Mississippi, a project originally developed by Shell Oil Company. Following our success at Little Creek (see “Little Creek Field” below), we embarked upon a strategic program to build a dominant position in this niche play. Following are highlights of our activities over the last few years:

•

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 wells and drilled nine additional CO₂producing wells, significantly increasing the estimated proved CO₂ reserves to approximately 4.6 Tcf as of December 31, 2005, which is more than enough for our existing and currently planned phases of operations. The estimate of 4.6 Tcf of proved CO₂ reserves is based on 100% ownership of the CO₂ reserves, of which Denbury’s net ownership (net revenue interest) is approximately 3.8 Tcf and is 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

Denbury Resources Inc.

			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 CO₂well in the region. Although our current proven and potential CO₂reserves 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 CO₂wells in the future, including up to three additional wells during 2006.

	•		During 2001 and 2002, we acquired several Mississippi oil fields in our CO₂ operating area, including Mallalieu, McComb and Brookhaven Fields (our Phase I area). Typical of mature properties in this area, the acquisition costs of these fields were relatively low in comparison to their significant reserve potential as tertiary recovery projects. As an example, we acquired West Mallalieu Field in May 2001 for $4.0 million, and by year-end 2001 had recognized 10.4 MMBOE of proved reserves, with additional future reserve potential in this field. At December 31, 2005, we had 43.2 MMBOE of proved reserves at these three fields.

	•		During the fourth quarter of 2005, we sold an average of 74.2 MMcf/d of CO₂ to commercial users and we used an average of 192.4 MMcf/d for our tertiary activities. We estimate that our current daily CO₂ deliverability is approximately 450 MMcf/d, and by year-end 2006 we hope to further increase our CO₂ deliverability to between 550 MMcf/d and 600 MMcf/d. We plan to continue our CO₂ drilling in 2006 and beyond, as we estimate that we will need up to 800 MMcf/d in the next five to six years in order to meet the projected timetable for our existing and currently planned tertiary projects.

	•		During 2004, we made the strategic decision to commence the construction of our Free State CO₂ pipeline, which runs from our CO₂ source near Jackson, Mississippi, to several of our East Mississippi properties. This pipeline is essentially complete and we expect to commence CO₂operations in three East Mississippi fields late in the first quarter or early in the second quarter of 2006. We believe that this expansion into East Mississippi, which we call Phase II, has significant oil potential. Combined with our forecast for Phase I in Southwest Mississippi, we anticipate having significant oil production growth from our tertiary operations for several years.

	•		We have assigned most of our industrial contracts to Genesis during the last two years in conjunction with the sale of volumetric production payments of CO₂ to Genesis. Pursuant to the terms of the volumetric production payments, Genesis has specific maximums on the amount of CO₂they are allowed to take each year, which generally relate to the anticipated volumes of the industrial customers. We provide Genesis with certain processing and transportation services in connection with these agreements for a fee of approximately $0.17 per Mcf of CO₂delivered to their industrial customers during 2005.

	•		In January 2006 we closed on the purchase of three oil fields for $248 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 (our planned Phase III); Citronelle Field in Southwest Alabama, and the smaller South Cypress Creek Field near the Company’s Eucutta Field in Eastern Mississippi (see “Recently Acquired Fields” below).

	•		During 2005 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 20” CO₂ pipeline in Southwest Mississippi and will allow us to transport CO₂ to Lake St. John and Cranfield Fields, both acquired in 2005 (our planned Phase IV). These fields have historically produced from the same reservoir, the Lower Tuscaloosa, as do our existing CO₂ floods in Southwest Mississippi. We are currently performing simulation studies on these fields to determine the optimum CO₂ flood to use at each field because both of these fields contain a natural gas cap, which is a different geological feature than in our other Southwest Mississippi fields. The acquisition is subject to regulatory approval, which could take up to six months.

Denbury Resources Inc.

Most of our tertiary operations are economic with oil prices in the twenties, although the precise break-even point varies by field. Our costs have escalated during the last few years and this trend is expected to continue. Our inception to date, all-in finding and development costs (including future development and abandonment costs) for our tertiary fields through December 31, 2005 was approximately $7.50 per BOE. Currently, we forecast that these costs will range from $3 to $11 per BOE, depending on the state of the field, the amount of potential oil, the proximity to a pipeline or other facilities, etc. Our operating costs averaged $12.00 per BOE in 2005 and are expected to range from $10 to $15 per BOE over the life of each field. Oil quality is another significant factor that impacts our economics. In West Mississippi, the light sweet oil produced from our tertiary operations receives near NYMEX prices, while the average discount to NYMEX for our production from oil fields in East Mississippi that we plan to flood in the near future was $9.39 per BOE during 2005, a differential that is significantly higher than historical averages, but one that appears to increase as oil prices increase. While these economic factors have wide ranges, our rate of return from these operations has been better than for our 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 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.

Currently, we plan to spend approximately $45 million in 2006 in the Jackson Dome area, drilling three wells and building additional pipelines and facilities, with which we hope to add both additional CO₂ reserves and higher deliverability for future operations. Approximately $105 million in capital expenditures is budgeted in 2006 for our oil fields with tertiary operations in Southwest Mississippi and approximately $55 million for oil fields in East Mississippi, making our planned combined CO₂ and tertiary recovery related expenditures approximately 50% of our current 2006 capital budget, similar to the 53% of 2005’s capital spending on these projects, including our $50 million Free State CO₂ pipeline to East Mississippi.

Our Tertiary Oil Fields with Proven Tertiary Reserves

At December 31, 2005, we had total tertiary-related proved oil reserves of approximately 59.8 MMBbls, consisting of 5.1 MMBbls at Little Creek (and surrounding smaller fields), 13.2 MMBbls at Mallalieu, 10.3 MMBbls at McComb, 19.3 MMBbls at Brookhaven, 2.9 MMBbls at Smithdale and 9.1 MMBbls at Eucutta Field. During 2006, we plan to commence tertiary operations at Eucutta, Soso and Martinville Fields, and do some preparatory work at Tinsley and Cranfield. Overall, our production from tertiary operations has increased from approximately 1,350 Bbls/d in 1999, the then existing production at Little Creek Field at the time of acquisition, to an average of 9,939 BBls/d during the fourth quarter of 2005. We expect this production to continue to increase for several years as we expand our tertiary operations to additional fields.

Little Creek Field. Little Creek Field was discovered in 1958, and by 1962 the field had been unitized and waterflooding had commenced. The pilot phase of CO₂flooding began in 1974 and the first two phases (each in a distinct area of the field) began in 1985. When we acquired the field in 1999, the first two phases were complete and the third phase was in process. We have completed development of the third, fourth and fifth phases and most of the currently planned development work at this field, although we will continue to modify existing patterns and drill wells as necessary to recover the maximum amount of oil or to extend the field into areas that have not benefited from CO₂injection. Based on the results of the two earliest phases of CO₂flooding at Little Creek, tertiary recovery has increased the ultimate recovery factor in the flooded portion of the field by approximately 17.5%, as compared to recoveries of approximately 20% for primary recovery and 18% for secondary recovery. The field has produced a cumulative 16.2 MMBbls (gross) of light sweet crude as a result of tertiary operations, and we currently estimate that an additional 6.1 MMBbls (gross) can be recovered.

Production from Little Creek Field was approximately 1,350 Bbls/d when we acquired the field in 1999. During the fourth quarter of 2005, production had increased to an average of 3,210 BOE/d (including Lazy Creek). Production at Little Creek Field has most likely reached its peak and will decline over the next several years. From inception through December 31, 2005, we had net positive cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Little Creek (including adjoining smaller fields) of $90.4 million (at the field level), plus the fields have a PV-10 Value of $156.4 million, using a December 31, 2005, NYMEX oil price of $61.04 per Bbl and a Henry Hub indicative cash price of $10.08 per MMBtu.

Denbury Resources Inc.

Mallalieu Field. We purchased West Mallalieu Field in May 2001. Shell Oil Company unitized West Mallalieu Field and commenced a pilot project in 1986 that produced approximately 2.1 MMBbls of oil as a result of CO₂flooding. We have expanded the pilot project by adding two to four patterns each year since 2001 and began to see our initial response approximately four months after initial injections in late 2002. We expanded our operations in this area to East Mallalieu in 2004 and 2005, with our first production response from East Mallalieu in early 2005. Production has continued to increase at these fields, from almost nothing at the time of acquisition to an average of 5,562 BBls/d in the fourth quarter of 2005. In contrast to Little Creek Field, 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 exceed the 17% of original oil in place that we expect from Little Creek Field. From inception through December 31, 2005, we had net positive cash flow (revenue less operating expenses and capital expenditures) from Mallalieu Field of $64.0 million (at the field level), plus the fields have a PV-10 Value of $452.3 million, using December 31, 2005, NYMEX pricing.

McComb and Smithdale Fields. We purchased McComb Field in 2002 for $2.3 million, a field with no pilot programs or tertiary operations at that time and virtually no current oil production. McComb is very close in proximity and analogous to Little Creek and Mallalieu Fields. We commenced tertiary recovery operations in 2003 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 patterns. The first production response occurred in the second quarter of 2004 and has gradually increased since that time, averaging 1,011 Bbls/d in the fourth quarter of 2005. During 2006, we expect to add six patterns within McComb Field and further expand the production facilities. In addition, we also started our initial work on an additional CO₂flood at nearby Smithdale Field during 2004 utilizing the same CO₂ facilities. We started injecting CO₂at Smithdale in the second quarter of 2005 and had our first production response in the fourth quarter, although the average was only 31 Bbls/d.

Brookhaven Field. Initial development of the Brookhaven Field, a field acquired from COHO Resources during 2002, began in late 2004 with the first injections of CO₂ in early 2005. During 2005, we completed development of the two patterns initiated in 2004 and developed an additional four patterns. Even though our CO₂ injections have been less than we initially planned, as we determined that some incremental work was required on the fields and the facilities and it took longer than expected, we had our first production response at Brookhaven Field in the fourth quarter of 2005, averaging 125 Bbls/d during the quarter. During 2006 we plan to expand our operations in Brookhaven and expect our production to increase at this field throughout the year.

Eucutta Field. Eucutta Field is the only field in East Mississippi that currently has proven tertiary oil reserves. This field was purchased from Amerada Hess in 1995 and is analogous to Heidelberg Field in that the majority of its historical production was produced from the Eutaw formation. Eucutta was unitized for water flooding in 1966 and has gone through several stages of development. During the 1980s, Amerada Hess installed an inverted 5-spot pilot test in the City Bank sand (one of the Eutaw sands) to test the application of CO₂ flooding. Although the pilot test only covered approximately 20 acres, the pilot test was successful in recovering an additional 17% of the original oil in place within the pattern. Based on this success, we have designed a CO₂ project for the Eucutta Field, began construction of our CO₂ facilities and began initial well work during 2005. Initial injection of CO₂ is projected to commence late in the first quarter of 2006. Our plans for 2006 include the development of an additional 21of the 48 total patterns and expansion of our CO₂ facilities. During 2005 we recognized 9.1 MMBbls of proved reserves in the Eucutta field attributable to the CO₂ flood. The 9.1 MMBbls represents a lower recovery factor than was achieved in the pilot program in the 1980s and therefore we expect to have upward reserve increases in the future.

Through December 31, 2005, we have spent a total of $273.5 million on tertiary oil fields (including the allocated acquisition costs), and have received $303.5 million in net operating income (revenue less operating expenses), or net positive cash flow of $30.0 million. These amounts do not include the capital costs or related depreciation and amortization of our CO₂producing properties at Jackson Dome, which had a net unrecovered cost balance of $143.5 million as of December 31, 2005, including $46.9 million associated with the Free State CO₂pipeline. At year-end 2005, the proved oil reserves in our CO₂fields had a PV-10 Value of $1.5 billion, using December 31, 2005, NYMEX pricing of $61.04 per Bbl.

Denbury Resources Inc.

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 producer in the basin. For years, this has been our area with the highest production and most proved reserves, representing production of approximately 11,475 BOE/d during the fourth quarter of 2005 (36% of our Company total) and proved reserves of 54.5 MMBOE as of December 31, 2005 (36% 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, we plan to commence tertiary operations in three of these fields in early 2006. Production from these fields has declined slightly over the last three years, averaging 13,638 BOE/d in 2003, 13,085 BOE/d in 2004 and 12,072 BOE/d during 2005. For 2006, we expect our budget in this region for conventional operations to be around $50 million, about the same as in 2005, representing approximately 10% of our current 2006 exploration and development budget of $494 million.

Heidelberg Field. The largest field in the region, and our largest field corporately, is Heidelberg Field, which for the fourth quarter of 2005 produced an average of 6,945 BOE/d, 11% less than the 2004 average of 7,775 BOE/d. Heidelberg Field was acquired from Chevron in December 1997. This field was discovered in 1944 and has produced an estimated 212 MMBbls of oil and 65 Bcf of gas since its discovery. 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 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 primary oil production at Heidelberg is from five 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 27 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, and an average of 14.1 MMcf/d for 2005. 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 produced lower than average production rates. The well was completed in two stages and the initial results have been very encouraging. We will most likely convert a significant number of our planned wells in 2006 to horizontal wells. If the early results are sustainable, then horizontal drilling may allow us to develop areas of the Selma Chalk that were previously thought to be uneconomic. Currently, we plan to drill 27 vertical natural gas wells during 2006, although the number of wells will likely be reduced if vertical wells are converted to horizontal wells.

Soso Field. Soso Field was purchased from COHO Resources in 2002. Although this field produces from numerous sands, the majority of our work in 2005 involved the construction of CO₂ facilities and establishment of two patterns in the Bailey sand. This field has not had any previous CO₂ injection or pilot projects. In reviewing Soso Field, we studied the Bailey sand, which has been one of the more prolific reservoirs within the field and exhibits characteristics of a depletion drive reservoir. Because of similar reservoir characteristics to our West Mississippi floods, we expect the Bailey tertiary flood to perform in a similar manner. Our original plans called for the co-development of the Cotton Valley and Bailey sands. After further review during 2005, we concluded that co-development of the Rodessa (a larger potential reserve target) could be done with minimal changes to our overall plan. Therefore, during 2006 we plan on initiating our first injections of CO₂by developing four additional Bailey patterns and one Rodessa pattern.

Martinville Field. Martinville field was purchased from COHO Resources in 2002. As is the case with all of the East Mississippi fields, Martinville produces from multiple reservoirs. Unlike the majority of our other planned CO₂ projects, Martinville does not contain one very large reservoir to CO₂ flood, but rather several smaller reservoirs. We have identified three formations at Martinville in which we plan to initiate CO₂flooding. The first reservoir to be CO₂ flooded is the Mooringsport, which, because it has been waterflooded very successfully, is expected to CO₂ flood successfully as well. We began construction of the required CO₂ facilities and essentially completed the development of the Mooringsport sand during 2005. The second reservoir, the Rodessa, has similar reservoir characteristics to the Mooringsport. We expect to initiate injection into the Rodessa with the completion of one injector well during 2006. The final reservoir is the Wash Fred 8500’ reservoir. This reservoir contains a low oil gravity, 15 API, which will not develop miscibility with CO₂ at reservoir conditions. Denbury has several fields with similar gravity oils, which like the Wash

Denbury Resources Inc.

Fred 8500’ have had lower recoveries due to the low oil gravities and strong water drives which do not sweep the oil efficiently. We plan to initiate injection during the first quarter into the Wash Fred 8500’ reservoir at the crest of the structure, allow the CO₂ to swell the oil, decrease the oil viscosity, and displace the water and oil downward in the reservoir to the producing wells. Successful implementation of a CO₂ project in the Wash Fred 8500’ reservoir would provide the impetus to look at a whole new set of fields that have historically not been considered for CO₂ injection, although there can be no assurance that this technique will be successful or economic. We anticipate that our first injections of CO₂ in Martinville will commence late in the first quarter of 2006.

Recently Acquired Mississippi Fields

January 2006 Acquisition. In January 2006, we closed on the purchase of three old oil fields for $248 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 the Company’s Eucutta Field in Eastern Mississippi. The acquisition includes an eight-inch pipeline (currently being used for natural gas storage) from our Jackson Dome area to Tinsley Field. We plan to initially use this pipeline to transport CO₂ to Tinsley Field. We anticipate commencing initial tertiary development work at Tinsley Field in 2006, with more extensive development planned for 2007.

In order to transport CO₂ to Citronelle Field in Alabama, a 60- to 70-mile extension will need to be added to our nearly completed Free State CO₂ pipeline between Jackson Dome and our Eastern Mississippi Eucutta Field. We are still reviewing Citronelle Field and have not yet determined a definitive timetable for tertiary development of Citronelle.

South Cypress Creek is a small field in Eastern Mississippi and will likely be developed after initial development of the Tinsley and Citronelle Fields as an additional project for the our Eastern Mississippi Phase II CO₂ project.

These three fields are currently producing approximately 2,200 BOE/d net to the acquired interests, and have proved reserves of approximately 14.4 million BOEs. We operate all three fields and own the majority of the working interests.

Texas and the Barnett Shale

We currently own about 50,000 acres of leases in the Barnett Shale area in North Central Texas, about 20,000 acres of which is in the more tested northern area of Parker County, 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. As of December 31, 2005, we had approximately 157 Bcf of proved reserves in the Barnett with a PV-10 Value of approximately $370.5 million, using December 31, 2005, Henry Hub indicative cash pricing of $10.08 per MMBtu. Through December 31, 2005, we have spent a total of $130.1 million on the Barnett Shale area and have received $35.9 million in net operating income (revenue less operating expenses), or net negative cash flow of $94.2 million.

We have continued 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 2005 we drilled and completed an additional 23 horizontal wells, increasing our net Barnett Shale production from approximately 5.8 MMcfe/d in the fourth quarter of 2004 to approximately 18.3 MMcfe/d during the fourth quarter of 2005. During 2005, we also shot 3-D seismic data over our entire northern acreage position, 90 to 100 square miles and initiated a shoot of the southern acreage. The 3-D seismic data should allow us to 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 2006 as we plan to drill approximately 48 horizontal wells, 36 of which are scheduled for Parker County and 12 of which are scheduled for Erath and the more southern counties. Including seismic costs and pipeline infrastructure costs, our planned 2006 capital expenditures in the Barnett Shale are estimated to make up $120 million of our $494 million capital budget. We already have secured all of the drilling rigs necessary to drill and complete our planned 2006 program.

Denbury Resources Inc.

With the continued expansion of the Barnett Shale play by others into other areas of North Central Texas, we have purchased approximately 30,000 acres in Erath, Bosque, Hamilton and Hill counties. We expect to commence the drilling of our first horizontal well in this area in the first or second quarter of 2006. This area of the Barnett shale does not possess the overall gross thickness that our wells in Parker County possess, but may contain the same net productive thickness. Until we have drilled a few of our own wells in this area, we are not sure how the economics will compare to the Parker County acreage.

We are continuing to review the issue of pipeline capacity in our area of the Barnett Shale play. Several gas buyers and pipeline companies are entering the area and making plans to install additional pipelines to handle the anticipated future volumes of gas and we are in various stages of negotiations regarding transportation.

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 42.0 MMcfe/d net to our interest in thefourth quarter of 2005, a decrease from our 2004 average of 45.8 MMcfe/d, but an increase from earlier 2005 quarters as a result of new wells drilled during 2005. During 2005, we spent approximately $47.4 million (excluding acquisitions) in this region, approximately 16% of our total exploration and development expenditures, drilling approximately 16 wells, primarily in Cameron, Jefferson Davis, and Terrebonne Parish areas. For 2006, our spending is expected to be about the same, with a budget of $50 million, or 10% of our currently planned $494 million exploration and development budget.

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 12 wells in Terrebonne Parish during 2005, all of which were successful. In 2006, we plan to drill approximately six exploratory wells in Terrebonne Parish and one development well.

In late 2004, we participated in the drilling of a prospect in South Chauvin Field that was based on 3-D seismic amplitudes that could be tied to past production. The first well was successfully drilled and tested in late 2004. During 2005, we participated in the drilling of three additional wells that tested similar amplitudes in the overall prospect. All three were successful. Based on our current production history and geological information, it appears these amplitudes are not in communication with each other and that each well is producing from its own reservoir. Gross production rates from these wells have individually exceeded 13 MMcf/d and the proved reserves (gross) associated with each well range from 1.5 Bcf to 5 Bcf. We have an average working interest of approximately 37.5% in these wells and prospects. Based on the proved reserves, the production life of each well will be short, most likely between 2 and 3 years. Our current plans include the drilling of 2 to 3 additional wells during 2006 in this prospect area testing additional amplitudes.

In late 2005 we spudded our Gumbo Prospect, the Westerfelt #2 well, a 19,000+ foot well testing the Rob L sands. The prospect was developed by merging three 3-D data sets that essentially all intersected over the project, but could not be fully imaged on any one dataset. We logged the well in January 2006 and expect to have this well completed in the first half of 2006. Based on the logs and initial seismic interpretation, we have preliminarily estimated that the well has proved reserves of approximately 12 Bcfe net to our 29% net revenue interest. The total hydrocarbon column and the associated potential reserves could be several times greater than our preliminary estimate of proved reserves if the reservoir is filled to the spill point of the structure. The drilling of delineation wells and or significant production history will be required to fully evaluate the potential reserves associated with this prospect. A second well on this prospect will likely be drilled in 2006, although the exact timing is unknown at this point.

Another of our significant South Louisiana fields, Thornwell Field, has historically been characterized by short-lived natural gas properties that have high initial production rates with a good rate of return. During 2005 we drilled one exploratory well to test the Marg Tex/Bol Mex sands and one development well in the Bol Perc. Although both wells were successful, the Marg Tex well, Pettitjean 8-1, encountered a significant amount of net pay. Currently the well is producing at a gross rate of 13 MMcf/d and 375 Bbls/d (7 MMcfe/d net to us). Based on the Pettitjean 8-1’s performance, we believe that three to four additional locations will be required to fully develop the potential reserves associated with the entire prospect. During 2006 we plan to drill at least two of these wells.

Denbury Resources Inc.

Field Summaries

Denbury operates in four primary areas: Louisiana, Eastern Mississippi, Western Mississippi and Texas. Our 13 largest fields (listed below) constitute approximately 91% of our total proved reserves on a BOE basis and 90% on a PV-10 Value basis. Within these 13 fields, we own a weighted average 94% 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 three primary field offices in Houma, Louisiana, Laurel, Mississippi, and Cleburne, Texas.


	Proved Reserves as of December 31, 2005 (1)											2005 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		19,273		—		19,273		12.6	%	$	405,761		31		—		81.9	%
Mallalieu (East & West)		13,164		—		13,164		8.6	%		452,306		4,739		—		76.6	%
McComb/Olive		10,268		—		10,268		6.7	%		277,894		908		—		75.6	%
Little Creek & Lazy Creek		5,103		—		5,103		3.4	%		156,377		3,529		—		83.3	%
Smithdale		2,890		—		2,890		1.9	%		68,345		8		—		79.5	%
Eucutta		9,110		—		9,110		6.0	%		102,427		—		—		82.8	%

Total Mississippi - CO2 floods		59,808		—		59,808		39.2	%		1,463,110		9,215		—		79.7	%


Other Mississippi
Heidelberg (East & West)		29,077		54,784		38,208		25.0	%		636,856		4,957		14,133		75.9	%
Eucutta		4,368		—		4,368		2.9	%		74,810		986		47		81.4	%
King Bee		1,792		—		1,792		1.2	%		29,937		377		—		79.4	%
Other Mississippi		8,195		11,898		10,178		6.7	%		188,067		2,867		3,130		38.0	%

Total Other Mississippi		43,432		66,682		54,546		35.8	%		929,670		9,187		17,310		64.3	%


Louisiana
Thornwell		1,206		13,049		3,381		2.2	%		132,482		377		4,838		40.4	%
S. Chauvin		501		15,581		3,098		2.0	%		112,859		241		6,963		36.1	%
Lirette		85		7,861		1,395		0.9	%		59,978		193		7,002		67.8	%
Other Louisiana		1,027		16,426		3,765		2.5	%		137,103		771		8,687		35.5	%

Total Louisiana		2,819		52,917		11,639		7.6	%		442,422		1,582		27,490		39.3	%


Texas
Newark (Barnett Shale)		—		156,858		26,143		17.1	%		370,535		5		12,844		74.3	%

Other		114		1,910		432		0.3	%		9,741		24		1,052		0.6	%


Company Total		106,173		278,367		152,568		100.0	%	$	3,215,478		20,013		58,696		52.4	%


(1)		The reserves were prepared using constant prices and costs in accordance with the guidelines of the SEC based on the prices received on a field-by-field basis as of December 31, 2005. The prices at that date were a NYMEX oil price of $61.04 per Bbl adjusted to prices received by field and a Henry Hub natural gas price average of $10.08 per MMBtu also adjusted to prices received by field.

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, 2005:


	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
Louisiana		40,002		33,721		28,263		19,928		68,265		53,649
Mississippi		97,430		77,918		256,221		41,787		353,651		119,705
Texas		16,543		14,612		53,194		35,089		69,737		49,701
Other		17,239		7,635		83,202		12,352		100,441		19,987

Total		171,214		133,886		420,880		109,156		592,094		243,042

Denbury’s net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 4% in 2006, 22% in 2007 and 21% in 2008.

Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells at December 31, 2005:


					Producing Natural
	Producing Oil Wells				Gas Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Operated Wells:
Louisiana		23		17.1		49		41.8		72		58.9
Mississippi		437		420.7		169		155.7		606		576.4
Texas		—		—		67		65.5		67		65.5
Other		1		0.5		30		16.8		31		17.3

Total		461		438.3		315		279.8		776		718.1

Non-Operated Wells:
Louisiana		12		1.1		21		4.7		33		5.8
Mississippi		32		1.7		16		3.9		48		5.6
Texas		—		—		2		0.2		2		0.2
Other		2		—		1		0.7		3		0.7

Total		46		2.8		40		9.5		86		12.3

Total Wells:
Louisiana		35		18.2		70		46.5		105		64.7
Mississippi		469		422.4		185		159.6		654		582.0
Texas		—		—		69		65.7		69		65.7
Other		3		0.5		31		17.5		34		18.0

Total		507		441.1		355		289.3		862		730.4

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,
	2005				2004				2003
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:⁽¹⁾
Productive ⁽²⁾		12		7.1		8		5.8		7		5.3
Non-productive⁽³⁾		1		0.6		4		2.3		7		4.8
Development Wells:⁽¹⁾
Productive⁽²⁾		81		74.3		68		53.8		37		31.3
Non-productive⁽³⁾⁽⁴⁾		—		—		1		0.6		3		1.2

Total		94		82.0		81		62.5		54		42.6


(1)		An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A developmental well is a well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

(2)		A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

(3)		A nonproductive well is an exploratory or development well that is not a producing well.

(4)		During 2005, 2004 and 2003, an additional 5, 8, and 5 wells, respectively, were drilled for water or CO₂ injection purposes.

Production and Unit Prices

Information regarding average production rates, unit sale prices and unit costs per BOE are set forth under “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.

Denbury Resources Inc.

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, 2005, we had three purchasers that each accounted for 10% or more of our 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 more than 10% of our total oil and natural gas revenues: Hunt Crude Oil Supply Co. (21%) and Genesis Energy, L.P. (14%). For the year ended December 31, 2003, two purchasers each accounted for 10% or more of our oil and natural gas revenues: Hunt Crude Oil Supply Co. (15%) and Genesis Energy, L.P. (12%).

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, our single largest field, 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, 2005, the discount for our oil production from Heidelberg Field averaged $13.98 per Bbl and for our Eastern Mississippi properties as a whole the discount averaged $13.23 per Bbl relative to NYMEX oil prices. For Mallalieu Field, the largest producer during 2005 of our CO₂properties in Western Mississippi, we averaged a premium of $0.78 per Bbl over NYMEX oil prices, and $0.60 per Bbl over NYMEX prices for our tertiary oil production in Western Mississippi taken as a whole. Our Louisiana properties averaged $6.15 per Bbl below NYMEX prices during 2005.

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, 2005, we averaged $0.07 above NYMEX for our Louisiana natural gas production. However, in the Barnett Shale area in Texas, due primarily to its location, the price we received averaged $1.82 below NYMEX. We expect our overall differential to NYMEX 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 long-lived, high margin nature of our oil and gas reserves and management’s experience and expertise in exploiting these reserves, we believe that we are effective in competing in the market.

Denbury Resources Inc.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. We cannot be certain when we will experience these issues and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results or restrict our ability to drill those wells and conduct those operations that we currently have planned and budgeted.

Federal and State Regulations

Numerous federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving 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.

Denbury Resources Inc.

Natural Gas Gathering Regulations

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Federal, State or Indian Leases

Our operations on federal, state or Indian oil and gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service (MMS) and other agencies.

Environmental Regulations

Public interest in the protection of the environment has increased dramatically in recent years. Our oil and natural gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials such as hydrocarbons and naturally occurring radioactive materials are subject to stringent regulation. We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries, fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures.

Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact the Company’s operations and costs. These regulations include, among others, (i) regulations by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act, Federal Resource Conservation and Recovery Act and analogous state laws that regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company; (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, 2005, 2004 and 2003. 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.

Denbury Resources Inc.

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 97% of our proved undeveloped oil reserves. We consider these reserves to be lower risk than other proved undeveloped reserves that require drilling at locations offsetting existing production because all of these proved undeveloped reserves are associated with secondary recovery or tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under primary production. The main reason these reserves are classified as undeveloped is because they require significant additional capital associated with drilling/re-entering wells or additional facilities in order to produce the reserves and/or are waiting for a production response to the water or CO₂ injections.

Our proved undeveloped natural gas reserves associated with our Selma Chalk play at Heidelberg and the Barnett Shale play account for approximately 95% of our proved undeveloped natural gas reserves. The remaining undeveloped natural gas reserves are spread over multiple fields. Our current plans for 2006 include development of 70 to 80 wells in our two primary natural gas plays, the Barnett Shale and Selma Chalk.


	December 31,
	2005			2004			2003
ESTIMATED PROVED RESERVES:
Oil (MBbls)		106,173			101,287			91,266
Natural gas (MMcf)		278,367			168,484			221,887
Oil equivalent (MBOE)		152,568			129,369			128,247

PERCENTAGE OF TOTAL MBOE:
Proved producing		40	%		39	%		43	%
Proved non-producing		16	%		16	%		18	%
Proved undeveloped		44	%		45	%		39	%
REPRESENTATIVE OIL AND GAS PRICES:⁽¹⁾
Oil-NYMEX	$	61.04		$	43.45		$	32.52
Natural gas — Henry Hub		10.08			6.18			5.97
PRESENT VALUES:⁽²⁾
Discounted estimated future net cash flow before income taxes (“PV-10 Value”) (thousands)	$	3,215,478		$	1,643,289		$	1,566,371
Standardized measure of discounted estimated future net cash flow after income taxes (thousands)		2,084,449			1,129,196			1,124,127


(1)		The prices of each year-end were based on market prices in effect as of December 31 of each year, NYMEX prices per Bbl and Henry Hub cash prices per MMBtu, with the appropriate adjustments (transportation, gravity, BS&W, purchasers’ bonuses, Btu, etc.) applied to each field to arrive at the appropriate corporate net price.

(2)		Determined based on year-end unescalated prices and costs in accordance with the guidelines of the SEC, discounted at 10% per annum.

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 13, “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 50% of our 2006 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. 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 70% of our proved reserves are oil. 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.

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 2005, NYMEX oil prices were high throughout the year, averaging over $56.00 per Bbl for 2005. During 2004 and 2005, 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

Denbury Resources Inc.

heavier, sour crudes, and was even higher during the fourth quarter of 2004, averaging $6.48 per Bbl. During 2005, our oil differential averaged $6.33 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 have as much of an impact on our profitability as does the volatility in the NYMEX oil prices.

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 and in 2005, averaged $8.97 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 9, “Derivative Contracts,” 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 or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted.

Our future performance depends upon our ability to find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we can successfully replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and natural gas production and lower revenues and cash flows from operations. We have historically replaced reserves through both drilling and acquisitions. In the future we may not be able to continue to replace reserves at acceptable costs. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investment to maintain or expand our oil and natural gas reserves if our cash flows from operations are reduced, due to lower oil or natural gas prices or otherwise, or if external sources of capital become limited or unavailable. Further, the process of using CO₂ for tertiary recovery and the related infrastructure requires significant capital investment, often one to two years prior to any resulting production and cash flows from these projects, heightening potential capital constraints. If we do not continue to make significant capital expenditures, or if outside capital resources become limited, we may not be able to maintain our growth rate. In addition, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves will be

Denbury Resources Inc.

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 $248 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 are producing approximately 2,200 BOE/d net to the acquired interests, and have proved reserves of approximately 14.4 million BOEs. If we are unable to successfully develop the potential oil reserves and increase production at these three fields, it would negatively affect the return on our investment in these fields.

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.

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.

Denbury Resources Inc.

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, 2005, three purchasers each accounted for more than 10% of our oil and natural gas revenues and in the aggregate, for 61% 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. 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, 2005, approximately 44% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but these assumptions may not be accurate, and this may not occur.

We are subject to complex federal, state and local laws and regulations, including environmental laws, that 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.

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 January 31, 2006, we have approximately $100.0 million available on our borrowing base under our bank credit facility. The next semi-annual redetermination of the borrowing base for our bank credit facility will be on April 1, 2006. Our bank borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which

Denbury Resources Inc.

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 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 10, “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, including those noted below. 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

Denbury Resources Inc.

provide accruals for litigation and claims if we determine that we may have a range of legal exposure that would require accrual. The estimate of the potential impact from the following legal proceedings on our financial position, overall results of operations or cash flows could change in the future.

Along with two other companies, we have been named in a lawsuit styled J. Paulin Duhe, Inc. vs. Texaco, Inc., et al, Cause No. 101,227, filed in late 2003 in the 16^th Judicial District Court, Division “E,” Terrebonne Parish, Louisiana, seeking restoration to its original condition of property on which oil has been produced over the past 70 years. The contract and tort claims by the plaintiffs allege surface and groundwater damage of 26 acres that are part of our Iberia Field in Iberia Parish, Louisiana. Recently, plaintiff’s experts have initially alleged that clean-up of alleged contamination of the property would cost $79.0 million, although settlement offers by plaintiffs have already been made for much smaller sums. The property was originally leased to Texaco, Inc. for mineral development in 1934 and Denbury acquired its interest in the property in August 2000 from Manti Operating Company. During 2005, the courts ruled that the plaintiffs’ claims were premature insofar as they sought to enforce the end of lease restoration obligation and dismissed that claim. Other claims were not dismissed and certain aspects of the litigation are ongoing. We believe that we are indemnified by the prior owner, which we expect to cover our exposure to most damages, if any, found to have occurred prior to the time that we purchased the property. We believe that the allegations of this lawsuit are subject to a number of defenses, are without merit and we and the other defendants plan to vigorously defend this lawsuit, and if necessary, we will seek indemnification from the prior owner.

On December 29, 2003, an action styled Harry Bourg Corporation vs. Exxon Mobil Corporation, et al, Cause No. 140749, was filed in the 32^nd Judicial District Court, Terrebonne Parish, Louisiana against Denbury and 11 other oil companies and their predecessors alleging damage as the result of mineral exploration activities conducted by these oil and gas operators/companies over the last 60 years. Plaintiff has asked for restoration of the 10,000-acre property and/or damages in claims made under tort law and various oil and gas contracts. The Bourg Corporation produced preliminary expert reports that allege damages of approximately $100.0 million against the defendants as a group. Discovery is continuing in this case, with trial currently set for June 2006. Depending on the outcome of the case, we may have indemnification obligations to prior owners. We believe we have historical documents and matters of fact that we believe provide strong defenses against these claims and we plan to vigorously defend this lawsuit along with the other defendants.

Item 4. Submission of Matters to a Vote of Security Holders

A special meeting of the stockholders was held on October 19, 2005, for the purposes of: (1) approving an amendment to our Restated Certificate of Incorporation to increase the number of shares of our authorized common stock from 100,000,000 shares to 250,000,000 shares; (ii) approving an amendment to our Restated Certificate of Incorporation to split our common shares 2-for-1; and (iii) granting authority to the Company to extend the solicitation period in the event that the special meeting is postponed or adjourned for any reason. At the record date, September 6, 2005, 57,153,230 shares of common stock were outstanding and entitled to one vote per share upon all matters submitted at the meeting. Holders of 51,315,563 shares of common stock, representing approximately 90% of the total issued and outstanding shares of common stock, were present in person or by proxy at the meeting to cast their vote. All matters were approved as listed below.

With respect to the amendment to our Restated Certificate of Incorporation to increase the number of shares of our authorized common stock from 100,000,000 shares to 250,000,000 shares, the votes were cast as follows:


For	Against	Abstentions
50,448,960	859,097		7,506

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


For	Against	Abstentions
51,252,432	51,750		11,381

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


For	Against	Abstentions
24,246,544	24,131,812		2,937,206

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. As of February 28, 2006, the number of record holders of Denbury’s common stock was 678. Management believes, after inquiry, that the number of beneficial owners of Denbury’s common stock is in excess of 9,700. On February 28, 2006, the last reported sales price of Denbury’s Common Stock, as reported on the NYSE, was $28.35 per share.


	2005				2004
	High		Low		High		Low
First Quarter	$	18.32	$	12.37	$	8.47	$	6.63
Second Quarter		20.53		14.02		10.87		8.36
Third Quarter		25.71		19.95		13.10		9.30
Fourth Quarter		25.50		19.36		14.65		12.03

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 2005.

Equity Compensation Plan Information

The following table summarizes information about Denbury’s equity compensation plans as of December 31, 2005.


					Number of securities
					remaining available
					for future issuance
	Number of securities to		Weighted average		under equity
	be issued upon exercise		exercise price of		compensation plans
	of outstanding options,		outstanding options,		(excluding securities
	warrants and rights		warrants and rights		reflected in column a)
Plan Category	(a)		(b)		(c)
Equity Compensation plans approved by security holders:

Stock Option Plan		8,370,610	$	6.64		—

2004 Omnibus Plan		1,035,462		19.66		1,644,538

Employee Stock Purchase Plan		—		—		452,371
Equity compensation plans not approved by security holders:

Director Compensation Plan		—		—		138,229

		9,406,072	$	8.07		2,235,138

Denbury Resources Inc.

Item 6. Selected Financial Data


(In thousands, unless otherwise noted)	Year Ended December 31,
	2005			2004⁽¹⁾			2003			2002			2001⁽¹⁾
Consolidated Statements of Operations Data:
Revenues	$	560,392		$	382,972		$	333,014		$	285,152		$	285,111
Net income		166,471			82,448			56,553	(2)		46,795			56,550
Net income per common share ⁽³⁾:
Basic		1.49			0.75			0.52	(2)		0.44			0.57
Diluted		1.39			0.72			0.51	(2)		0.43			0.56
Weighted average number of common shares outstanding ⁽³⁾:
Basic		111,743			109,741			107,763			106,487			98,650
Diluted		119,634			114,603			110,928			108,730			100,722
Consolidated Statements of Cash Flow Data:
Cash provided by (used by):
Operating activities	$	360,960		$	168,652		$	197,615		$	159,600		$	185,047
Investing activities		(383,687	)		(93,550	)		(135,878	)		(171,161	)		(318,830	)
Financing activities		154,777			(66,251	)		(61,489	)		12,005			134,986
Production (Daily):
Oil (Bbls)		20,013			19,247			18,894			18,833			16,978
Natural gas (Mcf)		58,696			82,224			94,858			100,443			85,238
BOE (6:1)		29,795			32,951			34,704			35,573			31,185
Unit Sales Price (excluding hedges):
Oil (per Bbl)	$	50.30		$	36.46		$	27.47		$	22.36		$	21.34
Natural gas (per Mcf)		8.48			6.24			5.66			3.31			4.12
Unit Sales Price (including hedges):
Oil (per Bbl)	$	50.30		$	27.36		$	24.52		$	22.27		$	21.65
Natural gas (per Mcf)		7.70			5.57			4.45			3.35			4.66
Costs per BOE:
Lease operating expenses	$	9.98		$	7.22		$	7.06		$	5.48		$	4.84
Production taxes and marketing expenses		2.54			1.55			1.17			0.92			0.96
General and administrative		2.62			1.78			1.20			0.96			0.89
Depletion, depreciation, and amortization		9.09			8.09			7.48			7.26			6.27
Proved Reserves:
Oil (MBbls)		106,173			101,287			91,266			97,203			76,490
Natural gas (MMcf)		278,367			168,484			221,887			200,947			198,277
MBOE (6:1)		152,568			129,369			128,247			130,694			109,536
Consolidated Balance Sheet Data:
Total assets	$	1,505,069		$	992,706		$	982,621		$	895,292		$	789,988
Total long-term liabilities		617,343			368,128			434,845			432,616			360,882
Stockholders’ equity (4)		733,662			541,672			421,202			366,797			349,168


(1)		We sold Denbury Offshore, Inc. in July 2004. We acquired Matrix Oil and Gas Inc. in July 2001.

(2)		In 2003, we recognized a gain of $2.6 million for the cumulative effect adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” The adoption of SFAS No. 143 increased basic and diluted net income per common share by $0.02. In April 2003, we recorded a pre-tax charge of $17.6 million associated with the early debt retirement.

(3)		On October 31, 2005, we split our common stock on a 2-for-1 basis. Information relating to all prior years shares and earnings per share has been retroactively restated to reflect the stock split.

(4)		We have never paid any dividends on our common stock.

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 reserves of carbon dioxide (“CO₂”) used for tertiary oil recovery east of the Mississippi River, 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 three primary field offices located in Houma, Louisiana; Laurel, Mississippi; and Cleburne, Texas.

2005 Overview

Continued expansion of our tertiary operations. Since we acquired our first carbon dioxide tertiary flood in Mississippi over six years ago, we have gradually increased our emphasis on these types of operations. We particularly like this 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 CO₂is one of the most important ingredients, if not the key ingredient, to our tertiary operations. During 2005 we increased our proved CO₂ reserve quantities by 74%, from 2.7 Tcf as of December 31, 2004, to approximately 4.6 Tcf as of December 31, 2005 (both of these quantities are on a working interest basis – see “CO₂ Operations – CO₂Resources” for further information).

Operating results. Earnings and cash flow were at record annual levels in 2005, primarily as a result of high commodity prices. Production increased approximately 6% over the prior year’s production after adjusting for the production associated with our offshore properties sold in July 2004, even though we deferred approximately 1,100 BOE/d during 2005 as a result of two hurricanes (See “Operating Income – Production” below). Virtually all expenses increased during 2005, on both an absolute and per BOE basis, as we experienced cost increases in almost every aspect of our business, as much as 20% to 30% per annum for certain items. Operating expenses also increased as a result of our increased emphasis on tertiary operations, which have higher operating costs per BOE than our other properties. Nevertheless, during 2005 the high commodity prices more than offset the higher expenses. As has been our practice for several years, we are reinvesting virtually all of our cash flow in new projects, with a desire to (i) further increase our production and reserves, and (ii) keep our balance sheet strong by limiting our exploration and development budget to an amount approximately equal to our cash flow from operations. During 2005, our proved reserves increased from 129.4 MMBOE as of December 31, 2004, to 152.6 MMBOE as of December 31, 2005, replacing approximately 313% of our 2005 production, over 85% of which was from internal organic growth and the balance from acquisitions.

Net income for 2005 was $166.5 million, approximately double 2004 net income of $82.4 million and nearly a three-fold increase over 2003 net income of $56.6 million. Lower expense on our commodity hedges improved our net income. We paid out approximately $16.8 million during 2005 as compared to $84.6 million during 2004 and $62.2 million during 2003 in settlement payments on our commodity hedges (see “Market Risk Management”). As our financial position has improved over the last few years, we have generally hedged less, thus reducing our out of pocket cash payments, even though commodity prices have continued to increase.

Stock split. On October 19, 2005, our stockholders approved an amendment to our certificate of incorporation to increase our authorized shares of common stock from 100 million shares to 250 million shares and to split our common stock on a two-for-one basis. Stockholders of record as of the close of business on October 31, 2005, received one additional share of Denbury common stock for each share of common stock held at that time. All per share numbers for all periods included herein have been restated for this two-for-one split.

2004 sale of offshore operations. On July 20, 2004, we closed the sale of Denbury Offshore, Inc., a subsidiary that held our offshore assets, for approximately $187 million (after sale adjustments). Our offshore properties made up approximately 12% of our year-end 2003 proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented approximately 25% (9,114 BOE/d) of our 2004 second quarter production.

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

Recent Acquisitions

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. We expect to begin our initial tertiary development work at Tinsley Field during 2006 with more extensive development planned for 2007. The timing of tertiary development at Citronelle Field is uncertain as we will need to build a 60- to 70-mile pipeline extension of our CO₂line 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. See “CO₂ Operations” for further information regarding our CO₂ operations.

The preliminary adjusted purchase price for these three properties was approximately $248 million, after adjusting for interim net cash flow and minor purchase price adjustments. The acquisition was funded with proceeds of the $150 million of senior subordinated notes issued in December 2005 and bank financing under the Company’s existing credit facility, bringing the outstanding balance of the Company’s bank debt as of January 31, 2006, to approximately $100 million.

During 2005, we reached an agreement with Southern Natural Gas Company to acquire a 102-mile natural gas pipeline that runs from Gwinville Field in Central Mississippi to near Lake St. John Field, near the Louisiana/Mississippi border. This pipeline crosses our existing 20” CO₂ pipeline in Southwest Mississippi and will allow us to transport CO₂ to two oil fields we acquired during 2005, Lake St. John and Cranfield Fields. The purchase price and associated anticipated remediation work is estimated at approximately $5.2 million. Closing of the acquisition is subject to regulatory approval, which may take up to six months. Prior to converting the pipeline to CO₂ service, a smaller 17-mile natural gas pipeline will need to be constructed to replace natural gas service to the local communities currently being serviced by the pipeline.

Capital Resources and Liquidity

Our current capital budget for 2006, excluding any potential acquisitions, is approximately $494 million, which at commodity futures prices as of mid-February appears to be slightly more than our anticipated cash flow from operations. As has been our practice in the past, we attempt to reinvest all of our available cash flow from operations to find additional reserves and increase production. 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 anticipate that we would fund any minor differences between our capital budget and cash flow from operations with bank debt, but if the difference becomes significant, we would likely postpone some of our projects. As of February 28, 2006, we had approximately $100 million of unused borrowing base on our bank credit line, which in our opinion could be significantly expanded if desired.

We plan to spend approximately 50% of our capital budget on tertiary related projects and approximately 25% in the Barnett Shale area, with the balance split almost equally between our other operating areas. Although we now control most of the fields along our existing CO₂ pipeline in Southwest Mississippi, there are several fields in East Mississippi that could be acquired to further expand our planned tertiary operations there, plus we are continuing to seek additional interests in the fields that we currently own. Further, we would like to add additional phases or areas of tertiary operations by acquiring other old oil fields in other parts of our region of operations, building a CO₂ pipeline to those areas and initiating additional tertiary floods. The purchase price of these potential tertiary fields can vary widely, depending on the level of existing production and conventional oil reserves, making it impractical to forecast our acquisition expenditures. We would likely fund any acquisitions with debt, supplemented as we feel necessary with equity. Although we are comfortable with our existing debt levels, they are higher than they have been the last couple of years because we funded the recently closed $248 million property acquisition (see “Recent Acquisitions”) with debt. Since it is our desire to maintain a strong financial position, it is unlikely that we will

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

increase our debt levels by any significant amount in the near future other than on a temporary basis, and we have not eliminated the possibility of issuing equity to reduce part, or all, of the bank debt incurred for the recent acquisition. We could also generate cash, if desired, by refinancing our essentially completed $50 million CO₂ pipeline to East Mississippi, recouping our expended capital and instead paying for the cost of the pipeline over time. With our current credit availability and other options that we believe are available to us, we do not anticipate having any liquidity issues in the foreseeable future.

At December 31, 2005, we had outstanding $225 million (principal amount) of 7.5% subordinated notes due 2013, $150 million (principal amount) of 7.5% subordinated notes due 2015, approximately $9.4 million of capital lease commitments, no bank debt, and working capital of $145.1 million. We borrowed $100 million on our bank line at the end of January and used available cash to fund the $248 million acquisition, which closed on January 31, 2006.

Sources and Uses of Capital Resources

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 Energy, L.P. (“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 to $165.1 million, with a portion of such funds used in January 2006 to partially fund the $248 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.

During 2003, we generated approximately $197.6 million of cash flow from operations and generated an additional $29.4 million of cash from sales of oil and gas properties. The largest single asset sale was the sale of Laurel Field, acquired from COHO in August 2002, which netted us approximately $25.9 million. Later in the year, we also sold a volumetric production payment to Genesis, which netted us approximately $23.9 million of cash. During 2003, we spent $146.6 million on oil and natural gas exploration and development expenditures, $22.7 million on CO₂ capital investments and acquisitions, and approximately $11.8 million on oil and natural gas property acquisitions, for total capital expenditures of approximately $181.1 million. Our exploration and development expenditures included approximately $115.3 million spent on drilling, $15.7 million of geological, geophysical and acreage expenditures and $35.2 million spent on facilities and recompletion costs. In addition,

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

during 2003 we incurred approximately $15.6 million of costs to refinance our previously outstanding subordinated debt. The $147.3 million of net total expenditures (including the $15.6 million of debt refinancing costs but net of property sales proceeds) was funded by our cash flow from operations, with the balance used to reduce our total debt by approximately $50.0 million.

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 obligations that are not on our balance sheet include our operating leases, which at year-end 2005 totaled $37.2 million 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, 2005, we had a total of $460,000 outstanding in letters of credit. Genesis Energy, Inc., our 100% owned subsidiary that is the general partner of Genesis, has guaranteed the bank debt of Genesis, which consists of $10.1 million in letters of credit at December 31, 2005. 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, 2005. 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 is presented in the following table:


	Payments Due by Period
Amounts in Thousands	Total		2006		2007		2008		2009		2010		Thereafter

Contractual Obligations:
Subordinated debt (a)	$	375,000	$	—	$	—	$	—	$	—	$	—	$	375,000
Estimated interest payments on subordinated debt (a)		234,262		28,125		28,125		28,125		28,125		28,125		93,637
Operating lease obligations		37,236		6,971		6,959		6,812		5,931		4,392		6,171
Capital lease obligations(b)		9,411		1,185		1,185		1,185		1,185		1,185		3,486
Capital expenditure obligations (c)		90,682		43,763		26,249		15,990		4,680		—		—
Other long-term liabilities reflected in our Consolidated Balance Sheet:
Derivative liabilities (d)		10,458		2,774		3,706		3,978		—		—		—

Other Cash Commitments:
Future development costs on proved oil and gas reserves, net of capital obligations (e)		441,123		203,289		133,229		59,746		16,294		17,119		11,446
Future development cost on proved C02 reserves, net of capital obligations (f)		134,759		24,759		17,000		17,000		—		—		76,000
Asset retirement obligations (g)		69,066		1,820		1,057		3,723		455		2,399		59,612

Total	$	1,401,997	$	312,686	$	217,510	$	136,559	$	56,670	$	53,220	$	625,352

(a)		These long-term borrowings and related interest payments are further discussed in Note 6 to the Consolidated Financial Statements. This table assumes that our long-term debt is held until maturity.

(b)		Represents future minimum cash commitments to Genesis under capital leases in place at December 31, 2005, primarily for transportation of crude oil and CO₂. Approximately $3 million of these payments represents interest.

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

(c)

Represents future minimum cash commitments under contracts in place as of December 31, 2005, primarily for drilling rig services and well related costs. As is common in our industry, we commit to make certain expenditures on a regular basis as part of our ongoing development and exploration program. These commitments generally relate to projects that occur during the subsequent several months and are usually part of our normal operating expenses or part of our capital budget, which for 2006 is currently set at $494 million. In addition, we have recurring expenditures for such things as accounting, engineering and legal fees, software maintenance, subscriptions, and other overhead type items. Normally these expenditures do not change materially on an aggregate basis from year to year and are part of our general and administrative expenses. We have not attempted to estimate these types of expenditures in this table as most could be quickly cancelled with regard to any specific vendor, even though the expense itself may be required for ongoing normal operations of the Company.

(d)

Represents the estimated future payments under our derivative obligations based on the futures market prices as of December 31, 2005. These amounts will change as oil and natural gas commodity prices change. The estimated fair market value of our oil and natural gas commodity derivatives at December 31, 2005, was a $9.4 million liability. See further discussion of our derivative contracts and their market price sensitivities in “Market Risk Management” below in this Management’s Discussion and Analysis of Financial Condition and in Note 9 to the Consolidated Financial Statements.

(e)

Represents projected capital costs as scheduled in our December 31, 2005 proved reserve report that are necessary in order to recover our proved undeveloped oil and natural gas reserves. These are not contractual commitments and are net of any other capital obligations shown above.

(f)

Represents projected capital costs as scheduled in our December 31, 2005 proved reserve report that are necessary in order to recover our proved undeveloped reserves for our CO₂ source wells used to produce CO₂ for our tertiary operations. These are not contractual commitments and are net of any other capital obligations shown above.

(g)

Represents the estimated future asset retirement obligations on an undiscounted basis. The discounted asset retirement obligation of $27.1 million, as determined under SFAS No. 143, is further discussed in Note 4 to the Consolidated Financial Statements.

Long-term contracts require us to deliver CO₂ to our industrial CO₂ customers at various contracted prices, plus we have a CO₂ delivery obligation to Genesis pursuant to three volumetric production payments (“VPP”) entered into during 2003, 2004 and 2005. Based upon the maximum amounts deliverable as stated in the contracts and the volumetric production payments, we estimate that we may be obligated to deliver up to 390 Bcf of CO₂ to these customers over the next 18 years; however, since the group as a whole has historically taken less CO₂ than the maximum allowed in their contracts, based on the current level of deliveries, we project that our commitment would likely be reduced to approximately 264 Bcf. The maximum volume required in any given year is approximately 113 MMcf/d, although based on our current level of deliveries, this would likely be reduced to approximately 74 MMcf/d. Given the size of our proven CO₂ reserves at December 31, 2005 (approximately 4.6 Tcf before deducting approximately 237.1 Bcf for the three VPPs), our current production capabilities and our projected levels of CO₂ usage for our own tertiary flooding program, we believe that we will be able to meet these delivery obligations.

Results of Operations

CO₂ Operations

Overview. Our interest in tertiary operations has increased to the point that approximately 50% of our 2005 expenditures and 2006 capital budget are dedicated to tertiary related operations. We particularly like this play as (i) it is lower risk and more predictable than most traditional exploration and development activities, (ii) it provides a reasonable rate of return at relatively low oil prices (generally in the twenties, 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 CO₂that 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 CO₂pipeline that we acquired in 2001. The most significant fields in this area are Little Creek, Mallalieu, McComb and Brookhaven. Phase II, which we are just starting with the completion of our CO₂pipeline to East Mississippi, includes Eucutta, Soso, Martinville and Heidelberg Fields. With the properties acquired in our recent acquisition that closed in January 2006 (see “Recent Acquisitions” above), we have labeled the planned operations at Tinsley Field, Northwest of Jackson Dome, as

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

Phase III. Phase IV includes Cranfield and Lake St. John Fields, two fields near the Mississippi / Louisiana border west of the fields in Phase I.

CO₂Resources. In February 2001, we acquired the sources of CO₂ located near Jackson, Mississippi, and a 183-mile pipeline to transport it to our oil fields. Since February 2001, we have acquired two and drilled nine additional CO₂producing wells, significantly increasing our estimated proved CO₂ reserves from approximately 800 Bcf at the time of acquisition to approximately 4.6 Tcf as of December 31, 2005, approximately 500 Bcf more than we estimate we need for our existing and currently planned phases of tertiary operations. The estimate of 4.6 Tcf of proved CO₂ reserves is based on 100% ownership of the CO₂ reserves, of which Denbury’s net revenue interest ownership is approximately 3.8 Tcf, and is 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 937 Bcf of CO₂ to develop and produce the proved tertiary recovery reserves we have recorded at December 31, 2005.

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 2006, we estimate that we are capable of producing approximately 450 MMcf/d of CO₂, over five 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 2006, in order to further increase our production capacity and potentially increase our proven CO₂ reserves. Our drilling activity at Jackson Dome will continue beyond 2006 as our current forecasts for the four planned phases suggest that we will need over 800 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 a volumetric production payment for the CO_2. Our average daily CO₂ production during 2003, 2004 and 2005 was approximately 170 million, 218 million, and 242 million cubic feet per day, of which approximately 62% in 2003, and 73% in 2004, and 73% in 2005 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 $0.16 per Mcf in operating expenses to produce our CO₂during 2005, more than our 2004 annual average of $0.12 per Mcf, primarily due to increased labor, utilities and equipment rental expenses during 2005, coupled with higher royalty expenses because several of our royalties correlate with oil prices. During 2003, we spent approximately $0.15 per Mcf to produce our CO_2.Our estimated total cost per thousand cubic feet of CO₂ during 2005 was approximately $0.25, after inclusion of depreciation and amortization expense related to the CO₂ production, as compared to approximately $0.21 during 2004.

Overview of Tertiary Economics. Most of our tertiary operations are economic at oil prices in the twenties, although the economics vary by field. Our costs have escalated during the last few years due to general cost inflation in the industry and this trend is expected to continue. Our inception to date finding and development costs (including future development and abandonment costs) for our tertiary oil fields through December 31, 2005, was approximately $7.50 per BOE. Currently, we forecast that these costs will range from $3 to $11 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 averaged $12.00 per BOE in 2005 and are expected to range from $10 to $15 per BOE over the life of each field, 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 plan to start flooding during 2006, was $9.39 per BOE during 2005, a differential that is significantly higher than historical 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 our 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

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

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 our overall tertiary development program. We believe that such delays, if any, should only be temporary.

Financial Statement Impact of CO2 Operations. The increasing emphasis on CO₂ tertiary recovery projects has made, and will continue to make, an impact on our financial results and certain operating statistics.

First, there is a significant delay between the initial capital expenditures and the resulting production increases, as these tertiary operations require the building of facilities before CO₂ flooding can commence and it usually takes six to twelve months before the field responds (i.e., oil production commences) to the injection of CO₂. Further, as we expand to other areas, there will be times when we spend significant amounts of capital before we can recognize any proven reserves as these other areas, for the most part, will require an oil production response to the CO₂ injections before any oil reserves can be recorded. Further, 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 liquid state for re-injection purposes). As commodity and energy prices increase, so do our operating expenses in these fields. Our operating cost for our tertiary operations during 2005 averaged $12.00 per BOE, as compared to an estimated cost of around $7 to $10 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 are recorded as lease operating expenses on those fields. Since we expense all of the operating costs to produce and inject our CO₂, the operating costs per barrel will generally be higher at the inception of CO₂ injection before oil production is realized in a particular field. Our overall 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).

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 CO₂ related oil production 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 we plan to flood as part of Phase II have recently sold at a significant discount to NYMEX. 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, Smithdale and Brookhaven Fields, as well as 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, 2005, we had approximately 59.8 MMBbls of proven oil reserves related to tertiary operations (50.7 MMBbls of which was in Phase I and the balance in Phase II) and have identified and estimated significant additional oil potential in other fields that we own in this region. We plan to start CO₂injections at three fields in Phase II within the first half of 2006, although we do not expect any material production response until 2007. During 2006, we will also start preliminary development work at Tinsley Field (Phase III) and at Cranfield (Phase IV).

Our oil production from our CO₂tertiary recovery activities has steadily increased during the last few years, from 3,970 Bbls/d in 2002 to 9,215 Bbls/d during 2005. Our oil production in the third quarter of 2005 decreased 6% over second quarter 2005 levels primarily as a result of production deferred because of two hurricanes which disrupted our electrical power, forcing us to temporarily shut-in our production. Tertiary oil production represented approximately 48% of our total corporate oil production during the fourth quarter of 2005 and approximately 31% of our total corporate production 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. Following is a chart with our tertiary oil production by field for 2003, 2004 and by quarter for 2005.

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
Tertiary Oil Field	2005		2005		2005		2005		2005		2004		2003

Brookhaven		—		—		—		125		31		—		—
Little Creek & Lazy Creek		3,709		3,847		3,357		3,210		3,529		3,148		3,093
Mallalieu (East and West)		4,235		4,582		4,565		5,562		4,739		3,351		1,578
McComb & Olive		700		988		928		1,011		908		285		—
Smithdale		—		—		—		31		8		—		—


Total tertiary oil production		8,644		9,417		8,850		9,939		9,215		6,784		4,671

Our operations in this area, as well as others, have had minor delays during 2005. 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; delays caused by the two hurricanes; and a general tightening of available materials and equipment in the industry. Generally, the fields are performing as anticipated, but 2005 tertiary oil production was not quite as high as originally expected because of these delays and the two hurricanes. In addition, the timing of specific well responses is not always possible to accurately forecast, so we could experience variances from our expected long-term oil production forecast.

In addition to higher energy costs to operate our tertiary recycling facilities related to higher commodity prices, we have experienced general cost inflation during the last few years. We have also leased a portion of our recycling and plant equipment used in our tertiary operations, which further increases operating expenses. Over the last three years we have leased certain equipment that qualify for operating lease treatment representing an underlying aggregate cost of approximately $30.3 million as of December 31, 2005, and we expect to enter into new leases for equipment during 2006 representing additional underlying costs of approximately $30 million. Further, the cost to produce our CO₂increased during 2005 (see “CO₂Resources” above), all of which resulted in an increase in our tertiary operating cost per BOE from $9.90 per BOE in 2004 to $12.00 per BOE during 2005. The absolute amount of operating expenses related to tertiary operations increased from $19.3 million during 2003 to $24.6 million during 2004 and $40.4 million during 2005.

Through December 31, 2005, we had spent a total of $273.5 million on fields currently being flooded (included allocated acquisition costs), and had received $303.5 million in net cash flow (revenue less operating expenses and capital expenditures), or net positive cash flow of $30.0 million. The proved oil reserves in our CO₂fields have a PV-10 Value of $1.5 billion, using December 31, 2005, constant NYMEX pricing of $61.04 per Bbl. These amounts do not include the capital costs or related depreciation and amortization of our CO₂ producing properties, but do include CO₂source field lease operating costs and transportation costs. Through December 31, 2005, we had a balance of approximately $143.5 million of unrecovered costs for the CO₂assets.

CO₂ Related Capital Budget for 2006. Tentatively, we plan to spend approximately $45 million in 2006 in the Jackson Dome area with the intent to add additional CO₂ reserves and deliverability for future operations. Approximately $105 million in capital expenditures is budgeted in 2006 for our Phase I properties (Southwest Mississippi) and approximately $55 million for Phase II properties (East Mississippi), plus an additional $29 million for properties in Phases III and IV, making our combined CO₂ related expenditures just under 50% of our 2006 capital budget.

Operating Income

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 5% from 2003 to 2004 and approximately 10% from 2004 to 2005, primarily related to the sale of our offshore properties in July 2004 and further impacted by the hurricanes during 2005, but the effect of the deferred production was more than offset by the higher commodity prices.

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


	Year Ended December 31,
Amounts in Thousands Except Per Share Amounts	2005		2004			2003

Net income	$	166,471	$	82,448		$	56,553
Net income per common share:
Basic	$	1.49	$	0.75		$	0.52
Diluted		1.39		0.72			0.51

Adjusted cash flow from operations	$	343,383	$	200,193		$	189,802
Net change in assets and liabilities relating to operations		17,577		(31,541	)		7,813

Cash flow from operations (GAAP measure)	$	360,960	$	168,652		$	197,615

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, as noted above, during 2003, our accounts payable and accrued liabilities increased as a result of our higher drilling activity level late in the year, particularly offshore, increasing our available cash from operations. 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, both of which contributed to the significant difference between our 2004 adjusted cash flow and GAAP cash flow from operations. 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 2005 than a year earlier, due to higher oil and natural gas prices, partially offsetting the benefit of higher accounts payable and accrued liabilities.

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

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


	Year Ended December 31,
	2005			2004			2003

AVERAGE DAILY PRODUCTION VOLUMES
Bbls		20,013			19,247			18,894
Mcf		58,696			82,224			94,858
BOE(l)		29,795			32,951			34,704

OPERATING REVENUES (thousands)
Oil sales	$	367,414		$	256,843		$	189,442
Natural gas sales		181,641			187,934			196,021

Total oil and natural gas sales	$	549,055		$	444,777		$	385,463


OIL AND GAS DERIVATIVE CONTRACTS (thousands) (2)
Cash expense on settlements of derivative contracts	$	(16,761	)	$	(84,557	)	$	(62,210	)
Non-cash derivative (expense) income		(12,201	)		(1,270	)		3,578

Total expense from oil and gas derivative contracts	$	(28,962	)	$	(85,827	)	$	(58,632	)


OPERATING EXPENSES (thousands)
Lease operating expenses	$	108,550		$	87,107		$	89,439
Production taxes and marketing expenses (3)		27,582			18,737			14,819

Total production expenses	$	136,132		$	105,844		$	104,258


CO2 sales and transportation fees (4)	$	8,119		$	6,276		$	8,188
CO2 operating expenses		2,251			1,338			1,710

CO2 operating margin	$	5,868		$	4,938		$	6,478


UNIT PRICES-INCLUDING IMPACT OF DERIVATIVE SETTLEMENTS (2)
Oil price per Bbl	$	50.30		$	27.36		$	24.52
Gas price per Mcf		7.70			5.57			4.45

UNIT PRICES-EXCLUDING IMPACT OF DERIVATIVE SETTLEMENTS (2)
Oil price per Bbl	$	50.30		$	36.46		$	27.47
Gas price per Mcf		8.48			6.24			5.66

OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1)
Oil and natural gas revenues	$	50.49		$	36.88		$	30.43


Lease operating expenses	$	9.98		$	7.22		$	7.06
Production taxes and marketing expenses		2.54			1.55			1.17

Total oil and natural gas production expenses	$	12.52		$	8.77		$	8.23


(1)		Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (BOE).

(2)		See also Market Risk Management below for information concerning the Company’s derivative transactions. Effective January 1, 2005, we elected to discontinue hedge accounting for our oil and natural gas derivative contracts; see Note 9 to the Consolidated Financial Statements and “Critical Accounting Policies and Estimates – Oil and Gas Derivative Contracts” below.

(3)		For 2005 and 2004, includes transportation expenses paid to Genesis of $4.0 million and $1.2 million, respectively.

(4)		For 2005, 2004, and 2003 includes deferred revenue of $3.1 million, $2.4 million and $0.3 million respectively, associated with volumetric production payments and transportation income of $3.5 million, $2.7 million and $0.4 million, respectively, both from Genesis.

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

Production. Average daily production by area for 2003, 2004 and 2005, and each of the quarters of 2005 is listed in the following table (BOE/d).


	Average Daily Production (BOE/d)
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Operating Area	2005		2005		2005		2005		2005		2004		2003

Mississippi — non-CO2 floods		13,057		12,788		10,998		11,475		12,072		13,085		13,638

Mississippi — CO2 floods		8,644		9,417		8,850		9,939		9,215		6,784		4,671

Onshore Louisiana		6,710		5,791		5,169		6,992		6,164		7,630		8,222

Barnett Shale		1,313		2,052		2,150		3,048		2,145		587		224

Other⁽¹⁾		—		421		178		195		199		—		—


Total production excl. offshore		29,724		30,469		27,345		31,649		29,795		28,086		26,755

Offshore Gulf of Mexico — Sold July 2004		—		—		—		—		—		4,865		7,949


Total Company		29,724		30,469		27,345		31,649		29,795		32,951		34,704


(1)		Primarily represents production from an offshore property retained from the sale in July 2004.

As a result of the sale of our offshore properties in July 2004, total production decreased as listed in the above table. Adjusting for the offshore sale, overall production increased approximately 5% on a BOE/d basis during 2004 and approximately 6% during 2005, anchored by the increased production from our tertiary operations and Barnett Shale play, generally offset by overall declines in our onshore conventional properties in Mississippi and natural gas wells in Louisiana. However, other factors that caused fluctuations between the various periods should also be noted as outlined below.

During August and September, 2005, hurricanes Katrina and Rita came ashore, negatively affecting almost all of our existing production. While we did not incur any significant property damage as a result of either storm, we estimate that we deferred approximately 350,000 barrels of oil equivalent (“BOE”) of production during the third quarter of 2005 as most of our fields were shut-in for periods ranging from several days to a few weeks, primarily because of a lack of power or because of flooding. As a result, production was lower in the third quarter than in the immediately prior quarter in every area of our operations except for the Barnett Shale play in Texas. While almost all of our wells had been returned to production by late October, we estimate that we deferred an additional 500 BOE/d of production in the fourth quarter as a result of the two hurricanes. In the aggregate, the deferred production from the two hurricanes lowered our 2005 average annual production rate by almost 1,100 BOE/d.

Most of the non-CO₂ fields in Mississippi have been on a slight decline during the last few years as a result of normal depletion. Heidelberg Field, our single largest field, which is located in this area, has partially offset this decline, as its production increased from 2003 to 2004, then declined slightly in 2005. Heidelberg production averaged 7,535 BOE/d during 2003, 7,775 BOE/d during 2004, and 7,312 BOE/d during 2005. Most production increases at Heidelberg are attributable to additional natural gas drilling in the Selma Chalk formation as Heidelberg’s oil production has been slowly decreasing. Natural gas production at this field averaged 10.3 MMcf/d in 2003, 13.8 MMcf/d in 2004, and 14.1 MMcf/d in 2005, making Heidelberg Field our single largest natural gas producing field during 2005.

As more fully discussed in “CO₂ Operations” above, oil production from our tertiary operations has increased each year.

While our onshore Louisiana annual production average is less in 2005 than in 2004, as a result of drilling 19

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

successful wells during 2005 (including wells completed in January 2006), production increased in Louisiana during the fourth quarter of 2005 as compared to the prior quarters. As a result, we expect our 2006 average production in Louisiana to be higher than in 2005. Production in this area, predominately natural gas, is relatively short-lived in nature and can decline rapidly unless offset by new wells. As an example, Thornwell Field, an onshore Louisiana field, has been particularly volatile, averaging 2,487 BOE/d during 2003, 1,487 BOE/d during 2004, reaching a three-year low of 649 BOE/d during the second quarter of 2005, but then increasing to 2,169 BOE/d during the fourth quarter of 2005 as a result of our drilling two successful wells during 2005. In spite of its short life and volatile production, we have generated a good return on investment at Thornwell, generating $43.5 million of net positive cash flow (operating revenues less operating expenses and capital expenditures) through December 31, 2005, with a remaining PV-10 Value of $132.5 million as of December 31, 2005 (based on SEC proved reserve report at year-end 2005 prices).

Natural gas production in the Barnett Shale has increased as a result of increased drilling activity in 2004 and 2005 and the acquisition of additional interests during the second quarter of 2005 that added approximately 1.5 MMcf/d of production. These wells are characterized by steep decline rates in their first year of production (as much as 50% to 60%), followed by a gradual leveling-off of production and a resultant slow decline rate, giving them an overall long production life. Natural gas production in this area is expected to further increase throughout 2006 as we anticipate drilling 45 to 50 wells in this area during 2006. We currently have four rigs running in this area.

Our production for 2005 was weighted toward oil (67%) and we expect a similar weighting toward oil in 2006 due to our increasing emphasis on tertiary operations, unless we make an acquisition that is predominantly natural gas.

Oil and Natural Gas Revenues. Our oil and natural gas revenues have increased for each of the last two years, primarily as a result of higher commodity prices, offset in part by lower production as a result of the sale of offshore properties. Between 2004 and 2005, revenues increased by 23%. The overall increase in commodity prices contributed $148.0 million in additional revenues, a 33% increase, partially offset by an overall decrease of $43.7 million (a 10% decrease) related to the 10% lower production volumes. Between 2003 and 2004, revenues increased by 15%. The overall increase in commodity prices contributed $77.8 million in additional revenues, a 20% increase; partially offset by an overall decrease in revenues of $18.5 million (a 5% decrease) related to the 5% lower production volumes.

During 2005, we made payments on our derivative contracts of $16.8 million, down from $84.6 million paid out during the prior year. Our 2005 payments related to a natural gas collar, lowering our effective net natural gas price by $0.78 per Mcf. During 2004, we paid out $64.1 million on our oil hedges ($9.10 per Bbl) and $20.4 million ($0.68 per Mcf) on our natural gas hedges relating to swaps and collars we purchased one to two years earlier when commodity prices were lower. About $30.5 million of the hedge payments related to swaps originally put in place to protect the rate of return for the COHO acquisition in August 2002. The payments in 2003 were similar in nature, but slightly less due to lower overall commodity prices. During 2003, we paid out $20.3 million on our oil hedges ($2.95 per Bbl) and $41.9 million ($1.21 per Mcf) on our natural gas hedges on generally the same type of swaps and collars. For 2006, we have hedged a lower percentage of our overall production, so we do not anticipate that our payments on our derivative contracts will reach the levels seen during 2003 and 2004. See “Market Risk Management” for a further discussion of our derivative activities.

Our net oil and natural gas prices have increased each year as outlined in the above table. These prices would have been even higher if our net price would have increased as much as NYMEX prices. During 2004 and continuing into 2005, the discount for our heavier, sour crude (which predominantly applies to our Eastern Mississippi production) increased significantly, lowering our overall net price relative to NYMEX. Our net oil price averaged $3.60 below NYMEX during 2003, increased to $4.91 during 2004, and further increased to $6.33 during 2005. This occurred in spite of our increasing light sweet oil production from our Phase I tertiary operations, which should have improved our overall net price as such crude receives near NYMEX prices and is becoming a higher percentage of our overall production. However, as evident in 2004 and 2005, the oil market is subject to significant and sudden changes and it is difficult to forecast these trends, although our experience indicates that the discount or NYMEX differential for our heavier sour crude increases as NYMEX oil prices increase.

During 2003 and 2004, there was less fluctuation in our natural gas prices relative to NYMEX. During both of those years, our net natural gas prices were at, or slightly above, the quoted NYMEX prices, primarily because of

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

the high Btu content of our natural gas and the close proximity of our Louisiana natural gas production to Henry Hub. For 2003, we had an average $0.18 premium to NYMEX and for 2004, had a $0.02 premium to NYMEX. During 2005, our natural gas price averaged $0.49 below NYMEX, primarily due to the increasing natural production in the Barnett Shale area, which averaged $1.82 per Mcf below NYMEX. The NYMEX differential in this area appears to increase with higher natural gas prices; plus, the production in this area is growing and is expected to increase again during 2006. Although these factors could change depending on the overall natural gas market, we would expect these factors to gradually reduce our overall net natural gas price relative to NYMEX in the near future.

Operating Expenses. Our lease operating expenses increased on both a per BOE basis and in total dollars primarily as a result of (i) our increasing emphasis on tertiary operations (see discussion of those expenses under “CO₂ Operations” above), (ii) general cost inflation in our industry, (iii) increased personnel and related costs, (iv) higher fuel and energy costs to operate our properties, (v) increasing lease payments for certain of our tertiary operating facilities, and (vi) higher workover costs. During 2005, operating costs averaged $9.98 per BOE, up from $7.22 per BOE in 2004 and $7.06 per BOE during 2003. Operating expenses on our tertiary operations increased from $19.3 million in 2003 to $24.6 million during 2004 and $40.4 million during 2005, as a result of the increased tertiary activity level. Tertiary operating expenses were particularly impacted by the higher power and energy costs, higher costs for CO₂ and payments on leased facilities and equipment (see “CO₂ Operations” above). We expect this increase in tertiary operating costs to continue and to further increase our cost per BOE as they become a more significant portion of our total production and operations.

Workover expenses increased by over $3.5 million during 2005 as compared to 2004, with over one-half of the increase relating to costs to repair a mechanical failure on one onshore Louisiana well. Workover expenses were also high in 2003 when we spent $2.8 million on two individually significant workovers relating to mechanical failures of two onshore Louisiana wells, plus several smaller workovers.

Production taxes and marketing expenses generally change in proportion to commodity prices and therefore were higher each year along with the increasing commodity prices. The sale of our offshore properties also contributed to the increase in production taxes and marketing expenses on a per BOE basis during 2004 and 2005, as most of our offshore properties were tax exempt. We also recognized incremental transportation expenses paid by us to Genesis as a result of a change in the way we market our crude oil. Beginning in September 2004, we commenced using Genesis as a transporter rather than a purchaser. This incremental transportation cost is approximately $1.0 million per quarter, but is more than offset by higher oil revenue and this change in the way we do business has given us a higher gross margin.

General and Administrative Expenses

During the last three years, general and administrative (G&A) expenses on a per BOE basis have increased from $1.20 per BOE during 2003, to $1.78 per BOE during 2004, to $2.62 per BOE during 2005, increasing even faster than the gross aggregate dollar increases in G&A expense as production has declined each year due primarily to the sale of our offshore properties.


	Year Ended December 31,
Amounts in Thousands Except Per BOE and Employee Data	2005			2004			2003

Gross G&A expense	$	64,622		$	53,658		$	46,031
Operator overhead charges		(32,452	)		(28,048	)		(26,823	)
Capitalized exploration expense		(5,084	)		(5,072	)		(5,507	)

		27,086			20,538			13,701
State franchise taxes		1,454			923			1,488

Net G&A expense	$	28,540		$	21,461		$	15,189

Average G&A expense per BOE	$	2.62		$	1.78		$	1.20
Employees as of December 31		460			380			374

Gross G&A expenses increased $11.0 million, or 20%, between 2004 and 2005. This increase is generally attributable to higher compensation costs due to additional employees (80 employees were added during 2005), wage increases and $4.1 million of non-cash compensation expense for the amortization of deferred compensation associated with the issuance of restricted stock to officers and directors in 2004 and 2005, as compared to $1.6

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

million during 2004 (see below). We also incurred approximately $1.4 million to provide food, water, gasoline, and other essential supplies to our employees and charitable organizations in Mississippi and Louisiana following the hurricanes. In addition, we incurred higher professional service and consultant fees primarily related to Sarbanes-Oxley compliance, investigation of hotline reports, and documentation and testing of our new software system that we began using in January 2005, as well as increased maintenance costs as a result of the change to our new software system. These 2005 increases were offset by the absence of approximately $2.4 million of employee severance payments paid in 2004 related to the sale of our offshore properties in July 2004.

Gross G&A expenses increased $7.6 million, or 17%, between 2003 and 2004. The largest component of the increase was approximately $2.4 million of employee severance payments for the offshore professional and technical staff terminated in conjunction with our offshore property sale. We also incurred additional G&A expenses associated with our corporate restructuring in December 2003, compliance with the requirements of the Sarbanes-Oxley Act, the sale of stock by the Texas Pacific Group in March 2004, a provision for potential litigation losses, amortization of restricted stock grants, higher bonus levels for employees than in 2003 due to the strong performance during 2004, and overall increases in most other categories of G&A due to general cost inflation.

From August 2004 through January 2005, we granted a total of 2.3 million shares of restricted stock to our officers and independent directors, generating deferred compensation expense of approximately $23.6 million, the market value of the shares on the date of grant. Approximately 65% of this restricted stock vests over five years and the balance upon retirement (in addition to vesting upon death, disability or a change of control). We are amortizing the non-cash $23.6 million of compensation expense over the five-year vesting period and over the projected retirement date vesting period, expensing approximately $1.6 million during 2004 and $4.1 million during 2005.

Higher operator overhead recovery charges resulting from the incremental development activity helped to partially offset the increase in gross G&A, partially reduced by the impact of the offshore property sale. Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. As a result of the additional operated wells from acquisitions, additional tertiary operations, and drilling activity during the past year, the amount we recovered as operator overhead charges increased by 5% between 2003 and 2004 and 16% between 2004 and 2005. Capitalized exploration costs decreased in 2004 as a result of the personnel reductions in our offshore area related to the property sale and remained essentially flat in 2005 due to additional personnel and related cost increases. The net effect of the increases in gross G&A expenses, operator overhead recoveries and capitalized exploration costs was a 41% increase in net G&A expense between 2003 and 2004 and a 33% increase between 2004 and 2005. The increase was even higher on a per BOE basis as a result of lower production, primarily related to the offshore property sale.

Interest and Financing Expenses


	Year Ended December 31,
Amounts in Thousands Except Per BOE Data	2005			2004			2003

Cash interest expense	$	18,800		$	18,506		$	21,950
Non-cash interest expense		827			962			1,251
Less: Capitalized interest		(1,649	)		—			—

Interest expense	$	17,978		$	19,468		$	23,201

Interest and other income	$	3,218		$	2,388		$	1,573

Average net cash interest expense per BOE (1)	$	1.28		$	1.34		$	1.61
Average debt outstanding	$	248,825		$	270,770		$	341,496
Average interest rate (2)		7.6	%		6.8	%		6.4	%


(1)		Cash interest expense less capitalized interest and other income on a BOE basis.
(2)		Includes commitment fees but excludes amortization of debt issue costs.

Interest expense for 2005 decreased from 2004 levels primarily due capitalized interest of $1.6 million relating to the construction of our CO₂ pipeline to East Mississippi. As a result of the lower production because of the 2004 offshore sale and production deferred as a result of the two hurricanes, interest expense on a per BOE basis was not as positive as it was on an absolute basis.

Interest expense for 2004 decreased from 2003 levels primarily due to lower average debt levels as a result of our $50 million reduction in debt during 2003 and the payoff of our bank debt in the third quarter of 2004 with the

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

proceeds from our offshore property sale. Our non-cash interest expense in 2004 decreased as a result of the subordinated debt refinancing in March 2003, which eliminated the amortization of discount on our old subordinated debt originally issued in 1998, which was higher than the discount and related amortization on our new subordinated debt issue issued in 2003. Interest and other income increased as a result of the cash generated from the offshore property sale.

Depletion, Depreciation and Amortization (“DD&A”)


	Year Ended December 31,
Amounts in Thousands, Except Per BOE Data	2005		2004		2003

Depletion and depreciation of oil and natural gas properties	$	88,949	$	88,505	$	87,842
Depletion and depreciation of CO2 assets		5,334		4,664		2,542
Asset retirement obligations		1,682		2,408		2,852
Depreciation of other fixed assets		2,837		1,950		1,472

Total DD&A	$	98,802	$	97,527	$	94,708

DD&A per BOE:
Oil and natural gas properties	$	8.34	$	7.54	$	7.16
CO2 assets and other fixed assets		0.75		0.55		0.32

Total DD&A cost per BOE	$	9.09	$	8.09	$	7.48

Our proved reserves increased from 128.2 MMBOE as of December 31, 2003, to 129.4 MMBOE as of December 31, 2004, even after adjusting for approximately 16.5 MMBOE of proved reserves, primarily related to the offshore sale that took place in mid-2004. Our proved reserves further increased to 152.6 MMBOE as of December 31, 2005. Reserve quantities and associated production are only one side of the DD&A equation, with capital expenditures less accumulated depletion, asset retirement obligations less related salvage value, and projected future development costs making up the remainder of the calculation.

We adjust our DD&A rate each quarter based on any changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. Our DD&A rate on a per BOE basis increased 12% between 2004 and 2005, primarily due to rising costs and increases in capital spending. During 2005, we spent approximately $71.0 million on acquisitions, of which approximately $50.1 million was included in our full cost pool, with the balance becoming part of our unevaluated properties. Due to high commodity prices, the acquisition cost per BOE was around $14.60 per BOE, contributing to the higher DD&A rate. In addition, most of our future development cost estimates on our proved undeveloped reserves have been increased to reflect the rising costs in the industry.

Our DD&A rate on a per BOE basis increased 8% between 2003 and 2004, primarily due to the higher percentage of expenditures on offshore properties during 2003 and the first six months of 2004, which have historically had higher overall finding and development costs, and an increase in certain of our future development cost estimates to reflect the rising costs in the industry. Although the 2004 average DD&A rate was similar to the DD&A rate of $8.00 per BOE during the fourth quarter of 2003, there were significant fluctuations during the year resulting from the offshore sale (as the sales proceeds were credited to the full cost pool) and upward adjustments in future development costs primarily to reflect cost inflation in the industry.

Our DD&A rate for our CO₂and other fixed assets increased in 2004 and 2005 as a result of the additional cost incurred drilling CO₂wells during each year and higher associated future development costs, partially offset by an increase in CO₂reserves from 1.6 Tcf as of December 31, 2003, to 2.7 Tcf as of December 31, 2004, to 4.6 Tcf as of December 31, 2005 (100% working interest basis before amounts attributable to Genesis volumetric production payments — see “CO₂ Operations — CO₂ Resources”).

As part of the requirements of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, with a corresponding capitalized amount. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. On an undiscounted basis, we estimated our retirement obligations as of December 31, 2003, to be $82.7 million, with an estimated salvage value of $43.3 million, also on an undiscounted basis. As of December 31, 2004, we estimated our retirement obligations to be $52.1 million ($21.5 million present

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

value), with an estimate salvage value of $43.6 million, the decrease related to the sale of our offshore properties in July 2004. As of December 31, 2005, we estimated our retirement obligations to be $69.1 million ($27.1 million present value), with an estimate salvage value of $50.2 million, the increase related to our increased activity and higher cost estimates due to the inflation in our industry. DD&A is calculated on the increase to oil and natural gas and CO₂ properties, net of estimated salvage value. We also include the accretion of discount on the asset retirement obligation in our DD&A expense.

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. We did not have any full cost pool ceiling test write-downs in 2003, 2004 or 2005 and do not expect to have any such write-downs in the foreseeable future at current commodity price levels.

Income Taxes


	Year Ended December 31,
Amounts in Thousands, Except Per BOE Amounts	2005			2004			2003

Current income tax expense (benefit)	$	27,177		$	22,929		$	(91	)
Deferred income tax provision		54,393			16,463			26,303

Total income tax provision	$	81,570		$	39,392		$	26,212

Average income tax provision per BOE	$	7.50		$	3.27		$	2.07
Net effective tax rate		32.9	%		32.3	%		32.7	%
Federal tax net operating loss carryforwards	$	—		$	—		$	94,955
Total net deferred tax asset (liability)		(129,474	)		(71,936	)		(43,539	)

Our income tax provision for 2004 and 2005 was based on an estimated statutory tax rate of 39%, and for 2003 was based on an estimated statutory tax rate of 38%. Our net effective tax rate was lower than our estimated statutory rates due primarily to our enhanced oil recovery (“EOR”) tax credits we earn related to our tertiary operations and to a lesser degree, to a new manufacturing deduction that became allowable in 2005 for oil and gas producing activities covered by the American Jobs Creation Act of 2004. Our current income tax expense represents anticipated cash payment due to alternative minimum taxes. During the third quarter of 2004, we recognized approximately $21.0 million of current income taxes as a result of the sale of our offshore properties, which was a gain for income tax purposes. The taxes on the offshore sale were primarily alternative minimum taxes as we were able to offset the related regular tax with our net operating loss carryforwards.

As of December 31, 2005, we had utilized all of our federal tax net operating loss carryforwards, but had an estimated $42.1 million of enhanced oil recovery credits to carry forward. Since the ability to earn additional enhanced oil recovery credits is reduced or even eliminated based on the level of oil prices, we do not expect to earn any EOR credits during 2006 because of the high oil prices during 2005, which we estimate will raise our effective tax rate. We will be able to utilize the EOR credit carryforwards in the future to reduce our cash taxes. If oil prices remain at current levels or increase further in the future, we will not earn any additional EOR credits and once our existing EOR credits are utilized, our cash taxes will also increase.

Results of Operations on a per BOE Basis

The following table summarizes the cash flow, DD&A and results of operations on a per BOE basis for the comparative periods. Each of the individual components is discussed above.

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


	Year Ended December 31,
Per BOE Data	2005			2004			2003

Oil and natural gas revenues	$	50.49		$	36.88		$	30.43
Loss on settlements of derivative contracts		(1.54	)		(7.01	)		(4.91	)
Lease operating expenses		(9.98	)		(7.22	)		(7.06	)
Production taxes and marketing expenses		(2.54	)		(1.55	)		(1.17	)

Production netback		36.43			21.10			17.29
CO2 operating margin		0.54			0.41			0.51
General and administrative expenses		(2.62	)		(1.78	)		(1.20	)
Net cash interest expense		(1.28	)		(1.34	)		(1.61	)
Current income taxes and other		(1.50	)		(1.78	)		(0.01	)
Changes in assets and liabilities relating to operations		1.62			(2.63	)		0.62

Cash flow from operations		33.19			13.98			15.60
DD&A		(9.09	)		(8.09	)		(7.48	)
Deferred income taxes		(5.00	)		(1.37	)		(2.08	)
Non-cash derivative adjustments		(1.12	)		(0.11	)		0.28
Changes in assets and liabilities, loss on early retirement of debt, change in accounting principle and other non-cash items		(2.67	)		2.43			(1.86	)

Net income	$	15.31		$	6.84		$	4.46

Market Risk Management

We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. The following table presents the carrying and fair values of our debt, along with average interest rates. We had no bank debt outstanding as of December 31, 2005, but had $100 million outstanding at February 15, 2006. The fair value of the subordinated debt is based on quoted market prices. None of our debt has any triggers or covenants regarding our debt ratings with rating agencies.


	Maturity Dates	Carrying		Fair
Amounts in Thousands	2006-2010	Value		Value

Fixed rate debt:
Senior Subordinated Notes due 2013, net of discount	$—	$	223,591	$	228,375
(The interest rate on the subordinated debt is a fixed rate of 7.5%.)

Senior Subordinated Notes due 2015	$—	$	150,000	$	152,250
(The interest rate on the subordinated debt is a fixed rate of 7.5%.)

From time to time, we enter into various derivative contracts to hedge our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. Historically, we hedged up to 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt. For 2005 and beyond, we have entered into fewer derivative contracts, primarily because of our strong financial position resulting from our lower levels of debt relative to our cash flow from operations.

When we make a significant acquisition, we generally attempt to hedge a large percentage, up to 100%, of the forecasted proved production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. As of December 31, 2005, the only derivative contracts we have in place relate to the $248 million acquisition that closed on January 31, 2006, on which we entered into contracts to cover 100% of the estimated proved producing production at the time we signed the purchase and sale agreement. While these derivative contracts related to the acquisition represent less than 6% of our estimated 2006 production, they are intended to help protect our acquisition economics related to the first three years of production from the proved producing reserves that we acquired. These swaps cover 2,200 Bbls/d for 2006 at a price of $59.65 per Bbl; 2,000 Bbls/d for 2007 at a price of $58.93 per Bbl; and 2,000 Bbls/d for 2008 at a price of $57.34 per Bbl.

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

All of the mark-to-market valuations used for our financial derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. For a full description of our derivative contract positions at year-end 2005, see Note 9 to the Consolidated Financial Statements.

Effective January 1, 2005, we elected to de-designate our existing derivative contracts as hedges and to account for them as speculative contracts going forward. This means that any changes in the fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings. During 2005, we amortized the December 31, 2004, balance in Accumulated Other Comprehensive Loss as that was the remaining life of those contracts. Information regarding our current derivative contract positions and results of our historical derivative activity is included in Note 9 to the Consolidated Financial Statements.

At December 31, 2005, our derivative contracts were recorded at their fair value, which was a net liability of approximately $9.4 million, a larger liability than the $4.9 million fair value liability recorded as of December 31, 2004. This change is the result of higher commodity prices, partially offset by the expiration of several of our derivative contracts during 2005 due to the passage of time. During 2005, we recognized total expense related to our hedge contracts of $29.0 million, consisting of $16.8 million cash payments, $4.5 million of expense relating to market-to-market non-cash adjustments, and $7.7 million of expense related to amortization of Other Comprehensive Loss.

Based on NYMEX crude oil futures prices at December 31, 2005, we would expect to make future cash payments of $10.5 million on our crude oil commodity derivative contracts. If crude oil futures prices were to decline by 10%, we would expect to receive a payment under our crude oil commodity derivative contracts of $3.9 million, and if futures prices were to increase by 10% we would expect to pay $24.8 million. We did not have any NYMEX natural gas commodity derivative contracts outstanding at December 31, 2005.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with generally accepted accounting principles requires that we select certain accounting policies and make certain estimates and judgments regarding the application of those policies. Our significant accounting policies are included in Note 1 to the Consolidated Financial Statements. These policies, along with the underlying assumptions and judgments by our management in their application, have a significant impact on our consolidated financial statements. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our financial statements.

Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Reserves

Businesses involved in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and gas industry. We apply the full-cost method of accounting for our oil and natural gas properties. Another acceptable method of accounting for oil and gas production activities is the successful efforts method of accounting. In general, the primary differences between the two methods are related to the capitalization of costs and the evaluation for asset impairment. Under the full-cost method, all geological and geophysical costs, exploratory dry holes and delay rentals are capitalized to the full cost pool, whereas under the successful efforts method such costs are expensed as incurred. In the assessment of impairment of oil and gas properties, the successful efforts method follows the guidance of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” under which the net book value of assets are measured for impairment against the undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the full cost pool (net book value of oil and gas properties) is measured against future cash flows discounted at 10% using commodity prices in effect at the end of the reporting period. The financial results for a given period could be substantially different depending on the method of accounting that an oil and gas entity applies.

In our application of full cost accounting for our oil and gas producing activities, we make significant estimates at the end of each period related to accruals for oil and gas revenues, production, capitalized costs and operating expenses. We calculate these estimates with our best available data, which includes, among other things,

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

production reports, price posting, information compiled from daily drilling reports and other internal tracking devices and analysis of historical results and trends. While management is not aware of any required revisions to its estimates, there will likely be future adjustments resulting from such things as changes in ownership interests, payouts, joint venture audits, re-allocations by the purchaser/pipeline, or other corrections and adjustments common in the oil and natural gas industry, many of which will require retroactive application. These types of adjustments cannot be currently estimated or determined and will be recorded in the period during which the adjustment occurs.

Under full cost accounting, the estimated quantities of proved oil and natural gas reserves used to compute depletion and the related present value of estimated future net cash flows therefrom used to perform the full-cost ceiling test have a significant impact on the underlying financial statements. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepare the report, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statement disclosures. Over the last four years, Denbury’s annual revisions to its reserve estimates have averaged approximately 3% of the previous year’s estimates and have been both positive and negative.

Changes in commodity prices also affect our reserve quantities. For instance, between 2001 and 2002, commodity prices rebounded from the prior year’s fall, resulting in an increase to our reserve quantities of approximately 3.5 MMBOE. During 2003, 2004 and 2005, the change related to commodity prices was virtually zero, less than in prior years, as prices were relatively high each year-end. These changes in quantities affect our DD&A rate and the combined effect of changes in quantities and commodity prices impacts our full-cost ceiling test calculation. For example, we estimate that a 5% increase in our estimate of proved reserves quantities would have lowered our fourth quarter 2005 DD&A rate from $9.80 per Bbl to approximately $9.39 per Bbl and a 5% decrease in our proved reserve quantities would have increased our DD&A rate to approximately $10.25 per Bbl. Also, reserve quantities and their ultimate values are the primary factors in determining the borrowing base under our bank credit facility and are determined solely by our banks.

There can also be significant questions as to whether reserves are sufficiently supported by technical evidence to be considered proven. In some cases our proven reserves are less than what we believe to exist because additional evidence, including production testing, is required in order to classify the reserves as proven. In other cases, properties such as certain of our potential tertiary recovery projects may not have proven reserves assigned to them primarily because we have not yet completed a specific plan for development or firmly scheduled such development. We have a corporate policy whereby we generally do not book proved undeveloped reserves unless the project has been committed to internally, which normally means it is scheduled within the next one to two years (or at least the commencement of the project is scheduled in the case of longer-term multi-year projects such as waterfloods and tertiary recovery projects). Therefore, particularly with regard to potential reserves from tertiary recovery (our CO₂ operations), there is uncertainty as to whether the reserves should be included as proven or not. We also have a corporate policy whereby proved undeveloped reserves must be economic at long-term historical prices, which are usually significantly less than the year-end prices used in our reserve report. This also can have the effect of eliminating certain projects being included in our estimates of proved reserves, which projects would otherwise be included if undeveloped reserves were determined to be economic solely based on current prices in a high price environment, as was the case during the last three year-ends. (See Depletion, Depreciation and Amortization under Results of Operations above for a further discussion.) All of these factors and the decisions made regarding these issues can have a significant effect on our proven reserves and thus on our DD&A rate, full-cost ceiling test calculation, borrowing base and financial statements.

Asset Retirement Obligations

We have significant obligations related to the plugging and abandonment of our oil and gas wells, and the removal of equipment and facilities from leased acreage and returning such land to its original condition. SFAS No. 143 requires that we estimate the future cost of this obligation, discount it to its present value, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the

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

required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our DD&A expense in future periods. See Note 4 to our Consolidated Financial Statements for further discussion regarding our asset retirement obligations.

Income Taxes

We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and prior to year-end 2005, net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our enhanced oil recovery credits). If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2005, we believe that all of our deferred tax assets recorded on our Consolidated Balance Sheet will ultimately be recovered. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would increase in the period it is determined that recovery is not probable. A 1% increase in our effective tax rate would have increased our calculated income tax expense by approximately $2.5 million, $1.2 million, and $0.8 million for the years ended December 31, 2005, 2004 and 2003. See Note 7 to the Consolidated Financial Statements for further information concerning our income taxes.

Oil and Gas Derivative Contracts

We enter into derivative contracts to mitigate our exposure to commodity price risk associated with future oil and natural gas production. These contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps. Under SFAS No. 133, every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized currently in earnings. If the derivative qualifies for cash flow hedge accounting, the change in fair value of the derivative is recognized in accumulated other comprehensive income (equity) to the extent that the hedge is effective and in the income statement to the extent it is ineffective.

Prior to 2005, we applied hedge accounting to our commodity derivative contracts, thereby recording a significant portion of the fair value changes to equity instead of income. We recognized losses on ineffectiveness on our hedges of $282,000 for 2003 and $2.7 million for 2004. We measured and computed hedge effectiveness on a quarterly basis. If a hedging instrument became ineffective, hedge accounting was discontinued and any deferred gains or losses on the cash flow hedge remained in accumulated other comprehensive income until the periods during which the hedges would have otherwise expired. If we determined it probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument were recognized in earnings immediately.

As of January 1, 2005, we abandoned hedge accounting. This means that any changes in the future fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the balance to earnings. While we may experience more volatility in our net income than if we had continued to apply hedge accounting treatment as permitted by SFAS No. 133, we believe that for us the benefits associated with applying hedge accounting do not outweigh the cost, time and effort to comply with hedge accounting. During 2005, we recognized expense of $4.5 million related to changes in the fair market value of our derivative contracts. For our prior two most recently completed fiscal years, if we had not chosen to designate hedge accounting treatment to our oil and natural gas derivative contracts, or if none of our derivative contracts had qualified for hedge accounting treatment, we estimate that our net income would have increased or (decreased) for 2004 and 2003 by approximately $25.0 million and $(7.8 million), respectively.

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

Use of Estimates

The preparation of financial statements requires us to make other estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and believe that the ultimate actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties and such risks and uncertainties could cause the actual results to differ materially from our estimates.

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), “Share Based Payment,” which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB 25 and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in our Consolidated Statements of Operations based on their estimated fair values.

We adopted SFAS No. 123(R) on January 1, 2006, using the modified prospective application method described in the statement. Under the modified prospective method, we will apply the standard to new awards granted or modified effective January 1, 2006. Also, we will recognize compensation expense for the unvested portion of awards outstanding as of December 31, 2005 over the remaining service periods. At January 1, 2006, we had $16.6 million of unearned compensation cost related to unvested stock option awards. This compensation cost will be recognized over the remaining vesting period, which is estimated to be approximately $8.0 million during 2006, $5.2 million during 2007, $3.1 million during 2008 and $0.3 million during 2009. These amounts do not include the impact of any new awards granted in 2006.

SFAS No. 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may serve to reduce Denbury’s future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future; however, it will not have an impact on the Company’s overall cash flows.

Forward-Looking Information

The statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not limited to, statements found in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, cost savings, production rates and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters, mark-to-market values, competition and long-term forecasts of production, finding cost, rates of return, estimated costs, future capital expenditures and overall economics and other variables surrounding our tertiary operations and future plans. Such forward-looking statements generally are accompanied by words such as plan, estimate, expect, predict, anticipate, projected, should, assume, believe, “target” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company’s financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or


		Page
	Glossary and Selected Abbreviations		3

	PART I

Item 1.	Business		4
Item 1A.	Risk Factors		19
Item 1B.	Unresolved Staff Comments		23
Item 2.	Properties		23
Item 3.	Legal Proceedings		23
Item 4.	Submission of Matters to a Vote of Security Holders		24

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		25
Item 6.	Selected Financial Data		27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
Item 7A.	Quantitive and Qualitive Disclosures About Market Risk		49
Item 8.	Financial Statements and Supplementary Data		49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		86
Item 9A.	Controls and Procedures		86
Item 9B.	Other Information		87

	PART III

Item 10.	Directors and Executive Officers of the Company		88
Item 11.	Executive Compensation		88
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		88
Item 13.	Certain Relationships and Related Transactions		88
Item 14.	Principal Accountant Fees and Services.		89

	PART IV

Item 15.	Exhibits and Financial Statement Schedules		89
	Signatures		92
Second Amendment to 5th Amended and Restated Credit Agreement
Amendment for Increased Commitment to 5th Amended and Restated Credit Agreement
Description of Cash Bonus Compensation Arrangements
Description of Equity and Other Long-term Award Grant Practices
Description of Non-employee Directors' Compensation Arrangements
Form of Stock Appreciation Rights Agreement
Form of Stock Appreciation Rights Agreement
Form of Stock Appreciation Rights Agreement
Form of Restricted Stock Award
Form of Restricted Stock Award
Form of Deferred Payment Cash Award
Form of Deferred Payment Cash Award
List of Subsidiaries
Consent of PricewaterhouseCoopers LLP
Consent of Deloitte & Touche LLP
Consent of DeGolyer and MacNaughton
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906
Summary of DeGoyler and MacNaughton's Report