UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2008 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, 2008
	OR
o		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

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 1200, Plano, TX		75024
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code:		(972) 673-2000

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

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

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

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company. See definition of “large accelerated filer”, “accelerated filer”, and “small reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o

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

The aggregate market value of the registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter was $6,251,312,368.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2009, was 248,411,326.

DOCUMENTS INCORPORATED BY REFERENCE

Document:				Incorporated as to:
1.		Notice and Proxy Statement for the Annual Meeting of Shareholders to be held May 13, 2009.		1.		Part III, Items 10, 11, 12, 13, 14

 

 

Denbury Resources Inc.
2008 Annual Report on Form 10-K
Table of Contents

				Page
		Glossary and Selected Abbreviations			3
		PART I
Item 1.		Business			4
Item 1A.		Risk Factors			22
Item 1B.		Unresolved Staff Comments			28
Item 2.		Properties			28
Item 3.		Legal Proceedings			28
Item 4.		Submission of Matters to a Vote of Security Holders			28
		PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			29
Item 6.		Selected Financial Data			31
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			58
Item 8.		Financial Statements and Supplementary Data			58
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			99
Item 9A.		Controls and Procedures			99
Item 9B.		Other Information			99
		PART III
Item 10.		Directors, Executive Officers and Corporate Governance			100
Item 11.		Executive Compensation			100
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			100
Item 13.		Certain Relationships and Related Transactions, and Director Independence			100
Item 14.		Principal Accountant Fees and Services			100
		PART IV
Item 15.		Exhibits and Financial Statement Schedules			100
		Signatures			104
EX-10.(d)
EX-10.(n)
EX-10.(o)
EX-21
EX-23.(a)
EX-23.(b)
EX-31.(a)
EX-31.(b)
EX-32
EX-99

Denbury Resources Inc.

Glossary and Selected Abbreviations

Bbl		One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bbls/d		Barrels of oil produced per day.
Bcf		One billion cubic feet of natural gas or CO2.
Bcfe		One billion cubic feet of natural gas equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
BOE		One barrel of oil equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
BOE/d		BOEs produced per day.
Btu		British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
CO2		Carbon dioxide.
Finding and Development     Cost		The average cost per BOE to find and develop proved reserves during a given period. It is calculated by dividing costs, which includes the total acquisition, exploration and development costs incurred during the period plus future development and abandonment costs related to the specified property or group of properties, by the sum of (i) the change in total proved reserves during the period plus (ii) total production during that period.
MBbls		One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE		One thousand BOEs.
Mbtu		One thousand Btus.
Mcf		One thousand cubic feet of natural gas or CO2.
Mcf/d		One thousand cubic feet of natural gas or CO2 produced per day.
Mcfe		One thousand cubic feet of natural gas equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
Mcfe/d		Mcfes produced per day.
MMBbls		One million barrels of crude oil or other liquid hydrocarbons.
MMBOE		One million BOEs.
MMBtu		One million Btus.
MMcf		One million cubic feet of natural gas or CO2.
MMcf/d		One million cubic feet of natural gas or CO2 per day.
MMcfe		One thousand Mcfe.
MMcfe/d		MMcfes produced per day.
PV-10 Value		When used with respect to oil and natural gas reserves, PV-10 Value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs and abandonment, using prices and costs in effect at the determination date, and before income taxes, discounted to a present value using an annual discount rate of 10%. PV-10 Value is a non-GAAP measure and its use is further discussed in footnote 3 to the table on page 21.
Proved Developed     Reserves*		Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves*		The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped     Reserves*		Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
Tcf		One trillion cubic feet of natural gas or CO2.

Denbury Resources Inc.

PART I

Item 1. Business

Website Access to Reports

     We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge on or through our Internet website, www.denbury.com , as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

The Company

     Denbury Resources Inc. is a Delaware corporation organized under Delaware General Corporation Law (“DGCL”) and is engaged in the acquisition, development, operation and exploration of oil and natural gas properties in the Gulf Coast region of the United States, primarily in Mississippi, Louisiana, Texas and Alabama. Our corporate headquarters is located at 5100 Tennyson Parkway, Suite 1200, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2008, we had 797 employees, 493 of whom were employed in field operations or at the field offices. Our employee count does not include the approximately 610 employees of Genesis Energy, LLC as of December 31, 2008, 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 where we have a competitive advantage as a result of our CO2 reserves and expanding infrastructure, or where we believe we can ultimately obtain it;
	•		acquire properties where we believe additional value can be created through tertiary recovery operations and a combination of other exploitation, development, exploration and marketing techniques;
	•		acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it;
	•		maximize the value of our properties by increasing production and reserves while controlling cost; and

•

maintain a highly competitive team of experienced and incentivized personnel.

Denbury Resources Inc.

Acquisitions

     Information as to recent acquisitions and divestitures by Denbury is set forth under Note 2, “Acquisitions and Divestitures,” to the Consolidated Financial Statements.

Oil and Gas Operations

Our CO₂ Assets

     Overview. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999, we have gradually increased our emphasis on these types of operations. During this time, we have learned a considerable amount about tertiary operations and working with carbon dioxide. Our tertiary operations have grown to the point that approximately 50% of our December 31, 2008 proved reserves are proved tertiary oil reserves, almost 50% of our forecasted 2009 production is expected to come from tertiary oil operations (on a BOE basis), and almost all of our 2009 capital expenditures are related to our current or future tertiary operations. We particularly like this play as (i) it has a lower risk and is more predictable than most traditional exploration and development activities, (ii) it provides a reasonable rate of return at relatively low oil prices (we estimate our economic per barrel dollar cost on these projects at current oil prices is in the range of the mid-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 CO₂ except our own, and these large volumes of CO₂ that we own drive the play. In addition, we are pursuing anthropogenic (man-made) sources of CO₂ to use in our tertiary operations, which we believe will not only help us recover additional oil, but will provide an economical way to sequester CO₂. We have acquired several old oil fields in our areas of operations with potential for tertiary recovery and plan to acquire additional fields, and we are continuing to expand our CO₂ pipeline infrastructure to transport CO₂.

     During 2008, we added 63.4 MMBbls of tertiary-related proved oil reserves, primarily initial proven tertiary oil reserves at Heidelberg Field (Phase II), Tinsley Field (Phase III) and Lockhart Crossing Field (Phase I) (see discussion of the individual fields below), increasing our proved tertiary oil reserves from 69.5 MMBbls at December 31, 2007 to 125.8 MMBbls as of December 31, 2008. In order to recognize proved tertiary oil reserves, we must either have an oil production response to the CO₂ injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the associated production response.

     We believe that CO₂ is one of the most efficient tertiary recovery mechanisms for crude oil. The CO₂ acts somewhat like a solvent for the oil, removing it from the oil-bearing formation as the CO₂ passes through the rock. CO₂ tertiary floods are unique because they require large volumes of CO₂, the location of which, to our knowledge, is limited to a few geological basins, one of which is our source near Jackson, Mississippi. Further, the most efficient way to transport CO₂ is via dedicated pipelines, which are also in limited supply. Because the sources and methods of transportation of CO₂ are limited, only 5% or approximately 250,000 Bbls/d of the United States domestic oil production is derived from tertiary recovery projects.

     Our CO₂ source field, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s while being explored for hydrocarbons. This significant source of CO₂ is the only known one of its kind in the United States east of the Mississippi River. Mississippi’s first enhanced oil recovery project began in the mid 1980s in Little Creek Field following the installation of Shell Oil Company’s Choctaw CO₂ Pipeline. The 183-mile Choctaw Pipeline (now referred to as NEJD Pipeline) transported CO₂ produced from Jackson Dome to Little Creek Field. While the CO₂ flood proved successful in recovering significant amounts of oil, commodity prices at that time made the project unattractive for Shell and they later sold their oil fields in this area, as well as the CO₂ source wells and pipeline.

     While enhanced oil recovery (“EOR”) projects utilizing CO₂ may not be considered a new technology, Denbury applies several additional technologies to the fields: well evaluations, new completion or stimulation techniques, operating equipment and seismic interpretations. We began our CO₂ operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson Dome CO₂ reserves and NEJD pipeline in 2001. Based upon our success at Little Creek, we embarked upon a strategic program to improve our understanding and knowledge of CO₂ production and tertiary recovery to build a dominant position in this enhanced oil play.

Denbury Resources Inc.

     Tertiary Recovery Phases. We categorize our tertiary operations by labeling operating areas or groups of fields as phases. Phase I includes several fields along our 183-mile NEJD CO₂ Pipeline that runs through southwest Mississippi and into Louisiana. The most significant fields in this area are Little Creek, Mallalieu, McComb, and Brookhaven Fields, all fields which have been producing oil for some time, and one of our newest enhanced oil fields, Lockhart Crossing Field. We saw our first tertiary oil production from Lockhart Crossing Field, located in South Louisiana, during 2008. Lockhart Crossing, although a relatively small field, is the first of three fields we plan to CO₂ flood in Louisiana and is our first flood outside the state of Mississippi.

     Phase II, which began with the early 2006 completion of the Free State CO₂ Pipeline to East Mississippi, includes Eucutta, Soso, and Martinville Fields which have been producing oil for over two years, and Heidelberg Field where we started injecting CO₂ in December 2008. Tinsley Field, located northwest of Jackson, Mississippi, acquired in January 2006, is our Phase III and is serviced by that portion of the Delta CO₂ Pipeline completed in January 2008. Tinsley Field had its first oil production response in the second quarter of 2008. Phase IV includes Cranfield, where we began CO₂ injection operations during July 2008 and had our first oil production response in the first quarter of 2009, and Lake St. John Field, a project currently scheduled to commence in 2011, both fields located near the Mississippi/Louisiana border west of the Phase I fields. Phase V is Delhi Field, a Louisiana field acquired in 2006, located southwest of Tinsley Field. CO₂ injection in Phase V will begin in 2009 upon completion of the Delta CO₂ Pipeline, an 80-mile pipeline from Tinsley to Delhi. Citronelle Field in Southwest Alabama, another field acquired in 2006, is our Phase VI. Citronelle will require an extension to the Free State CO₂ Pipeline in order to commence this project, the timing of which is uncertain at this time. Our last two currently existing phases will require completion of our 320-mile Green Pipeline, which will run from Southern Louisiana to Hastings Field, south of Houston, Texas, scheduled for completion in 2010. Hastings Field, a field on which we acquired a purchase option in late 2006 and purchased in February 2009, is our Phase VII and the Seabreeze Complex, acquired in 2007, will be our Phase VIII.

     Jackson Dome. In February 2001, we acquired approximately 800 Bcf of proved producing CO₂ reserves for $42 million, a purchase that gave us control of most of the CO₂ supply in Mississippi, as well as ownership and control of a critical 183-mile CO₂ pipeline. This acquisition provided the platform to significantly expand our CO₂ tertiary recovery operations by assuring that CO₂ would be available to us on a reliable basis and at a reasonable and predictable cost. Since February 2001, we have acquired two wells and drilled 20 additional CO₂ producing wells, significantly increasing our estimated proved CO₂ reserves to approximately 5.6 Tcf as of December 31, 2008, which is almost enough for our existing and currently planned phases of operations. The estimate of 5.6 Tcf of proved CO₂ reserves is based on 100% ownership of the CO₂ reserves, of which Denbury’s net ownership (net revenue interest) is approximately 4.5 Tcf and is included in the evaluation of proved CO₂ reserves prepared by DeGolyer and MacNaughton. In discussing our available CO₂ reserves, we make reference to the gross amount of proved reserves, as this is the amount that is available both for Denbury’s tertiary recovery programs and for industrial users who are customers of Denbury and others, as Denbury is responsible for distributing the entire CO₂ production stream.

     Today, we own every producing CO₂ well in the region. Although our current proved and potential CO₂ reserves are quite large, in order to continue our tertiary development of oil fields in the area, incremental deliverability of CO₂ is needed. In order to obtain additional CO₂ deliverability, we continued our exploration efforts by completing a 136 square mile 3-dimensional seismic program during 2008. The 3-D seismic program was located west of the DRI Ice Field over existing known CO₂ fields and adjacent lead areas. The seismic data will be evaluated during 2009 with anticipated exploratory drilling in future years. During 2008 we drilled and completed five CO₂ production wells. These wells added 360 MMcf/d of CO₂ production capacity which increased the Jackson Dome total CO₂ production capacity to between 900 MMcf/d and 1.0 Bcf/d. During the fourth quarter 2008, production averaged 767 MMcf/d of CO₂, a 44% increase over levels in the fourth quarter 2007. In addition to expanding our production capacity, during 2008 we completed the installation and startup of a second train at the Barksdale dehydration facility at Jackson Dome. This expansion added 300 MMcf/d of CO₂ dehydration capacity, which increased the Jackson Dome total CO₂ dehydration capacity to approximately 1.1 Bcf/d. We also installed a pump station in Brandon, Mississippi, to boost NEJD pipeline pressure and increase CO₂ deliverability capacity in that pipeline to approximately 515 MMcf/d. In order to ensure future production rates, processing capabilities and deliverability to the main transportation pipelines, during 2009 we are constructing a 150 MMcf/d Trace Dehydration Facility, installing additional pump capacity at the Brandon Pump Station and constructing a 13-mile pipeline from the Barksdale dehydration facility to the Brandon Pump Station. This pipeline will provide additional capacity to the NEJD line by bypassing a majority of the industrial users.

Denbury Resources Inc.

     During 2008, we sold an average of 89 MMcf/d of CO₂ to commercial users, and we used an average of 548 MMcf/d for our tertiary activities. We are continuing to increase our CO₂ production, averaging 767 MMcf/d during the fourth quarter of 2008. We estimate that our planned tertiary operations will not require any significant additional deliverability through 2010.

     Man-made CO₂ sources. In addition to our natural source of CO₂, we are in discussions with the owners of several possible gasification plants which, if built, will convert coal or petroleum coke into various other fuels, with CO₂ being a significant by-product of the process. If built, these plants could provide us with significant additional sources of CO₂ in the future which would enable us to further expand our tertiary operations, although the earliest source of this manufactured CO₂ is not expected to be available to us until 2013. These plants have all been delayed due to current economic conditions and it is uncertain when, if ever, these plants will be built. We have entered into long-term commitments to purchase manufactured CO₂ from four proposed plants, which, if all four plants are built, could potentially provide us with an aggregate of 1.0 Bcf/d of CO₂, commencing in 2013. In addition to the proposed gasification plants, we have ongoing discussions underway regarding existing plants of various types that emit CO₂ and we may be able to purchase their volumes. In order to capture such volumes, we (or the plant owner) would need to install additional equipment, which include at a minimum, compression facilities. Most of these existing plants emit relatively small volumes of CO₂, generally less than the proposed gasification plants, but such volumes may still be attractive if the source is located near our proposed Green CO₂ pipeline. The cost of man-made CO₂ will likely be higher than CO₂ from our natural source, but the location of these plants could mitigate some of the incremental cost of transportation, and we believe that in the next few years Congress could enact legislation to address climate change by capping or taxing U.S. CO₂ emissions, which could ultimately increase the supply and lower our cost of man-made CO₂ for our operations by creating economic penalties for the emission of CO₂. Further, we see these sources as a possible expansion of our natural Jackson Dome source, assuming they are economic, and we believe that our potential ability to tie these sources together with pipelines will give us a significant competitive advantage over our competitors in our geographic area in acquiring additional oil fields and future potential man-made sources of CO₂. We believe that we are a likely purchaser of CO₂ produced in our area of operations because of the scale of our tertiary operations, the CO₂ pipeline infrastructure that we are continuing to develop, and the large natural source of CO₂ (Jackson Dome), which can act as a swing CO₂ source to balance our CO₂ supplies and demand.

     CO₂ pipelines. We acquired the NEJD 183-mile CO₂ Pipeline that runs from Jackson Dome to near Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome source field (see above). Construction of our Free State Pipeline was completed in 2006 and it is currently transporting CO₂ to our four existing Phase II tertiary fields in East Mississippi (Eucutta, Soso, Martinville and Heidelberg) and will also be used for our proposed projects at South Cypress Creek and other fields in Phase II.

     During 2008, we continued our expansion of our CO₂ pipeline infrastructure with the completion of the first segment of our Delta Pipeline between Jackson Dome and Tinsley Field in January (31 miles), which significantly increased the transportation capacity of CO₂ to that field. We also reconditioned and converted the natural gas pipeline we acquired from Southern Natural Gas Company in 2007 to CO₂ service, which we are currently using to transport CO₂ to our first Phase IV field, Cranfield Field. During 2008, we started construction to further extend our Delta Pipeline with a 24” 78-mile extension from Tinsley Field to Delhi Field. Completion of this segment is expected during the second quarter of 2009.

     In late 2006, we purchased an option to acquire Hastings Field, a potential tertiary flood located near Houston, Texas, which we subsequently acquired in February 2009. In order to flood Hastings Field, we are building a CO₂ pipeline from the southern end of our existing NEJD CO₂ Pipeline that terminates near Donaldsonville, Louisiana, to Hastings Field, estimated to be approximately 320 miles. Based on our latest estimates, this pipeline is expected to cost between $700 million and $750 million. During 2007, we committed to the manufacture of the 24” pipe and thereby locked-in the pipe purchase price, and acquired approximately 100-plus miles of the necessary 320 miles of right-of-way. Our efforts during 2008 were focused on engineering design, pipe manufacturing and right-of-way acquisitions. Construction of the pipeline began during November 2008 and will continue through 2010. This multi-year project is underway and in 2009 we expect elevated activity and elevated spending (especially during the first half of the year) as crews work to complete the pipeline and its connecting line to Oyster Bayou Field, east of Galveston Bay, by late 2009 or early 2010 and on to the Hastings Field by year-end 2010. Initially, we anticipate transporting CO₂ from our natural source at Jackson Dome on this line, but ultimately we expect that it will be used to ship predominately man-made (anthropogenic) sources of CO₂.

Denbury Resources Inc.

     Overall tertiary economics. When we began our tertiary operations several years ago, they were generally economic at oil prices below $20 per Bbl, although the economics varied by field. Our costs have escalated during the last few years due to general cost inflation in the industry, but we expect them to be reduced to an economic break-even dollar cost on these projects in the mid-twenties per barrel if oil prices remain at their current reduced level, dependent on the specific field. Our inception-to-date finding and development costs (including future development and abandonment costs but excluding expenditures on fields without proved reserves) for our tertiary oil fields through December 31, 2008, are approximately $11.30 per BOE. Currently, we forecast that our finding and development costs for most of our tertiary projects will average less than $10 per BOE over the life of each field, depending on the state of a particular field at the time we begin operations, the amount of potential oil, the proximity to a pipeline or other facilities, and other factors, as the finding and development costs to date do not include significant unproved potential reserves in most of the fields. Our operating costs for tertiary operations are highly dependent on commodity prices and could range from $15 to $25 per BOE over the life of each field, again depending on the field itself.

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

     Tentatively, we plan to spend approximately $52 million in 2009 in the Jackson Dome area with the intent to add additional CO₂ deliverability for future operations. Approximately $138 million in capital expenditures is budgeted in 2009 at the oil field level in Phases I through V, plus an additional $485 million for our Delta and Green CO₂ Pipelines, making our combined CO₂ related expenditures just over 90% of our projected $750 million 2009 capital budget.

Our Tertiary Oil Fields with Proved Tertiary Reserves

     On December 31, 2008, we had total tertiary-related proved oil reserves of approximately 125.8 MMBbls, consisting of 3.2 MMBbls at Little Creek Field (and surrounding smaller fields), 11.8 MMBbls at Mallalieu Field, 13.7 MMBbls at McComb and Smithdale Fields, 17.3 MMBbls at Brookhaven Field, 9.1 MMBbls at Eucutta Field, 9.0 MMBbls at Soso Field, 0.8 MMBbls at Martinville Field, 34.4 MMBbls at Tinsley, 4.0 MMBbls at Lockhart, and 22.4 MMBbls at Heidelberg. 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 21,874 Bbls/d during the fourth quarter of 2008. We expect this production to continue to increase for several years as we expand our tertiary operations to additional fields.

Phase I Fields

     Mallalieu Field. Mallalieu Field consists of two units, West Mallalieu Unit and the smaller East Mallalieu Unit. Combined they are our most prolific tertiary flood in terms of production, producing 5,056 Bbls/d during the fourth quarter 2008. In contrast to many of our existing fields, Mallalieu Field was not waterflooded prior to CO₂ injection. Therefore, we estimate that the tertiary recovery of oil from Mallalieu Field as a result of CO₂ injection could approach 25% of the original oil in place. During 2007, we increased our proved reserves in this area, raising our estimated recovery factor from 17% to 20% for this field, based on production performance to date. A total of $11.3 million was invested in this field during 2008 to drill, re-enter or recomplete wells in efforts to improve production. During the fourth quarter of 2008, we began an expansion of the central processing facility in this field, which is expected to be completed in July, 2009. The expansion of the facility will allow CO₂ recycle rates to increase from the current 160 MMcf/d to 230 MMcf/d.

     From inception through December 31, 2008, we had net positive cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Mallalieu Field of $421.0 million.

Denbury Resources Inc.

     McComb and Smithdale Fields. We commenced tertiary recovery operations in 2003 at McComb Field and started injecting CO₂ late that year. Significant development occurred during 2004 and 2005 as we expanded the nearby Olive Field CO₂ facility to handle the processing of McComb’s produced oil, water and CO₂, and developed an additional four injection patterns. The first production response occurred in the second quarter of 2004 and has generally increased since that time, averaging 1,563 Bbls/d in the fourth quarter of 2008. During 2008, we expanded the number of injection wells and increased injection pressures, resulting in significant increases in our CO₂ injections at McComb Field. The field continues to present challenges to the technical team, but we are improving our understanding of the reservoir. The technical team is working to further improve production rates by monitoring injection patterns, reworking producing wells, and using injection surveys for conformance issues within the reservoir.

     In early 2008, we had a mechanical failure in one of our best wells at Smithdale, causing a temporary decline in production. The well was redrilled and oil production was restored, averaging 529 Bbls/d in the fourth quarter of 2008. The reservoir at Smithdale is a channel and thus our drilling was based on the completion of our 2007 3-D seismic survey covering the McComb and Smithdale Fields. By utilizing the 3-D seismic data, our geoscientists are able to put our wells in optimal positions within the channels at Smithdale to maximize the aerial coverage and sweep of the CO₂ injected.

     From inception through December 31, 2008, we had not yet recovered our costs in these fields, with net negative cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from these fields of $101.2 million.

     Brookhaven Field. Our first tertiary CO₂ production response at Brookhaven Field occurred during the fourth quarter of 2005, with oil production rates averaging 125 Bbls/d during the fourth quarter of 2005. Production rates continued to generally increase throughout 2006 and 2007 as additional injection patterns have been developed. Brookhaven Field has three discrete reservoirs that are being simultaneously CO₂ flooded. Our oil production here during the fourth quarter of 2008 averaged 3,178 Bbls/d.

     During 2008, oil production increased from 3,000 to 4,500 barrels of oil per day as a result of expanded development of the CO₂ flood. Also, detailed production and reservoir evaluations identified certain areas of high permeability within the Tuscaloosa Reservoir that act as “thief zones” and take a disproportionate volume of CO₂ from the injection wells. Polymer treatments designed to reduce CO₂ injection into these “thief zones” were pumped successfully on two wells. The polymer treatments are designed to alter the injection profiles and improve the reservoir sweep efficiencies in the first and second development areas of Brookhaven Field. The injection and offsetting production results of these treatments are encouraging enough that additional treatments are planned in 2009.

     From inception through December 31, 2008, we had net positive cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Brookhaven of $4.6 million.

     Little Creek Area. The Little Creek area fields, Denbury’s most mature enhanced oil recovery project, were acquired in 1999. During the fourth quarter of 2008, production averaged 1,706 Bbls/d from the Little Creek area, which includes Lazy Creek. Production at Little Creek Field began declining during 2006 and is expected to gradually decline in the future, even though we are working to mitigate production declines by monitoring injection patterns, reworking producing wells and using injection surveys to control at which intervals the CO₂ is injected.

     A project was initiated in 2008 between Denbury, Mississippi State University, and the U.S. Department of Energy. The group is studying the process of alternating CO₂ injection with nutrient-enriched water in a CO₂ injection well to stimulate the growth and development of microbes in the reservoir. The one-year project will monitor injection pressures and offset oil samples for evidence of improved sweep efficiencies within the reservoir as a result of the growth of the microbes. If successful, the technique could be expanded to other portions of the field.

     From inception through December 31, 2008, 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 $183.5 million.

     Lockhart Crossing Field. Lockhart Crossing, located in Livingston Parish, Louisiana, is our first CO₂ project outside of Mississippi. Lockhart Crossing produces from the Wilcox formation at an average depth of 10,200’ and has similar reservoir characteristics to the Tuscaloosa formation in which we had great success with tertiary flooding at Little Creek and Mallalieu Fields.

     We initiated CO₂ injections during December 2007 after completing the six mile supply line connecting Lockhart Crossing to the NEJD Pipeline. We saw our first tertiary production there in July 2008. By the end of 2008, we had completed two of the five development phases in the field and we are using 3-D seismic data to assist us with the remaining development.

     From inception through December 31, 2008, we had not yet recovered our costs in this field, with net negative cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from this field of $59.5 million.

Denbury Resources Inc.

Phase II Fields

     Eucutta Field. The oil production response we have experienced in Eucutta has confirmed the results of the pilot project that was performed in the early 1980s. The Eutaw formation at Eucutta was unitized for water flooding in 1966 and has gone through several stages of development. During the 1980s, Amerada Hess installed an inverted 5-spot injection pilot in the First City Bank sand (one of the Eutaw sands) to test the application of CO₂ flooding. Although the pilot test only covered approximately 20 acres, the pilot was successful in recovering an additional 17% of the original oil in place within the pattern. Based on this success, we designed and constructed a CO₂ flood and facility for the Eucutta Field. Initial well work was completed and CO₂ injection started during the first quarter of 2006. The initial tertiary oil production occurred in the fourth quarter of 2006. During 2008, oil production continued to increase as the Eutaw Reservoir was more fully developed, averaging 3,538 Bbls/d during the fourth quarter of 2008. Our plans for 2009 include the development of the remaining injection patterns, along with an expansion and upgrade of the CO₂ facility. This work will be completed in early 2009, with an anticipated increase in oil production thereafter.

     At December 31, 2008, we had 9.1 MMBbls of proved reserves in the Eucutta Field attributable to the CO₂ flood based on a 13% recovery factor, which is lower than was achieved in the pilot program in the 1980s, and therefore we expect upward reserve revisions here in the future. Eucutta is analogous to Heidelberg Field in that the majority of its historical production was produced from the Eutaw formation. From inception through December 31, 2008, we had net positive cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Eucutta of $3.9 million.

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

     In 2007 we continued the development of additional patterns in both the Rodessa and Bailey intervals, and by the fourth quarter of 2007, we had our initial response from the Rodessa combined with continued response from the Bailey. In addition, a pilot CO₂ flood was initiated in the Cotton Valley Sand. We made significant additions to the CO₂ recycle facility during 2008, increasing the CO₂ purchase capacity. During the fourth quarter of 2008, production at Soso had increased to 2,704 Bbls/d.

     From inception through December 31, 2008, we had not yet recovered our costs in this field with net negative cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Soso of $67.6 million.

     Martinville Field. We initiated our first injections of CO₂ in Martinville Field during the first quarter of 2006 in both the Rodessa and Mooringsport formations. As is the case with most of the East Mississippi fields, Martinville produces from multiple reservoirs. Unlike the majority of our other planned CO₂ projects, Martinville does not contain a single large reservoir to CO₂ flood, but rather several smaller reservoirs. We completed construction of the CO₂ facilities and completed the development of the Mooringsport formation during 2006. During 2008, an additional producing well was drilled to expand the development of the Rodessa sand. A Lower Hosston “huff and puff” project was also initiated. The Lower Hosston project consists of injecting a predetermined volume of CO₂ into the reservoir, allowing the CO₂ time to disperse and contact oil, then flowing the well back and producing the oil that contacted the CO₂. Numerous cycles of injection and production are planned. We are currently in the first injection cycle on this project. During the fourth quarter of 2008 production at Martinville averaged 1,213 Bbls/d, almost all of which is from the Mooringsport.

     Although we booked minimal proved reserves in 2006 from the one responding well in the Mooringsport, in 2007 and 2008 we booked additional reserves, approximately 1.5 MMBbls and 0.8 MMBbls, respectively, in the Mooringsport and the Rodessa IX reservoir. There are several additional Rodessa reservoirs that will be developed following completion of the CO₂ flood in the Rodessa IX.

Denbury Resources Inc.

     From inception through December 31, 2008, we had not yet recovered our costs in this field with net negative cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Martinville of $6.2 million.

     The Martinville Field Wash Fred 8500’ reservoir development continues to evolve. The Wash Fred formation contains a low oil gravity (thick oil), 15^o API, which will not develop miscibility with CO₂ at reservoir conditions. Denbury has several fields with similar low gravity oils, which like the Wash Fred 8500’ have had lower recoveries due to the low oil gravities and strong water drives, which do not sweep the oil efficiently. We initiated CO₂ injection during the first quarter of 2006 at the crest of the structure. Although we will not achieve miscibility, the injection of CO₂ is expected to swell the oil, decrease the oil viscosity, and displace the water and oil downward in the reservoir to the adjacent producing wells and result in incremental oil production. Well bore issues delayed the implementation of this flood during 2006, and fluid handling and processing of the CO₂ with this heavy crude have continued to hamper the development of this flood. Although we have seen indications of CO₂ response, the ability to produce and process this heavy crude with the associated CO₂ production is proving very difficult. We are evaluating various ideas and scenarios to address the processing issues we are experiencing. If we can resolve these issues, this field could provide the impetus to look at a whole new array of fields that have historically not been considered for CO₂ injection, although there can be no assurance that this technique will be successful or economic.

     Heidelberg Field. Our 2008 capital program included $43.4 million for construction of the CO₂ pipeline necessary to transport CO₂ from the Free State Pipeline to Heidelberg Field, construction of the initial phase of the CO₂ recycle facilities and initial development of a CO₂ flood in West Heidelberg Field. The initial phase of our CO₂ project will be conducted in the West Heidelberg (WHEOUP) Unit. The reservoir associated with the WHEOUP unit is the Eutaw formation, the same formation we are CO₂ flooding at Eucutta Field. Thus we expect the results at Heidelberg to be similar to the results at Eucutta Field. During the first half of 2008, the Heidelberg central processing and CO₂ recycle facility surface site was secured, cleared, and prepared for construction and facility construction began during the third quarter of the year. The first phase well work was completed in the fourth quarter with the conversion of seventeen producers and eight CO₂ injectors. As of year end, we were injecting approximately 40 MMcf/d of CO₂ into the Eutaw formation in the southern end of West Heidelberg Field. During 2009, we will add eight new injection patterns and expand the central processing facility. Oil production response to the CO₂ injection is expected during the second half of 2009. Four phases are planned for West Heidelberg Field before moving EOR operations into East Heidelberg.

     Due to Heidelberg being an analogy to Eucutta, we were able to book proved tertiary oil reserves at Heidelberg Field at December 31, 2008. Although similar in many respects, the Eutaw reservoir at Heidelberg contains two to three times the potential oil reserves as the Eutaw formation at Eucutta Field.

Phase III Field

     Tinsley Field. Tinsley Field was acquired in January 2006 and is the largest oil field in the state of Mississippi. As is the case with the majority of fields in Mississippi, Tinsley produces from multiple reservoirs. Our primary target in Tinsley for CO₂ enhanced oil recovery operations is the Woodruff formation. A prior operator performed a pilot CO₂ project at Tinsley in the Perry sandstone. The CO₂ was successful at mobilizing oil but the operator decided not to expand the flood due to low crude oil prices. The acquisition of the field included an 8” pipeline that was installed to deliver CO₂ to the pilot project but was converted to natural gas service some time ago. We reconditioned the pipeline for CO₂ service and initiated limited CO₂ injection in Tinsley Field in January 2007. During 2008 the 24” Delta Pipeline was completed and placed in service between Jackson Dome and the Tinsley CO₂ recycle facility, allowing us to transport and inject significantly larger volumes of CO₂. We had our first tertiary oil production commencing in April 2008. By July 2008, all of the tertiary wells in the first two phases were responding to CO₂ injection and producing oil. During the fourth quarter of 2008, the average oil production was 1,832 Bbls/d. We also had non-CO₂ oil production during this same period of 736 Bbls/d.

     From inception through December 31, 2008, we had not yet recovered our costs in this field, with net negative cash flow (revenue less operating expenses and capital expenditures, including the acquisition cost) from Tinsley of $213.8 million.

Denbury Resources Inc.

Our Tertiary Oil Fields Without Proved Tertiary Reserves

     Cranfield. Cranfield development accelerated during 2008 as we increased the well count to 11 CO₂ injectors and 11 producers. Reconditioning of the CO₂ pipeline and the initial phase of the production facility were completed in the third quarter of 2008, which allowed us to commence CO₂ injection into the Lower Tuscaloosa reservoir. The CO₂ injection increased reservoir pressure to a level that caused most of the wells to begin flowing water by late 2008. We had our first minor amounts of tertiary oil production in January 2009. At Cranfield, we have participated with the Bureau of Economic Geology (BEG) from the University of Texas as they study CO₂ injection and sequestration to better define and understand the movement of CO₂ through the reservoir. The results of this study could lead to a greater recovery of the oil in the reservoir.

     Delhi Field. During May 2006, we purchased the Delhi Holt-Bryant Unit (“Delhi”) in Northern Louisiana for $50 million, plus a 25% reversionary interest to the seller after we achieve $200 million in net operating income. In 2008, eight wells were re-completed to be utilized in the Delhi flood patterns. We also finalized the development plans to complete two CO₂ flood patterns in the Paluxy formation and one pattern in the Tuscaloosa formation. The surveying and permitting process for wells, flowlines and facilities are expected to be completed during the first quarter of 2009. The Delta Pipeline (Tinsley to Delhi) is expected to be delivering CO₂ to Delhi Field by the end of the second quarter of 2009. The CO₂ processing facility engineering will be completed during 2009 and construction of the CO₂ facility will begin, with first enhanced oil production anticipated in 2010. As of December 31, 2008, there was no significant oil production nor proved oil reserves at Delhi Field.

     Hastings Field. During November 2006, we entered into an agreement with a subsidiary of Venoco, Inc. that gave us an option to purchase their interest in Hastings Field, a strategically significant potential tertiary flood candidate located near Houston, Texas. We exercised the purchase option prior to September 2008, and closed the $201 million acquisition during February 2009. As consideration for the option agreement, we made total payments of $50 million.

     The purchase price of $201 million included approximately $4.9 million for certain surface land, oilfield equipment and other related assets. Under the terms of the agreement, Venoco, Inc., the seller, retained a 2% override and reversionary interest of approximately 25% following payout, as defined in the option agreement. The Hastings Complex is currently producing approximately 2,400 BOE/d, net to the acquired interest, with conventional proved reserves of approximately 5.8 MMBOE using year-end 2008 prices. The Hastings proved reserves were not included in the Company’s year-end proved reserves. We plan to commence flooding the field with CO₂ beginning in 2011, after completion of our Green CO₂ Pipeline currently under construction, and construction of field CO₂ recycling facilities.

     As part of the agreement, we are required to spend an aggregate of approximately $179 million over a five year period to develop the field for tertiary operations (commencing in 2010), with an obligation to commence CO₂ injections in the field by late 2012.

     Based on preliminary engineering data, the West Hastings Unit (the most likely area to be initially developed as a tertiary flood) has significant net reserve potential from CO₂ tertiary floods, more reserve potential than any other single field in our inventory. We started construction of the Green Pipeline during November 2008 to transport CO₂ to this field (see “CO₂ pipelines” above). Based on our latest estimates, it will cost between $400 million and $600 million to develop the West Hastings Unit as a tertiary flood, excluding the cost of the Green Pipeline.

     Oyster Bayou, Fig Ridge and Gillock Fields. During 2007, we acquired an interest in three fields in Southeast Texas with significant tertiary potential. The Oyster Bayou and Fig Ridge Fields are located in close proximity to each other and are located on or close to the planned route of the 24” Green Pipeline. We acquired the majority interest in Oyster Bayou Field and a relatively small interest in Fig Ridge Field. We plan to start the unitization hearings required at Oyster Bayou Field during 2009. Because of current lack of majority interest at Fig Ridge Field, we will need the cooperation of other operators and lease owners to form the necessary unit. During 2008 we initiated those discussions.

     Our acquisitions in Gillock Field include an acquisition of almost all of the South Gillock Unit, the Southeast Gillock unit and the acquisition of a key lease in the Gillock Field. The Gillock acquisitions are located near the proposed Green Pipeline and Hastings Field. Denbury continues to evaluate other potential acquisition candidates in Southeast Texas and in Louisiana in proximity to our Green Pipeline.

Denbury Resources Inc.

     Overall Tertiary Economics to Date. Through December 31, 2008, we have invested a total of $1.4 billion on tertiary oil fields (including the allocated acquisition costs), and received $1.3 billion in net operating income (revenue less operating expenses), or net unrecovered cash flow of $105.3 million, the deficit primarily due to the significant funds expended on acquisitions during 2006. Of our total spending, approximately $229.6 million was invested to date on fields that had little or no proved reserves at December 31, 2008 (i.e., significant incremental proved reserves are anticipated in future years). These amounts do not include the capital costs or related depreciation and amortization of our CO₂ producing properties at Jackson Dome, which had an unrecovered net cash flow of $816.7 million as of December 31, 2008, including $525.7 million associated with CO₂ pipelines. At year-end 2008, the proved oil reserves in our tertiary recovery oil fields had a PV-10 Value of approximately $1.0 billion, using December 31, 2008, NYMEX pricing of $44.60 per barrel. In addition, there are significant probable and potential reserves at several other fields for which tertiary operations are under way or planned.

Texas Barnett Shale

     We currently own approximately 20,441 gross acres and 19,457 net acres in the Barnett Shale area in North Central Texas. We acquired our initial acreage in this area in 2001 and did only limited development until 2005. Through December 31, 2008, we have invested a total of $552.3 million on the Barnett Shale area (including acquisition costs) and have received $403.0 million in net operating income (revenue less operating expenses), or net negative cash flow of $149.3 million. At December 31, 2008, we had approximately 458 Bcfe of proved reserves in the Barnett Shale area with a PV-10 Value of approximately $430.0 million, using December 31, 2008, Henry Hub indicative cash pricing of $5.71 per MMBtu.

     We continue to refine our completion and fracturing techniques, including an analysis of the best number of fracture treatments to adequately stimulate the entire length of the lateral sections of our horizontal wells, which can exceed 4,000’. During 2008, we drilled and completed 38 horizontal wells which kept our production from this area about the same throughout the year, averaging approximately 73 MMcfe/d during the fourth quarter of 2008.

     Horizontal wells in the Barnett Shale were initially drilled by spacing horizontal wells approximately 1,500’ apart and drilling 3,000’ to 4,500’ laterals. As our development progressed, we began testing wells at various spacings of 750’ and subsequently 500’ along with other operators in the Barnett. Initial production rates and early production data indicated that we were not efficiently draining the reservoir on the larger initial well spacing, and thus we began developing our acreage position on 500’ well spacing which significantly increased the number of future development well locations that could be drilled. Our year-end reserves included 77 proved undeveloped locations, plus we have an additional 64 probable undeveloped locations based on 500’ well spacing. We have recently begun testing well spacings less than 500’ but the results of this additional downspacing are inconclusive at this time. We have drilled two 250’ spaced wells. These wells have produced volumes at or above that which an average conventionally spaced well would have produced at this time in their production life. If our testing of the Barnett Shale on tighter well spacing continues to be successful, it would significantly increase our number of future locations. We expect production in the Barnett Shale to decline during 2009, as we are planning on drilling only six wells during the year due to reduction of our overall capital expenditure program because of the significant decline in commodity prices during the last half of 2008. Our planned 2009 capital expenditures in the Barnett Shale area are estimated to be approximately $25 million.

East Mississippi Fields without Proved Tertiary Oil Reserves

     We have been active in East Mississippi since Denbury was founded in 1990 and are by far the largest oil producer in the basin. Historically, this was our area with the highest production and most proved reserves, and while still significant, it is no longer our largest. Production during the fourth quarter of 2008 averaged approximately 12,150 BOE/d from this area (25% of our Company total), and we had proved reserves of 40.1 MMBOE as of December 31, 2008 (16% of our Company total). Since we have generally owned these Eastern Mississippi properties longer than properties in our other regions, they tend to be more fully developed, and although most are targeted for tertiary operations in the future, only four currently have tertiary operations (Soso, Martinville, Eucutta and Heidleberg Fields). Production from our conventional and secondary recovery operations in our East Mississippi fields has been relatively consistent over the last three years, averaging 12,743 BOE/d in 2006, 12,479 BOE/d in 2007 and 11,897 BOE/d during 2008.

     Heidelberg Field. The largest field in the region and one of our largest fields corporately is Heidelberg Field, which for the fourth quarter of 2008 produced an average of 7,482 BOE/d. Heidelberg Field was acquired from Chevron in December 1997. The field is a large salt-cored anticline that is divided into western and eastern

Denbury Resources Inc.

segments due to subsequent faulting. Most of the past and current production comes from the Eutaw, Selma Chalk and Christmas sands at depths from 3,500’ to 5,000’.

     The majority of the oil production at Heidelberg is from six waterflood units that produce from the Eutaw formation (at approximately 4,400’). Most of our recent development at Heidelberg, other than our tertiary operations, has been in the Selma Chalk, a natural gas reservoir at around 3,700’, making Heidelberg our second largest gas field. We have steadily developed the Selma Chalk since 2001, drilling from 13 to 20 wells per year, increasing the natural gas production at Heidelberg to a peak quarterly average of 19.4 MMcf/d in the fourth quarter of 2008. During late 2006 and early 2007, we drilled our first horizontal wells in West Heidelberg Field where vertical wells were generally uneconomic. The horizontal wells have performed well and thus we expect to be able to expand our Selma Chalk development throughout West Heidelberg Field. During 2007, we drilled 13 horizontal Selma Chalk wells, two of which were located in West Heidelberg, and during 2008, we drilled 10 horizontal Selma Chalk wells, three of which were located in West Heidelberg. Similar to the Barnett Shale, we have severely curtailed capital expenditures on this field in 2009 as a result of lower commodity prices.

Denbury Resources Inc.

Field Summaries

     Denbury operates in five primary areas: Eastern Mississippi, Western Mississippi, Texas, Alabama and Louisiana. Our 17 largest fields (listed below) constitute approximately 97% of our total proved reserves on a BOE basis, and 96% of our total proved reserves on a PV-10 Value basis. Within these 17 fields, we own a weighted average 95% working interest and operate all of these fields. The concentration of value in a relatively small number of fields allows us to benefit substantially from any operating cost reductions or production enhancements we achieve, and allows us to effectively manage the properties from our four primary field offices located in Laurel, Mississippi; McComb, Mississippi; Jackson, Mississippi; and Aledo, Texas.

		Proved Reserves as of December 31, 2008(1)																				2008 Average Daily Production
		Oil				Natural Gas								BOE				PV-10 Value(2)				Oil				Natural Gas
		(MBbls)				(MMcf)				MBOEs				% of total				(000's)				(Bbls/d)				(Mcf/d)				Avg NRI
Tertiary Oil Fields
Tinsley			34,440				—				34,440				13.8	%		$	224,812				1,010				—				75.6	%
Heidelberg			22,394				—				22,394				8.9	%			22,948				—				—				77.3	%
Brookhaven			17,330				—				17,330				6.9	%			213,816				2,826				—				79.2	%
McComb Area			13,688				—				13,688				5.5	%			101,106				1,901				—				78.9	%
Mallalieu			11,790				—				11,790				4.7	%			161,077				5,686				—				76.6	%
Eucutta			9,147				—				9,147				3.7	%			135,975				3,109				—				83.5	%
Soso			9,024				—				9,024				3.6	%			91,089				2,111				—				77.2	%
Lockhart Crossing			3,970				—				3,970				1.6	%			35,502				186				—				58.0	%
Little Creek & Lazy Creek			3,213				—				3,213				1.3	%			40,758				1,683				—				83.2	%
Martinville			839				—				839				0.3	%			7,700				865				—				78.1	%
Total Tertiary Oil Fields			125,835				—				125,835				50.3	%			1,034,783				19,377				—				78.7	%
Mississippi
Heidelberg			17,066				63,637				27,672				11.0	%			276,199				4,505				17,663				77.3	%
Sharon			16				24,458				4,092				1.6	%			54,930				13				8,222				83.6	%
Eucutta			1,140				—				1,140				0.5	%			14,346				309				3				67.3	%
Summerland			1,044				—				1,044				0.4	%			7,524				373				—				74.4	%
S. Cypress Creek			937				17				940				0.4	%			9,523				190				20				83.0	%
Other Mississippi			4,777				2,807				5,245				2.1	%			53,816				2,012				1,065				21.4	%
Total Mississippi			24,980				90,919				40,133				16.0	%			416,338				7,402				26,973				48.4	%
Texas
Newark (Barnett Shale)			20,865				332,502				76,282				30.5	%			429,961				2,887				58,874				79.9	%
Other Texas			343				553				435				0.1	%			3,059				266				1,488				64.6	%
Total Texas			21,208				333,055				76,717				30.6	%			433,020				3,153				60,362				78.8	%
Louisiana and Other
Various Fields			417				3,912				1,069				0.4	%			17,786				310				1,312				56.7	%
Louisiana Sold (3)			—				—				—				—				—				15				518				49.0	%
Total Louisiana and Other			417				3,912				1,069				0.4	%			17,786				325				1,830				55.4	%
Alabama
Citronelle			6,686				—				6,686				2.7	%			24,906				1,176				—				63.3	%
Other Alabama			—				69				12				—				22				3				277				1.8	%
Total Alabama			6,686				69				6,698				2.7	%			24,928				1,179				277				29.5	%
Company Total			179,126				427,955				250,452				100.0	%		$	1,926,855				31,436				89,442				64.9	%

Denbury Resources Inc.

Oil and Gas Acreage, Productive Wells, and Drilling Activity

     In the data below, “gross” represents the total acres or wells in which we own a working interest and “net” represents the gross acres or wells multiplied by Denbury’s working interest percentage. For the wells that produce both oil and gas, the well is typically classified as an oil or natural gas well based on the ratio of oil to gas production.

Oil and Gas Acreage

     The following table sets forth Denbury’s acreage position at December 31, 2008:

		Developed								Undeveloped								Total
		Gross				Net				Gross				Net				Gross				Net
Mississippi			153,080				108,720				248,227				32,036				401,307				140,756
Louisiana			35,863				34,162				4,559				3,882				40,422				38,044
Texas			37,691				34,324				7,229				3,814				44,920				38,138
Alabama			19,429				15,218				68,697				11,755				88,126				26,973
Other			6,852				855				38,711				9,686				45,563				10,541
Total			252,915				193,279				367,423				61,173				620,338				254,452

     Denbury’s net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 25% in 2009, 22% in 2010 and 45% in 2011.

Productive Wells

     The following table sets forth our gross and net productive oil and natural gas wells at December 31, 2008:

		Producing Natural
		Producing Oil Wells								Gas Wells								Total
		Gross				Net				Gross				Net				Gross				Net
Operated Wells:
Mississippi			585				558.3				220				200.0				805				758.3
Louisiana			25				18.8				9				9.0				34				27.8
Texas			27				23.1				199				192.6				226				215.7
Alabama			151				120.3				7				3.1				158				123.4
Total			788				720.5				435				404.7				1,223				1,125.2
Non-Operated Wells:
Mississippi			39				3.8				20				4.6				59				8.4
Louisiana			—				—				1				—				1				—
Texas			1				—				4				0.5				5				0.5
Alabama			—				—				3				0.6				3				0.6
Other			4				—				—				—				4				—
Total			44				3.8				28				5.7				72				9.5
Total Wells:
Mississippi			624				562.1				240				204.6				864				766.7
Louisiana			25				18.8				10				9.0				35				27.8
Texas			28				23.1				203				193.1				231				216.2
Alabama			151				120.3				10				3.7				161				124.0
Other			4				—				—				—				4				—
Total			832				724.3				463				410.4				1,295				1,134.7

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,
		2008								2007								2006
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells:(1)
Productive(2)			—				—				9				6.2				10				8.5
Non-productive(3)			1				1.0				4				3.4				8				6.8
Development Wells:(1)
Productive(2)			102				98.3				101				96.8				90				82.7
Non-productive(3)(4)			1				0.7				—				—				—				—
Total			104				100.0				114				106.4				108				98.0

Production and Unit Prices

     Information regarding average production rates, unit sale prices and unit costs per BOE are set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Operating Results” included herein.

Title to Properties

     Customarily in the oil and gas industry, only a perfunctory title examination is conducted at the time properties believed to be suitable for drilling operations are first acquired. Prior to commencement of drilling operations, a thorough drill site title examination is normally conducted, and curative work is performed with respect to significant defects. During acquisitions, title reviews are performed on all properties; however, formal title opinions are obtained on only the higher value properties. We believe that we have good title to our oil and natural gas properties, some of which are subject to minor encumbrances, easements and restrictions.

Geographic Segments

     All of our operations are in the United States.

Significant Oil and Gas Purchasers and Product Marketing

     Oil and gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The loss of any single purchaser would not be expected to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive. For the year ended December 31, 2008, we had three significant purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (49%), Hunt Crude Oil Supply Co. (20%) and Crosstex Energy Field Services Inc. (14%).

Denbury Resources Inc.

For the year ended December 31, 2007, three purchasers each accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (43%), Hunt Crude Oil Supply Co. (19%) and Crosstex Energy Field Services Inc. (16%). For the year ended December 31, 2006, we had two significant purchasers that each accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (28%) and Hunt Crude Oil Supply Co. (18%).

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

Oil Marketing

     The quality of our crude oil varies by area, thereby impacting the corresponding price received. In Heidelberg Field, one of our larger fields, and our other Eastern Mississippi properties, our oil production is primarily light to medium sour crude and sells at a significant discount to the NYMEX prices. In Western Mississippi, the location of our Phase I tertiary operations, our oil production is primarily light sweet crude, which typically sells at near NYMEX prices, or often at a premium. For the year ended December 31, 2008, the discount for our oil production from Heidelberg Field averaged $15.65 per Bbl and for our Eastern Mississippi properties as a whole the discount averaged $13.64 per Bbl relative to NYMEX oil prices. For our Phase I tertiary fields in Southwest Mississippi, we averaged a premium of $3.75 per Bbl over NYMEX oil prices during 2008. For our Phase II tertiary fields, we averaged a discount of $6.61 per Bbl below NYMEX oil prices during 2008. Our Texas Barnett Shale properties averaged $43.74 per Bbl below NYMEX prices during 2008, largely because the reported oil sales are mostly natural gas liquids, which typically sell at much lower prices than crude oil.

Natural Gas Marketing

     Virtually all of our natural gas production is close to existing pipelines and consequently we generally have a variety of options to market our natural gas. We sell the majority of our natural gas on one-year contracts with prices fluctuating month-to-month based on published pipeline indices with slight premiums or discounts to the index. We receive near NYMEX or Henry Hub prices for most of our natural gas sales in Mississippi. For the year ended December 31, 2008, we averaged $0.35 above NYMEX prices for our Mississippi natural gas production. However, in the Barnett Shale area in Texas, due primarily to its location, the price we received averaged $0.74 below NYMEX prices.

Competition and Markets

     We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and obtaining goods, services and labor. Many of our competitors have substantially larger financial and other resources. Factors that affect our ability to acquire producing properties include available funds, available information about prospective properties and our standards established for minimum projected return on investment. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. Because of the nature of our core assets (our tertiary operations) and our ownership of a relatively uncommon significant natural source of carbon dioxide, we believe that we are effective in competing in the market.

     The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. We cannot be certain when we will experience

Denbury Resources Inc.

these issues, and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results or restrict our ability to drill those wells and conduct those operations that we currently have planned and budgeted.

Federal and State Regulations

     Numerous federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance. The following section describes some specific laws and regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives.

     Management believes that we are in substantial compliance with all laws and regulations applicable to our operations and that continued compliance with existing requirements will not have a material adverse impact on us. The future annual capital costs of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements. However, management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations.

Regulation of Natural Gas and Oil Exploration and Production

     Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and regulating the location of wells; the method of drilling and casing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and the disposal of fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization or pooling of oil and gas properties. In addition, state conservation laws which establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability.

Federal Regulation of Sales Prices and Transportation

     The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the U.S. federal government and are affected by the availability, terms and cost of transportation. In particular, the price and terms of access to pipeline transportation are subject to extensive U.S. federal and state regulation. The Federal Energy Regulatory Commission (FERC) is continually proposing and implementing new rules and regulations affecting the natural gas industry. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. The ultimate impact of the complex rules and regulations issued by FERC cannot be predicted. Some of FERC’s proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. While our sales of crude oil, condensate and natural gas liquids are not currently subject to FERC regulation, our ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective and their effect, if any, on our operations. Historically, the natural gas industry has been heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC, Congress and the states will continue indefinitely into the future.

Federal Energy and Climate Change Legislation

     In October 2008, as part of the Emergency Economic Stabilization Act, Congress included a new tax credit for carbon capture and sequestration, including that achieved through enhanced oil recovery, as further modified by the American Recovery and Reinvestment Act of 2009, passed in February 2009. In future periods Congress may decide to revisit legislation introduced in prior sessions to repeal existing incentives or impose new taxes on the

Denbury Resources Inc.

exploration and production of oil, gas and other minerals, and/or create new incentives for alternative energy sources. Congress may also consider legislation to reduce emissions of carbon dioxide or other greenhouse gases. If enacted, such legislation could impose a tax or other economic penalty on the production of oil and gas that, when consumed, ultimately release CO₂. Any additional taxes or economic penalties imposed on the production of oil and gas would increase the costs incurred by the Company in its exploration and production activities and more than likely reduce the supply of domestic production of oil and gas which could in turn increase the price received on our oil and gas production. At the same time, legislation to reduce the emissions of carbon dioxide or other gases could also create economic incentives for technologies and practices that reduce or avoid such emissions, including activities that sequester CO₂ in geologic formations such as oil and gas reservoirs. Denbury’s CO₂-EOR operations, including our CO₂ pipeline network are well positioned in this regard.

Natural Gas Gathering Regulations

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

Federal, State or Indian Leases

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

Environmental Regulations

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

     Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact the Company’s operations and costs. These regulations include, among others, (i) regulations by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act, Federal Resource Conservation and Recovery Act and analogous state laws that regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company or could result in the imposition of economic penalties on the production of fossil fuels that, when used, ultimately release CO₂; (iv) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; and (vi) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material (“NORM”).

     Management believes that we are in substantial compliance with applicable environmental laws and regulations. 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.

Denbury Resources Inc.

     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, 2008, 2007 and 2006. The reserve estimates were prepared using constant prices and costs in accordance with the guidelines of Statement of Financial Accounting Standards (“SFAS”) No. 69. 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. During 2008, we provided oil and gas reserve estimates for 2007 to the United States Energy Information Agency. The information provided was substantially the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2007.

     Our proved nonproducing reserves primarily relate to reserves that are to be recovered from productive zones that are currently behind pipe. Since a majority of our properties are in areas with multiple pay zones, these properties typically have both proved producing and proved nonproducing reserves.

     Proved undeveloped reserves associated with our CO₂ tertiary operations and our Heidelberg waterfloods in East Mississippi account for approximately 90% 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 94% of our proved undeveloped natural gas reserves. Due to the curtailment of our capital spending for 2009, our current plans include drilling only six new wells in the Barnett Shale during 2009.

		December 31,
		2008				2007				2006
ESTIMATED PROVED RESERVES:
Oil (MBbls)			179,126				134,978				126,185
Natural gas (MMcf)			427,955				358,608				288,826
Oil equivalent (MBOE)			250,452				194,746				174,322
PERCENTAGE OF TOTAL MBOE:
Proved producing			47	%			56	%			48	%
Proved non-producing			11	%			13	%			17	%
Proved undeveloped			42	%			31	%			35	%
REPRESENTATIVE OIL AND NATURAL GAS PRICES:(1)
Oil — NYMEX		$	44.60			$	95.98			$	61.05
Natural gas — Henry Hub			5.71				6.80				5.63
PRESENT VALUES (thousands):(2)
Discounted estimated future net cash flow before income taxes (“PV-10 Value”) (3)		$	1,926,855			$	5,385,123			$	2,695,199
Standardized measure of discounted estimated future net cash flow after income taxes			1,415,498				3,539,617				1,837,341

Denbury Resources Inc.

     There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control. See “Risk Factors — Estimating our reserves, production and future net cash flow is difficult to do with any certainty.” See also Note 15, “Supplemental Oil and Natural Gas Disclosures,” to the Consolidated Financial Statements.

Item 1A. Risk Factors

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 90% of our 2009 capital expenditures to be in this area. The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of carbon dioxide. Our ability to produce this oil would be hindered if our supply of carbon dioxide were limited due to problems with our current CO₂ producing wells and facilities, including compression equipment, or catastrophic pipeline failure. Our anticipated future crude oil production is also dependent on our ability to increase the production volumes of CO₂ and inject adequate amounts of CO₂ into the proper formation and area within each oil field. The production of crude oil from tertiary operations is highly dependent on the timing, volumes and location of the CO₂ injections. If our crude oil production were to decline, it could have a material adverse effect on our financial condition, results of operations and cash flows.

Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices could adversely affect our financial results.

     Our future financial condition, results of operations and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile, have been particularly volatile over the last six months, and likely will continue to be volatile in the future, especially given current world geopolitical conditions. As a result of the low oil and natural gas prices at December 31, 2008, we recorded a $226.0 million full cost ceiling test write-down. Subsequent to December 31, 2008, oil and natural gas prices have continued their volatility and are currently at levels lower than at year-end 2008. If oil and natural gas prices remain at these lower levels through March 31, 2009, or subsequent periods, we may be required to record additional full cost ceiling test write-downs in the first quarter of 2009, or in subsequent periods. The amount of any future write-down is difficult to predict and will depend upon the oil and natural gas prices at the end of each period, the incremental proved reserves that might be added during each period and additional capital spent.

     Our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas. This price volatility also affects the amount of our cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow or have outstanding under our bank credit facility is subject to semi-annual redeterminations. Oil prices are likely to affect us more than natural gas prices because approximately 72% of our December 31, 2008 proved reserves are oil, with oil being an even larger percentage of our future potential reserves and projects due to our focus on tertiary operations. The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These factors include:

	•		the level of consumer demand for oil and natural gas;
	•		the domestic and foreign supply of oil and natural gas;
	•		the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to agree to and maintain oil price and production controls;
	•		the price of foreign oil and natural gas;
	•		domestic governmental regulations and taxes;

Denbury Resources Inc.

	•		the price and availability of alternative fuel sources;
	•		weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico;
	•		market uncertainty;
	•		political conditions in oil and natural gas producing regions, including the Middle East; and
	•		worldwide economic conditions.

     These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements. Also, oil and natural gas prices do not necessarily move in tandem. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect upon our financial condition, results of operations, oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the oil and 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 until mid-2008, albeit with fluctuations. For 2008, NYMEX oil prices increases throughout the first six months, averaging approximately $111.03 per Bbl for the first six months of 2008. During the last half of 2008, oil prices declined substantially, ending the year at a NYMEX price of $44.60 per Bbl. Since we have acquired oil commodity derivative contracts with a NYMEX floor price of $75 per barrel covering approximately 80% of our 2009 forecasted oil production, we are relatively insensitive to lower oil prices during 2009. We currently do not have any oil or natural gas commodity derivative contracts in place for subsequent years, and therefore oil prices could decline to a level that makes our tertiary projects uneconomic. If that were to happen, we may decide to suspend future expansion projects and if prices were to drop below the cash break- even point for an extended period of time, we may decide to shut-in existing production, either of which would have a material adverse effect on our operations. Since our operating costs have not decreased as quickly as commodity prices, it is difficult to determine a precise break-even point for our tertiary projects. Based on prior history, we estimate that our economic break-even point for these types of projects would approximate per barrel dollar costs in the range of the mid-twenties, and our operating cash break-even point would be between $15 and $20 of cost per barrel if commodity prices remain at current levels for sustained periods.

     The prices we receive for our crude oil do not always correlate with NYMEX prices. Our NYMEX differentials over the last few years have ranged from a low of approximately $1.50 per Bbl to a high of almost $10.00 per Bbl. These variances have been due to various factors and are difficult to forecast or anticipate but have a direct impact on the net oil price we receive.

     Natural gas prices have also experienced volatility during the last few years. During 1999, natural gas prices averaged approximately $2.35 per Mcf and, like crude oil, have generally trended upward since that time, although with significant fluctuations along the way. NYMEX natural gas prices averaged $6.97 per MMBtu during 2006, $7.09 per MMBtu during 2007, and $8.89 per MMBtu during 2008, and ended 2008 at $5.62 per MMBtu.

The current financial crisis may have effects on our liquidity, business and financial condition that we cannot predict.

     Liquidity is essential to our business. Our liquidity could be substantially negatively affected by an inability to raise funding in the long-term or short-term debt capital markets or equity capital markets or an inability to access bank financing. The continued credit crisis and related turmoil in the global financial system is likely to continue to materially affect our liquidity, business and our financial condition. Our ability to access the capital markets has been restricted as a result of this crisis and may be restricted in the future when we would like, or need, to raise capital. The economic situation could also adversely affect the collectability of our trade receivables or performance by our suppliers and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, the current economic situation could lead to reduced demand for oil and gas, or lower prices for oil and gas, or both, which could have a negative impact on our revenues.

Denbury Resources Inc.

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

     As of February 27, 2009, we had outstanding $525 million (principal amount) of 7.5% subordinated notes, $420 million (principal amount) of 9.75% Senior Subordinated Notes, and $60 million of bank debt. At that time, we had approximately $690 million available on our bank credit line. We currently have a bank borrowing base of $1.0 billion, with a commitment amount of $750 million. The borrowing base represents the amount that can be borrowed from a credit standpoint, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The next semi-annual redetermination of the borrowing base for our bank credit facility will be on April 1, 2009. Our bank borrowing base is adjusted at the banks’ discretion and is based in part upon external factors, such as commodity prices, over which we have no control. If our then redetermined borrowing base is less than our outstanding borrowings under the facility, we will be required to repay the deficit over a period of six months.

     We may incur additional indebtedness in the future under our bank credit facility in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties as our projected 2009 capital expenditures, excluding acquisitions, are between $200 million and $300 million higher than our projected 2009 cash flow from operations. Further, our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas, which in the latter part of 2008, declined significantly. If oil and natural gas prices remain depressed for an extended period of time, our degree of leverage could increase substantially. The level of our indebtedness could have important consequences, including but not limited to the following:

	•		a substantial portion of our cash flows from operations may be dedicated to servicing our indebtedness and would not be available for other purposes;
	•		as a result of the discretionary nature of the setting of our bank borrowing base and its being highly dependent on current commodity prices, if commodity prices were to further decrease, our banks could reduce our borrowing base so that we could not borrow additional funds or to a level below our outstanding debt that would require us to repay any deficit (between the borrowing base and the outstanding bank debt) over a six month period;
	•		our business may not generate sufficient cash flow from operations to enable us to continue to meet our obligations under our indebtedness;
	•		our level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate and other purposes;
	•		our interest expense may increase in the event of increases in interest rates, because certain of our borrowings are at variable rates of interest;
	•		our vulnerability to general adverse economic and industry conditions may be greater as a result of our level of indebtedness, 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.

Denbury Resources Inc.

Product price derivative contracts may expose us to potential financial loss.

     To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative contracts in order to economically hedge a portion of our oil and natural gas production. Derivative contracts expose us to risk of financial loss in some circumstances, including when:

	•		production is less than expected;
	•		the counter-party to the derivative contract defaults on its contract obligations; or
	•		there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

     In addition, these derivative contracts may limit the benefit we would receive from increases in the prices for oil and natural gas. Information as to these activities is set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Management,” and in Note 10, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements.

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

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

     In January 2006, we purchased three oil fields for $250 million that we believe have significant potential oil reserves that can be recovered through the use of tertiary flooding: Tinsley Field approximately 40 miles northwest of Jackson, Mississippi; Citronelle Field in Southwest Alabama, and the smaller South Cypress Creek Field near our Eucutta Field in Eastern Mississippi. These three fields produced approximately 3,926 BOE/d net to the acquired interests during the fourth quarter of 2008, and have proved reserves of approximately 42.8 MMBOEs as of December 31, 2008. During 2008, we recognized approximately 34.8 MMBOE of proven tertiary reserves at Tinsley Field, but have yet to recognize any tertiary oil reserves at Citronelle or South Cypress Creek Fields. In February 2009, we closed on the acquisition of Hastings field located near Houston, Texas. Hastings is also a potential tertiary oil field and it will be supplied CO₂ by the Green Pipeline, which is currently under construction. The purchase price, including option payments, was approximately $250 million. We purchased these fields because we believe that they have significant additional potential through tertiary flooding and we paid a premium price for these properties based on that assumption. In addition to these specific acquisitions, we have, and plan to continue, acquiring other old oil fields that we believe are tertiary flood candidates, likely at a premium price. We are investing significant amounts of capital as part of this strategy. If we are unable to successfully develop the potential oil in these acquired fields, it would negatively affect the return on our investment on these acquisitions and could severely reduce our ability to obtain additional capital for the future, fund future acquisitions, and negatively affect our financial results to a significant degree.

     We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties and oil and gas leases. Many of our competitors have substantially larger financial and other resources. Other factors that affect our ability to acquire producing properties include available

Denbury Resources Inc.

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.

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

     The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Due to the recent record high oil and gas prices, we have experienced shortages of equipment used in our tertiary facilities, drilling rigs and other equipment, as demand for rigs and equipment has increased along with higher commodity prices. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services and personnel in our exploration and production

Denbury Resources Inc.

operations. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

The loss of more than one of our large oil and natural gas purchasers could have a material adverse effect on our operations.

     For the year ended December 31, 2008, three purchasers each accounted for more than 10% of our oil and natural gas revenues and in the aggregate, for 83% 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 flows is difficult to do with any certainty.

     Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to potential or probable reserves, particularly relating to our tertiary recovery operations. Forecasting the amount of oil reserves recoverable from tertiary operations and the production rates anticipated therefrom requires estimates, one of the most significant being the oil recovery factor. Actual results most likely will vary from our estimates. Also, the use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. Any significant inaccuracies in these interpretations or assumptions or changes of conditions could result in a reduction of the quantities and net present value of our reserves.

     Quantities of proved reserves are estimated based on economic conditions, including oil and natural gas prices in existence at the date of assessment. Our reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs and other factors. Downward revisions of our reserves could have an adverse effect on our financial condition, operating results and cash flows.

     The reserve data included in documents incorporated by reference represent only estimates. In accordance with requirements of the SEC, the estimates of present values are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and cost as of the date of the estimate.

     As of December 31, 2008, approximately 42% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but these assumptions may not be accurate, and this may not occur.

We are subject to complex federal, state and local laws and regulations, including environmental laws, which could adversely affect our business.

     Exploration for and development, exploitation, production and sale of oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax laws and environmental laws and regulations. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws, regulations or incremental taxes and fees, could harm our business, results of operations and financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations.

     It is possible that new taxes on our industry could be implemented and/or tax benefits could be eliminated or reduced, reducing our profitability and available cash flow. In addition to the short-term negative impact on our financial results, such additional burdens, if enacted, would reduce our funds available for reinvestment and thus ultimately reduce our growth and future oil and natural gas production.

Denbury Resources Inc.

     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.

Item 1B. Unresolved Staff Comments

     None.

Item 2. Properties

     See Item 1. “Business — Oil and Gas Operations.” We also have various operating leases for rental of office space, office and field equipment, and vehicles. See “Off-Balance Sheet Agreements — Commitments and Obligations” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and Note 11, “Commitments and Contingencies,” to the Consolidated Financial Statements for the future minimum rental payments. Such information is incorporated herein by reference.

Item 3. Legal Proceedings

     We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position or overall trends in results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that we may have a range of legal exposure that would require accrual.

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

     None.

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 sale prices are adjusted to reflect the 2-for-1 stock split on December 5, 2007. As of February 23, 2009, based on information from the Company’s transfer agent, American Stock Transfer and Trust Company, the number of holders of record of Denbury’s common stock was 1,066. On February 25, 2009, the last reported sale price of Denbury’s common stock, as reported on the NYSE, was $12.88 per share.

		2008								2007
		High				Low				High				Low
First Quarter		$	33.640			$	21.760			$	15.310			$	12.980
Second Quarter			40.320				27.280				19.380				14.835
Third Quarter			37.240				16.110				23.380				18.275
Fourth Quarter			18.860				5.590				30.560				22.405

     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 2008.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

										(c) Total Number of				(d) Maximum Number
		(a) Total								Shares Purchased				of Shares that May
		Number of				(b) Average				as Part of Publicly				Yet Be Purchased
		Shares				Price Paid				Announced Plans or				Under the Plan Or
Period		Purchased				per Share				Programs				Programs
October 1 through 31, 2008			3,475			$	15.44				—				—
November 1 through 30, 2008			398			$	10.33				—				—
December 1 through 31, 2008			—			$	—				—				—
Total			3,873			$	14.91				—				—

     There shares were purchased from employees of Denbury who delivered shares to the company to satisfy their minimum tax withholding requirements related to the vesting of restricted shares.

Denbury Resources Inc.

Share Performance Graph

     The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

     The following graph illustrates changes over the five-year period ended December 31, 2008, in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index. The results assume $100 was invested on December 31, 2003, and that dividends were reinvested.

		December 31,
		2003				2004				2005				2006				2007				2008
Denbury			100.00				197.34				327.53				399.57				855.50				314.02
S&P 500			100.00				110.88				116.33				134.70				142.10				89.53
Dow Jones U.S. Exploration and Production			100.00				141.87				234.54				247.14				355.06				212.61

Denbury Resources Inc.

Item 6. Selected Financial Data

(In thousands, unless otherwise noted)		Year Ended December 31,
		2008				2007				2006(1)				2005				2004(2)
Consolidated Statements of Operations Data:
Revenues		$	1,365,702			$	973,060			$	731,536			$	560,392			$	382,972
Net income (3)			388,396				253,147				202,457				166,471				82,448
Net income per common share (4):
Basic			1.59				1.05				0.87				0.74				0.38
Diluted			1.54				1.00				0.82				0.70				0.36
Weighted average number of common shares outstanding (4):
Basic			243,935				240,065				233,101				223,485				219,482
Diluted			252,530				252,101				247,547				239,267				229,206
Consolidated Statements of Cash Flow Data:
Cash provided by (used by):
Operating activities		$	774,519			$	570,214			$	461,810			$	360,960			$	168,652
Investing activities			(994,659	)			(762,513	)			(856,627	)			(383,687	)			(93,550	)
Financing activities			177,102				198,533				283,601				154,777				(66,251	)
Production (daily):
Oil (Bbls)			31,436				27,925				22,936				20,013				19,247
Natural gas (Mcf)			89,442				97,141				83,075				58,696				82,224
BOE (6:1)			46,343				44,115				36,782				29,795				32,951
Unit Sales Price
(excluding impact of derivative settlements):
Oil (per Bbl)		$	92.73			$	69.80			$	59.87			$	50.30			$	36.46
Natural gas (per Mcf)			8.56				6.81				7.10				8.48				6.24
Unit Sales Price
(including impact of derivative settlements):
Oil (per Bbl)		$	90.04			$	68.84			$	59.23			$	50.30			$	27.36
Natural gas (per Mcf)			7.74				7.66				7.10				7.70				5.57
Costs per BOE:
Lease operating expenses		$	18.13			$	14.34			$	12.46			$	9.98			$	7.22
Production taxes and marketing expenses			3.76				3.05				2.71				2.54				1.55
General and administrative			3.56				3.04				3.20				2.62				1.78
Depletion, depreciation and amortization			13.08				12.17				11.11				9.09				8.09
Proved Reserves:
Oil (MBbls)			179,126				134,978				126,185				106,173				101,287
Natural gas (MMcf)			427,955				358,608				288,826				278,367				168,484
MBOE (6:1)			250,452				194,746				174,322				152,568				129,369
Carbon dioxide (MMcf) (5)			5,612,167				5,641,054				5,525,948				4,645,702				2,664,633
Consolidated Balance Sheet Data:
Total assets		$	3,589,674			$	2,771,077			$	2,139,837			$	1,505,069			$	992,706
Total long-term liabilities			1,363,539				1,102,066				833,380				617,343				368,128
Stockholders’ equity (6)			1,840,068				1,404,378				1,106,059				733,662				541,672

Denbury Resources Inc.

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

     The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, “Financial Statements and Supplementary Data.” Our discussion and analysis includes forward looking information that involves risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report, along with “Forward Looking Information” at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward looking statements.

Overview

     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 significant operating acreage in the Barnett Shale play near Fort Worth, Texas, and also hold properties in Southeast Texas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, with our most significant emphasis relating to tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have four primary field offices located in Laurel, Mississippi; McComb, Mississippi; Jackson, Mississippi; and Aledo, Texas.

     Liquidity. During the last six months, we have taken several steps to improve our liquidity as a result of the deterioration in the capital markets and the decrease in oil and natural gas prices (see “Capital Resources and Liquidity”).

     2008 Operating Highlights. Oil and natural gas prices were extremely volatile during 2008, with NYMEX oil prices setting a record high of approximately $145 per Bbl around mid-year, followed by a rapid drop during the second half of the year to below $40 per Bbl, a price level not seen since 2004, finishing the year at $44.60 per Bbl. Natural gas prices followed a similar trend in 2008, beginning the year at $7.48 per Mcf, increasing to approximately $13.60 per Mcf in mid-2008, and then ending 2008 at slightly under $6.00 per Mcf. See the charts below for further information on the fluctuations in oil and natural gas prices during 2008.

     In spite of the commodity price volatility, our average revenue per BOE for the year was $79.42, approximately 34% higher than 2007’s average of $59.17 per BOE. These higher prices were a significant contributor to our record cash flow and earnings. Our 2008 cash flow from operations was $774.5 million, a 36% increase over our 2007 annual cash flow from operations of $570.2 million, and our 2008 net income of $388.4 million was 53% higher than our $253.1 million of net income during 2007. In addition to higher commodity prices during 2008, we had record high production levels, partially offset by higher operating costs and a $30.6 million charge related to the cancellation of the Conroe Field acquisition in early October (see also “Capital Resources and Liquidity” below). During 2008, we also had two significant non-cash operational items, (i) a net gain of $257.6 million ($159.7 million net of tax) associated with our fair value adjustments on our derivative contracts, the majority of which were related to the 2009 oil price collars acquired in October 2008, and (ii) a full cost ceiling write-down at December 31, 2008, of $226.0 million ($140.1 million net of tax) incurred because of the significant decrease in oil and natural gas prices during the latter part of 2008.

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

     During 2008 our oil and natural gas production averaged 46,343 BOE/d, an 18% increase over our 2007 average production (after adjusting for the sale of our Louisiana natural gas properties in December 2007 and February 2008), with growth primarily from our tertiary oil operations and Barnett Shale, partially offset by modest declines in our East Mississippi non-tertiary production. Our average tertiary oil production increased to 19,377 BOE/d in 2008, a 31% increase over our 2007 tertiary oil production levels, and our average Barnett Shale production increased to 12,699 BOE/d, a 33% increase year-over-year. (See “Results of Operations — Operating Results — Production” for more information). Our oil and natural gas revenues increased 41% in 2008, with 5% of the increase associated with the higher production levels and 36% of the increase due to higher oil and natural gas commodity prices.

     Our operating costs have gradually increased over the last few years along with commodity prices; the cost inflation caused by a corresponding increase in the demand for goods and services in our business as a result of commodity price escalation. While we recognized some cost savings during the last quarter of 2008 following the sharp decline in commodity prices during the second half of the year, operating costs have not decreased at the same rate as commodity prices. Therefore on average, virtually all of our expenses increased on both an absolute and per BOE basis during 2008. This continued a trend that we have experienced over the last several years as our costs have been increasing, due to (i) higher overall industry costs, (ii) a higher percentage of operations related to tertiary operations (which have higher operating costs per BOE), and (iii) higher compensation expense resulting from additional employees and increased salaries, which we consider necessary in order to remain competitive in the industry. We expect to see further cost reductions in 2009, as we believe that lower spending levels in the industry will reduce demand for goods and services and eventually lower costs, but it is uncertain how quickly costs will come down and by how much.

     We invested approximately $1.1 billion in capital projects and minor acquisitions during 2008, of which approximately $462.9 million was spent on CO₂ pipelines, facilities and drilling. During 2008 our proved oil and natural gas reserves increased from 194.7 MMBOE as of December 31, 2007 to 250.5 MMBOE at December 31, 2008, replacing approximately 525% of our 2008 production, almost entirely from organic growth. The most significant reserve additions during 2008 were approximately 63.4 MMBbls added in our tertiary oil operations, primarily associated with the booking of proved tertiary reserves at Tinsley, Heidelberg and Lockhart Crossing Fields, and 19.5 MMBOE added in our Barnett Shale operations.

     Genesis Transactions. On May 30, 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving our Northeast Jackson Dome (“NEJD”) and Free State CO₂ Pipelines, which included a long-term transportation service arrangement for the Free State Pipeline and a 20-year financing lease for the NEJD system. We received from Genesis $225 million in cash and $25 million of Genesis common units (1,199,041 units at an average price of $20.85 per unit). These transactions were treated as financing leases for accounting purposes, with the assets and liabilities recorded on our balance sheet. We currently project that we will initially pay Genesis approximately $30 million per annum under the financing lease and transportation services agreement, with future payments for the NEJD pipeline fixed at $20.7 million per year during the term of the financing lease, and the payments relating to the Free State Pipeline dependent on the volumes of CO₂ transported therein, with a minimum annual payment thereon of $1.2 million.

     Change in Tax Accounting Method for Certain Tertiary Costs. During the third quarter of 2008, we obtained approval from the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. Previously, we had capitalized and depreciated these costs, but now we can deduct these costs once the assets are placed into service. As a result, we expect to receive tax refunds of approximately $10.6 million for tax years through 2007, along with other tax benefits, and we have reduced our current income tax expense and increased our deferred income tax expense in 2008 to adjust for the impact of this change. This change is not expected to have a significant impact on our overall tax rate; however, it will allow for a quicker deduction of costs for tax purposes.

     This change in tax treatment impacts the overall economics of certain financing-type transactions we have historically utilized, primarily equipment lease financing and certain transactions with Genesis. Following the favorable ruling, we initially discontinued our leasing program and pipeline financings with Genesis, but with the recent downturn in commodity prices, we anticipate that our cash income taxes for 2009 will be minimal, minimizing the effect of this change in tax accounting. With lower projected cash income taxes expected for the near future, and given the generally advantageous interest rate inherent in equipment lease transactions, and their being an alternative source of liquidity, we plan to resume our equipment leasing program in 2009 and budgeted

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

$100 million of leasing in 2009, but if possible, we would like to lease as much as $150 million. Because of the uncertainties that exist in the capital markets, we cannot be certain of the dollar amount, pricing or availability of such equipment financing leases.

     The economic impact of our acceleration of tax deductions will also affect how we view future asset transactions with Genesis. Transactions which are not sales for tax purposes, such as the $175 million financing lease on the NEJD CO₂ Pipeline (see “Overview — Genesis Transactions” above) would not be affected provided that they meet other necessary tax criteria. Those transactions which constitute a sale for tax purposes, such as the $75 million sale and associated long-term transportation service agreement entered into with Genesis on our Free State CO₂ Pipeline (see “Overview — Genesis Transactions” above), will be less advantageous from a tax perspective.

     Sale of Louisiana Natural Gas Assets. In February 2008, we received the $48.9 million remaining portion (30%) of the proceeds from the sale of our Louisiana natural gas assets, the prior 70% of which closed in December 2007. Production attributable to the sold properties averaged 302 BOE/d (approximately 81% natural gas) during the first quarter of 2008, representing production prior to the closing date for the portion of the sale that closed in February.

     Recent 2009 Transactions

     Purchase of Hastings Field. On February 2, 2009, we closed the $201 million acquisition of the Hastings Field, which is located near Houston, Texas, and is a potential tertiary oil field to be supplied by the Green CO₂ Pipeline which has commenced construction. In August 2008, we exercised our option with a subsidiary of Venoco, Inc. (“Venoco”) to purchase Hastings Field, and in consideration of our exercising the option in 2008 rather than 2009, Venoco agreed to extend the deadlines for capital expenditures, commencement of CO₂ injections and certain other contractual requirements by one year.

     Management Succession Plan. On February 5, 2009, our Board of Directors adopted a management succession plan under which our current executive officers will assume new roles on or about June 30, 2009. Gareth Roberts, the Company’s founder, will relinquish his position as President and CEO and become Co-Chairman of the Board of Directors and will assume a non-officer role as the Company’s Chief Strategist. Phil Rykhoek, currently Senior Vice President and Chief Financial Officer, will become CEO; Tracy Evans, currently Senior Vice President — Reservoir Engineering, will become President and Chief Operating Officer; and Mark Allen, currently Vice President and Chief Accounting Officer, will become Senior Vice President and Chief Financial Officer.

     Subordinated Debt Issuance. On February 13, 2009, we issued $420 million of 9.75% Senior Subordinated Notes due 2016 (the “Notes”). The Notes were sold to the public at 92.816% of par, plus accrued interest from February 13, 2009, which equates to an effective yield to maturity of approximately 11.25% (before offering expenses). Interest on the Notes will be paid on March 1 and September 1 of each year, beginning September 1, 2009. The Notes will mature on March 1, 2016. We used the net proceeds from the offering of approximately $381 million to repay most of the then outstanding debt on our bank credit facility.

Capital Resources and Liquidity

     During the last six months, we have taken several steps to improve our liquidity as a result of the deterioration in the capital markets and the decrease in oil and natural gas commodity prices. These included a $400 million increase to our bank commitment amount (see “Increased Bank Credit Line” below for more details), cancellation of the $600 million acquisition of Conroe Field, purchase of oil derivative contracts covering approximately 80% of our currently estimated 2009 oil production, and reduction of our capital budget for 2009. Also, in February 2009, we issued $420 million of Senior Subordinated Notes (see “Overview — Recent 2009 Transactions — Subordinated Debt Issuance”).

     Prior to the decline in economic conditions, we had intended, in a tax free exchange, to exchange the Barnett Shale properties for the Conroe and Hastings Fields, both of which are future tertiary flood candidates located near Houston, Texas. However, because of the deterioration in capital market conditions, we believed that the sale of our Barnett Shale properties at a price that we would consider reasonable was doubtful, and without the certainty of a Barnett Shale property sale, we did not feel comfortable increasing our leverage. As such, we cancelled our $600 million contract to purchase Conroe Field, forfeiting a $30 million non-refundable deposit which we expensed in the third quarter. To further protect our liquidity in the event that commodity prices continued to decline, in October

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

2008 we purchased oil derivative contracts for 2009 with a floor price of $75 / Bbl and a ceiling price of $115 / Bbl for total consideration of $15.5 million. The collars cover 30,000 Bbls/d representing approximately 80% of our currently anticipated 2009 oil production. See “Oil and Natural Gas Derivative Contracts” below in this section for information regarding the counterparties for these collars. We further significantly increased our liquidity in February 2009 by issuing $420 million of subordinated debt. We used net proceeds from that offering ($381 million) to repay most of our then outstanding bank debt, freeing-up most of our bank credit line for future capital needs, as our total bank commitment amount of $750 million was not reduced because of the offering.

     We currently estimate that our 2009 total capital spending will be approximately $750 million, plus the already closed Hastings acquisition of $201 million. Our current 2009 capital budget includes approximately $485 million relating to our CO₂ pipelines, the majority of which is to build the Green CO₂ Pipeline. The budget also assumes that we fund approximately $100 million of budgeted equipment purchases with operating leases, a practice we had discontinued in the last half of 2008 as a result of our favorable tax ruling (see “Overview — Change in Tax Accounting Method for Certain Tertiary Costs”). Use of these operating leases is dependent upon being able to secure acceptable financing and as of February 27, 2009, we had not yet secured most of this financing. The 2009 budget incorporates significantly reduced spending in the Barnett Shale and in other conventional areas such as the Heidelberg Selma Chalk, and a slower development program for our tertiary operations. Based on our current cash flow projections, using $50.00 per barrel for oil and $5.00 per Mcf for natural gas prices and including our expected oil derivative contract settlements, we anticipate that our capital expenditures could exceed projected cash flow by $400 million to $500 million, including the Hastings acquisition.

     We anticipate funding this shortfall during 2009 with the proceeds from our February 2009 subordinated debt issuance and our bank credit line, and expect to have a total bank debt balance by the end of 2009 of $150 million to $250 million, leaving us $500 million to $600 million of availability on our $750 million bank commitment amount. We anticipate that this credit line will be sufficient to fund our 2009 plans and do not expect our bank credit line to be reduced by our banks unless commodity prices were to further decrease significantly from current levels. We may raise additional capital during 2009 if it is possible to do so in a reasonably economic manner. Such additional capital sources could include the sale or joint venture of assets, a volumetric production payment, additional operating leases, or other options that become available during the year. We will also continually monitor our capital expenditures on a regular basis, adjusting them up or down depending on commodity prices and the resultant cash flow. Therefore, should our cash flow be less than expected, we would plan to reduce our capital expenditures to the extent possible during the year, which could in turn, have the impact of reducing our anticipated production levels in future years. For 2009, we have contracted for certain capital expenditures, including construction of most of the Green Pipeline already in progress and two drilling rigs, and therefore the portion of capital that we could eliminate without significant penalty is limited (see also “Off-Balance Sheet Arrangements — Commitments and Obligations”).

     Based on our long-term models, we expect our future capital spending needs to be less in the future than they have been in recent years, excluding any potential acquisitions. Therefore, if commodity prices remain at current levels after 2009, we anticipate that we will be able to match our capital spending with our projected cash flow from operations and preserve our liquidity to the extent that we deem necessary, although any such spending reductions would most likely lower our anticipated rate of production growth.

     Increased Bank Credit Line. In early October 2008, we amended our bank credit facility, which increased the banks’ commitment amount from $350 million to $750 million, maintained our borrowing base at $1.0 billion, modified the commitment fees and pricing grid for the loan, raising the pricing grid by 25 basis points, and provided for other transactions, such as the acquisition of Conroe Field, which were not consummated. The borrowing base represents the amount that can be borrowed from a credit standpoint while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. We further amended our bank credit facility in February 2009 to allow us to issue the subordinated debt at an interest rate higher than the previously allowed 10% (see “Overview — Recent 2009 Transactions — Subordinated Debt Issuance”).

     While bank borrowing bases in our industry are likely to be reduced in the future to reflect the reduction in commodity prices, with $250 million of cushion between our borrowing base and commitment amount and the incremental value added by retaining our Barnett Shale properties, currently we do not expect our bank commitment level to be reduced below $750 million unless prices were to further decrease significantly from current strip prices of approximately $45.00 per barrel for oil and $5.00 per Mcf for natural gas. As of February 27, 2009, we had

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

outstanding $525 million (principal amount) of 7.5% subordinated notes, $420 million (principal amount) of 9.75% Senior Subordinated Notes and $60 million of bank debt.

     Although we remain interested in acquiring mature oil fields that we believe have potential as future tertiary flood candidates, with the general lack of liquidity in the capital markets, our ability to fund any significant acquisitions will be limited and are not likely to be material unless we are able to obtain additional capital.

Sources and Uses of Capital Resources

Capital Expenditure Summary
		Year Ended December 31,
Amounts in thousands		2008				2007				2006
Capital expenditures
Oil and gas exploration and development
Drilling		$	244,841			$	313,258			$	245,350
Geological, geophysical and acreage			18,183				22,829				31,590
Facilities			170,263				118,003				98,890
Recompletions			140,451				141,264				120,438
Capitalized interest			17,627				18,305				11,059
Total oil and gas exploration and development expenditures			591,365				613,659				507,327
Oil and natural gas property acquisitions			31,367				49,077				319,000
Total oil and natural gas capital expenditures			622,732				662,736				826,327
CO2 capital expenditures, including capitalized interest			462,889				171,182				63,586
Total		$	1,085,621			$	833,918			$	889,913

     Our 2008 capital expenditures were funded with $774.5 million of cash flow from operations, $225 million from the drop-down of CO₂ pipelines to Genesis, and $51.7 million from property sales proceeds.

     Our 2007 capital expenditures were funded with $570.2 million of cash flow from operations, $150.0 million from the April 2007 issuance of subordinated debt, $135.8 million from property sales proceeds, and $16.0 million of net bank borrowings.

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

Off-Balance Sheet Arrangements

Commitments and Obligations

     At December 31, 2008, our dollar denominated payment obligations that are not on our balance sheet include our operating leases, which at year-end 2008 totaled $128.6 million (including $104.5 million of equipment costs) relating primarily to the lease financing of certain equipment for CO₂ recycling facilities at our tertiary oil fields. We also have several leases relating to office space and other minor equipment leases. At December 31, 2008, we had a total of $10.5 million of letters of credit outstanding under our bank credit agreement. Additionally, we have dollar denominated obligations that are not currently recorded on our balance sheet relating to various obligations for development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs forecasted in our proved reserve reports. For a further discussion of our future development costs and proved reserves, see “Results of Operations — Depletion, Depreciation and Amortization” below.

     Genesis Energy, LLC, our subsidiary that is the general partner of Genesis (a limited partnership), could under certain circumstances become liable, in its capacity as general partner, for debts and obligations of Genesis. There were no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, LLC at December 31, 2008.

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

During the second quarter of 2008, we entered into transactions with Genesis relating to two of our CO₂ pipelines (see “Overview — Genesis Transactions” above). As a result of these two transactions, we currently project that we will initially pay Genesis approximately $30 million per annum under the financing lease and transportation services agreement (a pro-rated total of $15.4 million during 2008), with future payments for the NEJD pipeline fixed at $20.7 million per year during the term of the financing lease, and the payments relating to the Free State Pipeline dependent on the volumes of CO₂ transported therein, with a minimum annual payment thereon of $1.2 million.

     We currently have long-term commitments to purchase CO₂ from four proposed gasification plants, two of which are in the Gulf Coast region and two in the Midwest region (Illinois / Kentucky area) of the United States. The Midwest plants are not only conditioned on those specific plants being constructed, but also upon Denbury contracting additional volumes of CO₂ for purchase in the general area of the proposed plants that would provide an acceptable economic return on the CO₂ pipeline that we would need to construct to transport these volumes to our existing CO₂ pipeline system. If all four plants are built, these CO₂ sources are currently anticipated to provide us with aggregate CO₂ volumes of around 1 Bcf/d. Due to the current economic conditions, the earliest we would expect any plant to be completed and provide CO₂ would be 2013, and there is some doubt as to whether they will be constructed at all. The base price of CO₂ per Mcf from these CO₂ sources varies by plant and location, but is generally higher than our most recent all-in cost of CO₂ from our natural sources (Jackson Dome) using current oil prices. Prices for CO₂ delivered from these projects are expected to be competitive with the cost of our natural CO₂ after adjusting for our share of potential carbon emissions reduction credits using estimated futures prices of carbon emissions reduction credits. If all four plants are built, the aggregate purchase obligation for this CO₂ would be around $135 million per year, assuming a $50 per barrel oil price, before any potential savings from our share of carbon emissions reduction credits. All of the contracts have price adjustments that fluctuate based on the price of oil. Construction has not yet commenced on any of these plants, and their construction is contingent on the satisfactory resolution of various issues, including financing. While it is likely that not every plant currently under contract will be constructed, there are several other plants under consideration that could provide CO₂ to us that would either supplement or replace the CO₂ volumes from the four proposed plants that we currently have contracts with. We are having ongoing discussions and negotiations with several of these other potential sources. We have not included any financial commitment attributable to the existing contracts or other potential sources in the commitment table below as all such payments are contingent on the plants being built.

     A summary of our obligations at December 31, 2008, is presented in the following table:

		Payments Due by Period
Amounts in thousands		Total				2009				2010				2011				2012				2013				Thereafter
Contractual Obligations:
Subordinated debt (a)		$	525,000			$	—			$	—			$	—			$	—			$	225,000			$	300,000
Senior Bank Loan (a)			75,000				—				—				75,000				—				—				—
Estimated interest payments on subordinated debt and Senior Bank Loan (a)			234,096				41,588				41,588				40,933				39,375				26,661				43,951
Pipeline financing lease obligations (b)			588,414				29,358				31,759				33,205				33,438				33,518				427,136
Operating lease obligations			128,606				17,938				17,351				16,571				15,199				12,510				49,037
Capital lease obligations (c)			9,219				2,120				1,882				1,882				1,242				700				1,393
Capital expenditure obligations (d)			376,827				367,980				8,847				—				—				—				—
Other Cash Commitments:
Future development costs on proved oil and gas reserves, net of capital obligations (e)			890,262				97,048				312,069				188,275				115,605				61,921				115,344
Future development cost on proved CO2 reserves, net of capital obligations (f)			116,792				18,792				—				22,000				—				—				76,000
Asset retirement obligations (g)			106,413				2,154				1,321				1,288				722				1,013				99,915
Total		$	3,050,629			$	576,978			$	414,817			$	379,154			$	205,581			$	361,323			$	1,112,776

(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. On February 13, 2009 we issued $420 million of 9.75% Senior Subordinated Notes at a discount, 92.816% of par, for which the obligations related thereto are not included in the above table. See Note 14 to the Consolidated Financial Statements.

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

(b)		Represents estimated future cash payments under a long-term transportation service agreement for the Free State Pipeline, and future minimum cash payments in a 20-year financing lease for the NEJD pipeline system. Both transactions with Genesis were entered into in 2008 and are being accounted for as financing leases. The payment required for the Free State Pipeline is variable based upon the amount of the CO2 we ship through the pipeline and the commitment amounts disclosed above for that line are computed based upon our internal forecasts. Approximately $338.2 million of these payments represent interest. See Note 3 to Consolidated Financial Statements.
(c)		Represents future minimum cash commitments of $5.9 million to Genesis under capital leases in place at December 31, 2008, primarily for transportation of crude oil and CO2, and $3.3 million for office space and rental equipment. Approximately $2.0 million of these payments represents interest.
(d)		Represents future cash commitments under contracts in place as of December 31, 2008, primarily for pipe, pipeline construction contracts, drilling rig services and well related costs, including approximately $311.2 million for our Green CO2 Pipeline. 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 2009 is currently set at $750 million, exclusive of acquisitions. In certain cases we have the ability to terminate contracts for equipment in which case we would only be liable for the cost incurred by the vendor up to that point; however, as we currently do not anticipate cancelling those contracts these amounts include our estimated payments under those contracts. We also have recurring expenditures for such things as accounting, engineering and legal fees, software maintenance, subscriptions, and other overhead type items. Normally these expenditures do not change materially on an aggregate basis from year to year and are part of our general and administrative expenses. We have not attempted to estimate the amounts of these types of recurring expenditures in this table as most could be quickly cancelled with regard to any specific vendor, even though the expense itself may be required for ongoing normal operations of the Company.
(e)		Represents projected capital costs as scheduled in our December 31, 2008 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 under “Contractual Obligations” in the table above.
(f)		Represents projected capital costs as scheduled in our December 31, 2008 proved reserve report that are necessary in order to recover our proved undeveloped CO2 reserves from our CO2 source wells used to produce CO2 for our tertiary operations. These are not contractual commitments and are net of any other capital obligations shown above.
(g)		Represents the estimated future asset retirement obligations on an undiscounted basis. The present discounted asset retirement obligation is $45.1 million, as determined under SFAS No. 143, and is further discussed in Note 4 to the Consolidated Financial Statements.

     During February 2009, we closed our $201 million purchase of Hastings Field (see “Recent 2009 Transactions — Purchase of Hastings Field” above). Under the agreement, we are required to make aggregate net capital expenditures in this field of approximately $179 million over the next six years as follows (the following amounts representing cumulative amounts required by that date): $26.8 million by December 31, 2010, $71.5 million by December 31, 2011, $107.2 million by December 31, 2012, $142.9 million by December 31, 2013, and $178.7 million by December 31, 2014. If we fail to spend the required amounts by the due dates, we are required to make a cash payment equal to 10% of the cumulative shortfall at each applicable date. Further, we are committed to injecting at least an average of 50 MMcf/day of CO₂ (total of purchased and recycled) in the West Hastings Unit for the 90 day period prior to January 1, 2013. If such injections do not occur, we must either (1) relinquish our rights to initiate (or continue) tertiary operations and reassign to Venoco all assets previously purchased for the value of such assets at that time based upon the discounted value of the field’s proved reserves using a 20% discount rate, or (2) make an additional payment of $20 million in January 2013, less any payments made for failure to meet the capital spending requirements as of December 31, 2012, and a $30 million payment for each subsequent year (less amounts paid for capital expenditure shortfalls) until the CO₂ injection in the Hastings Field equals or exceeds the minimum required injection rate.

     Long-term contracts require us to deliver CO₂ to our industrial CO₂ customers at various contracted prices, plus we have a CO₂ delivery obligation to Genesis pursuant to three volumetric production payments (“VPP”) entered into during 2003 through 2005. Based upon the maximum amounts deliverable as stated in the industrial contracts and the volumetric production payments, we estimate that we may be obligated to deliver up to 512 Bcf of CO₂ on a cumulative basis to these customers over the next 19 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 254 Bcf. The maximum volume required in any given year is approximately 136 MMcf/d, although based on our current level of deliveries this would likely be reduced to approximately 78 MMcf/d. Given the size of our proven CO₂ reserves at December 31, 2008 (approximately 5.6 Tcf before deducting approximately 153.8 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.

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

Results of Operations

CO₂ Operations

     Overview. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999, we have gradually increased our emphasis on these types of operations. During this time, we have learned a considerable amount about tertiary operations and working with carbon dioxide. Our tertiary operations have grown to the point that approximately 50% of our December 31, 2008 proved reserves are proved tertiary oil reserves, almost 50% of our forecasted 2009 production is expected to come from tertiary oil operations (on a BOE basis), and almost all of our 2009 capital expenditures are related to our current or future tertiary operations. We particularly like this play as (i) it has a lower risk and is more predictable than most traditional exploration and development activities, (ii) it provides a reasonable rate of return at relatively low oil prices (we estimate our economic break-even per barrel dollar cost on these projects at current oil prices is in the range of the mid-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 CO₂ except our own, and these large volumes of CO₂ that we own drive the play. In addition, we are pursuing anthropogenic (man-made) sources of CO₂ to use in our tertiary operations, which we believe will not only help us recover additional oil, but will provide an economical way to sequester CO₂. We have acquired several old oil fields in our areas of operations with potential for tertiary recovery and plan to acquire additional fields, and we are continuing to expand our CO₂ pipeline infrastructure to transport CO₂.

     We talk about our tertiary operations by labeling operating areas or groups of fields as phases. Phase I is in Southwest Mississippi and includes several fields along our 183-mile NEJD CO₂ Pipeline that we acquired in 2001. The most significant fields in this area are Little Creek, Mallalieu, McComb and Brookhaven. Phase II, which began with the early 2006 completion of the Free State CO₂ Pipeline to East Mississippi, includes Eucutta, Soso, Martinville and Heidelberg Fields. Tinsley Field located northwest of Jackson, Mississippi, acquired in January 2006, is our Phase III and is serviced by that portion of the Delta CO₂ Pipeline completed in January 2008. Phase IV includes Cranfield and Lake St. John Fields, two fields near the Mississippi/Louisiana border located west of the Phase I fields, and Phase V is Delhi Field, a Louisiana field we acquired in 2006, located southwest of Tinsley Field. Flooding in Phase V is anticipated to begin in 2009 upon completion of the Delta CO₂ Pipeline from Tinsley to Delhi. Citronelle Field in Southwest Alabama, another field acquired in 2006, is our Phase VI which will require an extension to the Free State CO₂ Pipeline, the timing of which is uncertain at this time. Our last two currently existing phases will require completion of our proposed Green Pipeline, a 320-mile CO₂ pipeline which will run from Southern Louisiana to near Houston, Texas, and is scheduled for completion in 2010. Hastings Field, a field which we purchased in February 2009 (see “Commitments and Contingencies”), is our Phase VII, and the Seabreeze Complex, acquired in 2007, will be our Phase VIII.

     CO₂ Resources. Since we acquired the CO₂ source field located near Jackson, Mississippi, in 2001, we have continued to develop the field and have increased the proven CO₂ reserves from approximately 800 Bcf at the time of the acquisition to approximately 5.6 Tcf as of December 31, 2008. During 2008, the increase in our proven CO₂ reserves was offset by the 233 Bcf of CO₂ production during the year. The estimate of 5.6 Tcf of proved CO₂ reserves is based on 100% ownership of the CO₂ reserves, of which Denbury’s net revenue interest ownership is approximately 4.5 Tcf. Both reserve estimates are included in the evaluation of proven CO₂ reserves prepared by DeGolyer and MacNaughton. In discussing the available CO₂ reserves, we make reference to the gross amount of proved reserves, as this is the amount that is available for Denbury’s tertiary recovery programs, Genesis, and industrial users, as Denbury is responsible for distributing the entire CO₂ production stream for all of these uses. We currently estimate that it will take approximately 1.8 Tcf of CO₂ to develop and produce the proved tertiary recovery reserves we have recorded at December 31, 2008, in Phases I, II and III.

     Today, we own every known producing CO₂ well in the region, providing us a significant strategic advantage in the acquisition of other properties in Mississippi, Louisiana and Texas that could be further exploited through tertiary recovery. As of February 27, 2009, we estimate that we are capable of producing between 900 MMcf/d and 1 Bcf/d of CO₂, over eight 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 one more well planned for 2009, in order to further increase our production capacity. Our drilling activity at Jackson Dome will continue beyond 2009 as our current forecasts for the existing eight phases suggest that we will need approximately 1.4 Bcf/d of CO₂ production by 2013.

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

     In addition to using CO₂ for our tertiary operations, we sell CO₂ to third party industrial users under long-term contracts. Most of these industrial contracts have been sold to Genesis along with the sale of volumetric production payments for the CO_2. Our average daily CO₂ production during 2006, 2007 and 2008 was approximately 342 MMcf/d, 493 MMcf/d and 637 MMcf/d, respectively, of which approximately 75% in 2006, 81% in 2007 and 86% in 2008 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 $0.22 per Mcf in operating expenses to produce our CO₂ during 2008, more than our 2007 average of $0.21 per Mcf and our 2006 average of $0.19 per Mcf, with the higher costs each year primarily due to higher average oil costs, which is the basis upon which we pay royalty owners for the CO₂, and higher operating costs. Our CO₂ costs peaked at $0.27 per Mcf in the second quarter of 2008, corresponding to the peak in oil prices, but decreased during the fourth quarter of 2008 to an average of approximately $0.15 per Mcf as a result of the decline in oil prices. Our estimated total cost per thousand cubic feet of CO₂ during 2008 was approximately $0.30, after inclusion of depreciation and amortization expense related to the CO₂ production, as compared to approximately $0.29 per Mcf during 2007 and $0.28 per Mcf during 2006.