UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
2002 FORM 10-K
 (Mark One)

|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
 OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to________
COMMISSION FILE NUMBER 1-12935
DENBURY RESOURCES INC.
 (Exact name of Registrant as specified in its charter)

           DELAWARE                                            75-2815171
  (State or other jurisdiction                              (I.R.S. Employer
of incorporation or organization)                          Identification No.)

        5100 TENNYSON PARKWAY,
        SUITE 3000, PLANO, TX                                     75024
(Address of principal executive offices)                        (Zip Code)

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

                   TITLE OF EACH CLASS                             NAME OF EACH EXCHANGE ON WHICH REGISTERED
---------------------------------------------------------- ---------------------------------------------------------
Common Stock $.001 Par Value                                                New York Stock Exchange
========================================================== =========================================================	

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None
Indicate by check mark 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 [X] No [ ]
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. [X]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). [X]
As of March 18, 2003, the aggregate market value of the registrant's Common Stock held by non-affiliates was approximately $376,852,000.
The number of shares outstanding of the registrant's Common Stock as of March 18, 2003, was 53,682,038.

                       DOCUMENTS INCORPORATED BY REFERENCE

DOCUMENT                                                                  INCORPORATED AS TO
1. Notice and Proxy Statement for the Annual Meeting of          1.  Part III, Items 10, 11, 12, and 13
   Shareholders to be held May 20, 2003.
2. Annual Report to Shareholders for the year ended              2.  Part I, Item 1 and Part II, Items 5, 6, 7, 8
   December 31, 2002.	

                                                DENBURY RESOURCES INC.
                                            2002 ANNUAL REPORT ON FORM 10-K
                                                   TABLE OF CONTENTS

ITEM                                                                                               PAGE
                                                     PART I
1.               Business............................................................................ 3
2.               Properties..........................................................................10
3.               Legal Proceedings.................................................................. 10
4.               Submission of Matters to a Vote of Security Holders................................ 10

                                                     PART II

5.               Market for the Common Stock and Related Matters.................................... 11
6.               Selected Financial Data............................................................ 11
7.               Management's Discussion and Analysis of Financial Condition and Results of
                 Operations......................................................................... 11
7A.              Quantitative and Qualitative Disclosures About Market Risk......................... 11
8.               Financial Statements and Supplementary Data........................................ 11
9.               Changes in and Disagreements with Accountants on Accounting
                     and Financial Disclosure....................................................... 11

                                                    PART III

10.              Directors and Executive Officers of the Company.................................... 12
11.              Executive Compensation............................................................. 12
12.              Security Ownership of Certain Beneficial Owners and Management..................... 12
13.              Certain Relationships and Related Transactions..................................... 12
14.              Controls and Procedures............................................................ 12

                                                     PART IV

15.              Exhibits, Financial Statement Schedules and Reports on Form 8-K ................... 13
                 Signatures ........................................................................ 15
                 Certifications..................................................................... 16	

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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 our internet website, www.denbury.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. In addition, we have adopted a Code of Ethics for Senior Financial Officers and the Principal Executive Officer. We have posted this Code of Ethics on our website, where we also intend to post any waivers from or amendments to this Code of Ethics.
THE COMPANY
Denbury Resources Inc. is a Delaware corporation, organized under Delaware General Corporation Law, engaged in the acquisition, development, operation and exploration of oil and natural gas properties in the Gulf Coast region of the United States, primarily in Louisiana, Mississippi and in the Gulf of Mexico. Our corporate headquarters is located at 5100 Tennyson Parkway, Suite 3000, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2002, we have 356 employees, 239 of which were employed in field operations or at the field offices.
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.
BUSINESS STRATEGY
As part of our business strategy, we seek to:
o achieve attractive returns on capital through prudent acquisitions and subsequent exploitation of those acquired reserves;
o maintain a balanced portfolio of quality assets;
o maintain a conservative balance sheet to ensure maximum financial and operational flexibility; and
o create strong employee incentives through equity ownership throughout our company.
We believe that our growth to date in proved reserves, production, net asset value and cash flow is a direct result of our adherence to several fundamental principles that are at the core of our long-term growth strategy. During the last few years, by remaining focused in our core areas and through several small but strategic acquisitions, we have developed a unique competitive advantage in Mississippi with our carbon dioxide tertiary recovery program. Our position gives us the opportunity to increase reserves in our tertiary recovery program at attractive finding costs in a relatively low risk manner. At the same time, we have balanced our portfolio and improved the overall quality of our production by acquiring offshore Gulf of Mexico natural gas properties through our acquisition of Matrix Oil & Gas, Inc. in July 2001.
ACQUISITIONS
Information as to recent acquisitions by us is set forth under "Management's Discussion and Analysis of Financial Condition and Results of Operations - 2002 Acquisitions," appearing on page 27 of the Annual Report and under Note 2, "Acquisitions," to the Consolidated Financial Statements. Such information is incorporated herein by reference.
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OIL AND GAS OPERATIONS
Information regarding selected operating data and a discussion of our significant operating areas and the primary properties within those three areas are set forth under "Selected Operating Data," appearing on pages 8 through 11 of the Annual Report, and the "Operations Report" appearing on pages 14 through 24 of the Annual Report. Such information is incorporated herein by reference.
OIL AND GAS ACREAGE, PRODUCTIVE WELLS, DRILLING ACTIVITY
Information regarding oil and gas acreage, productive wells and drilling activity are set forth under "Selected Operating Data," appearing on page 11 of the Annual Report.
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 taken as a whole we have good title to our oil and natural gas properties, some of which are subject to minor encumbrances, easements and restrictions.
PRODUCTION
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" appearing on pages 33 through 36 of the Annual Report.
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. 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. For the year ended December 31, 2002, we had two significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Hunt Refining (14%) and Genesis (11%). For the year ended December 31, 2001, four purchasers each accounted for 10% or more of our oil and natural gas revenues: Conoco (14%), Hunt Refining (13%), EOTT Energy (12%), and Dynegy (12%). For the year ended December 31, 2000, four purchasers each accounted for 10% or more of our oil and natural gas revenues: Hunt Refining (24%), Southland Refining (17%), EOTT Energy (16%), and Dynegy (10%).
Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the proximity of our gas production to pipelines, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation. Our production is primarily from developed fields close to major pipelines or refineries and established infrastructure. As a result, we have not experienced any difficulty to date in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to market all of our production or obtain favorable prices.
Oil Marketing
The quality of our crude oil varies by area as well as the corresponding price received. In Heidelberg Field, our single largest field, and our other non-CO2 flood properties in Mississippi, our oil production is primarily light to medium sour crude and sells at a significant discount to the NYMEX prices. In Western Mississippi, our CO2 flood properties, and in Louisiana, our oil production is primarily light sweet crude, which typically sells at a small discount to NYMEX. For the
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year ended December 31, 2002, the discount for our oil production from Heidelberg Field and our other non-CO2 flood properties in Mississippi properties averaged a discount of $4.37 per Bbl. For our CO2 flood properties in Western Mississippi, our discount in 2002 averaged $0.72 per Bbl.
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.
Product Price Derivative Hedging Contracts
We enter into various financial contracts to hedge our exposure to commodity price risk associated with anticipated future oil and natural gas production. Information as to these activities is set forth under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Management," appearing on pages 40 through 41 of the Annual Report and in Note 7, "Derivative Hedging Contracts," to the Consolidated Financial Statements. Such information is incorporated herein by reference.
RISKS OF OUR BUSINESS
Oil and Natural Gas Price Volatility
Our future financial condition, results of operations and the carrying value of our oil and natural gas properties depends primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and likely will continue to be volatile in the future. This price volatility also affects the amount of cash flow available to us for capital expenditures and impacts 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 based on current prices at the time of redetermination. In the short-term, our production is balanced between oil and natural gas, but longer-term, oil prices are likely to have a greater impact on us because 74% of our reserves are oil, although for 2002 our production was 53% oil and 47% natural gas.
Over the last four years oil prices have gone from near historic low prices to higher prices not experienced for over ten years. At the end of 1998, NYMEX oil prices were at historic lows of approximately $12.00 per Bbl, but during 1999 and 2000 NYMEX oil prices increased to an average of approximately $19.30 and $30.25 per Bbl, respectively. During 2001, NYMEX oil prices declined to an average of approximately $26.00 per Bbl and were at $19.84 per Bbl at the end of 2001. Throughout 2002, NYMEX oil prices increased to average approximately $26.10 per Bbl and ended the year at $31.20 per Bbl.
Natural gas prices have experienced even more volatility over the same four year period. During 1999 natural gas prices averaged approximately $2.35 per Mcf and increased to an average of approximately $4.00 per Mcf during 2000, primarily due to low storage levels. At December 31, 2000, NYMEX natural gas prices were almost $10.00 per Mcf but declined steadily during 2001 as supplies of natural gas increased and as of year-end 2001, were $2.57 per Mcf. For 2002, natural gas prices generally increased throughout the year and averaged approximately $3.35 per Mcf and ended 2002 at $4.79 per Mcf.
Oil and natural gas prices are subject to wide fluctuations that result from a variety of factors, most of which are beyond our control. These factors include:
o relatively minor changes in the supply of and demand for oil and natural gas;
o weather conditions;
o market uncertainty;
o domestic and foreign governmental regulations and taxes;
o the availability and cost of alternative fuel sources;
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o the domestic and foreign supply of oil and natural gas;
o the price of foreign oil and natural gas;
o the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
o political conditions in oil and natural gas producing regions, including the Middle East and South America; and
o worldwide economic conditions.
These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. 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 and oil and natural gas reserves. Further, oil and natural gas prices do not necessarily move in tandem.
Oil and Natural Gas Drilling and Producing Operations
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:
o unexpected drilling conditions;
o title problems;
o pressure or irregularities in formations;
o equipment failures or accidents;
o adverse weather conditions;
o compliance with environmental and other governmental requirements; and
o cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.
The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of carbon dioxide ("CO2"). 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 production is also dependent on our ability to increase the production volumes of CO2. If our crude oil production were to decline, it could have a material adverse effect on our financial condition and results of operations. 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 a material adverse effect upon the profitability of these operations.
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.
In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above in an amount we believe is adequate. However, the nature of these risks is such that some liabilities could exceed our policy
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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 and financial condition.
Future Performance and Acquisitions
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. If we do not continue to make significant capital expenditures, or if outside capital resources become limited, we may not be able to maintain our growth rate. In addition, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves will be 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.
Our long-term business strategy includes growing our reserve base through acquisitions. We are continually identifying and evaluating acquisition opportunities and we have successfully completed acquisitions over the last several years. Estimating the reserves and forecasted production from acquired properties is inherently difficult and may result in our inability to achieve or maintain targeted production levels. In that case, our ability to realize the total economic benefit from the acquisition may be reduced or eliminated. There can be no assurance that we will successfully consummate any future acquisitions or that such acquisitions of oil and natural gas properties will contain economically recoverable reserves or that any future acquisition will be profitably integrated into our operations.
COMPETITION AND MARKETS
We face competition from other oil and natural gas companies in all aspects of its 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 balanced nature of our properties and reserves with regard to risk and commodity mix, our inventory of projects, and management's experience and expertise in exploiting these reserves, we believe that we are effective in competing in the market.
FEDERAL AND STATE REGULATIONS
Numerous federal, state and local laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to the current political or economic environment. Compliance with this regulatory burden increases our cost of doing business and affects our profitability. Changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations or profitability.
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Proposals and proceedings that might affect the oil and gas industry are pending before Congress, the Federal Energy Regulatory Commission, or "FERC", the Minerals Management Service, or "MMS", state legislatures and commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position. No material portion of our business is subject to re-negotiation of profits or termination of contracts or subcontracts at the election of the federal government.
The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.
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 or generated in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas we can produce from our wells in a given state and may limit the number of wells or the locations at which we can drill.
Federal Regulation of Sales Prices and Transportation
Currently, there are no federal, state or local laws that regulate the price for our sales of natural gas, NGLs, crude oil or condensate. However, the rates charged and terms and conditions for the movement of gas in interstate commerce through certain intrastate pipelines and production area hubs are subject to regulation under the Natural Gas Policy Act of 1978 ("NGPA"). Pipeline and hub construction activities are, to a limited extent, also subject to regulations under the Natural Gas Act of 1938 ("NGA"). While these controls do not apply directly to us, their effect on natural gas markets can be significant in terms of competition and cost of transportation services, which in turn can have a substantial impact on our profitability and costs of doing business. 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. We do not believe that we will be affected by any action taken in any materially different respect from other natural gas producers, gatherers and marketers with whom we compete.
Gathering Regulations
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Such regulation has not generally been applied against gatherers of natural gas, although 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, MMS and other agencies.
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Environmental Regulations
Public interest in the protection of the environment has increased dramatically in recent years. In addition, over the last two years we have acquired significant assets offshore in the Gulf of Mexico which are regulated by the MMS. Department of the Interior. 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 which regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements which may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company; (iv) the Oil Pollution Act of 1990 which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; and (vi) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material ("NORM").
In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials occur, and we incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we are able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributed to us under applicable state, federal or local laws or regulations.
Management believes that we are in substantial compliance with all currently applicable environmental laws and regulations. To date, compliance with such laws and regulations has not required the expenditure of any material amounts, and management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations. Since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. To our knowledge, there are currently no material adverse environmental conditions that exist on any of our properties and there are no current or threatened actions or claims by any local, state or federal agency or by any private landowner against us pertaining to such a condition. Further, we are not aware of any currently existing condition or circumstance that may give rise to such actions or claims in the future.
We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us.
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ESTIMATED NET QUANTITIES OF PROVED OIL AND GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES
Estimates of net proved oil and gas reserves as of December 31, 2002, 2001 and 2000 have been prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. See Note 10, "Supplemental Oil and Natural Gas Disclosures," to the Consolidated Financial Statements and pages 8 and 9 of the Annual Report for disclosure of reserve data. Such information is incorporated herein by reference.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control. The reserve data included herein represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and judgment. As a result, estimates of different engineers often vary. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, and are inherently imprecise. Actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from our estimates. Such variations may be significant and could materially affect estimated quantities and the present value of our proved reserves. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which Denbury or the oil and natural gas industry in general are subject.
You should not assume that the present values referred to herein represents the current market value of our estimated oil and natural gas reserves. 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. A change in price of $0.10 per Mcf and $1.00 per Bbl would result in a change in our December 31, 2002 PV-10 Value of proved reserves of approximately 1.0% and 3.3%, respectively. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in the Notes to Consolidated Financial Statements, which is calculated after provision for future income tax.
Quantities of proved reserves are estimated based on economic conditions, including oil and natural gas prices in existence at the date of assessment. Our reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs and other factors. Downward revisions of our reserves could have an adverse affect on our financial condition and operating results. Selected information on our reserves on properties we operate is filed with the DOE in its Annual Survey of Domestic Oil and Gas Reserves.
ITEM 2. PROPERTIES
See Item 1. Business - "Oil and Gas Operations." We also have various operating leases for rental of office space, office equipment, and vehicles. See Note 8, "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
Due to the nature of our business, we are involved in various legal or administrative proceedings that arise from time to time in the ordinary course of our business. In the opinion of management, there are no material pending legal proceedings to which Denbury or any of our subsidiaries is a party or of which any of their property is the subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of security holders during the fourth quarter of 2002.
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PART II
ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED MATTERS
Information as to the markets in which Denbury's common stock is traded, the quarterly high and low prices for such stock during the last two years, the restriction on the payment of dividends with respect to the common stock, and the approximate number of stockholders of record at February 1, 2003, is set forth under "Common Stock Trading Summary" appearing on page 70 of the Annual Report. Such information is incorporated herein by reference.
Affiliates of the Texas Pacific Group beneficially own approximately 32% of the Company's outstanding common stock and their representatives hold four of nine seats on Denbury's Board of Directors. As a result of its ownership, the Texas Pacific Group has the effective ability to elect all of Denbury's directors and to control its business and affairs, including decisions with respect to the acquisition or disposition of assets, the future issuance of our common stock or other securities, dividend policy and decisions with respect to the Company's drilling, operating and acquisition expenditure plans. Although the Company's articles of incorporation require a two-thirds majority vote by the board of directors on most significant transactions, such as significant asset purchases and sales, issuances of equity and debt, changes in the board of directors and other matters, there is no agreement that would prevent the Texas Pacific Group from replacing all directors of the Company by calling a meeting of Denbury's shareholders.
ITEM 6. SELECTED FINANCIAL DATA
Selected Financial Data for Denbury for each of the last five years are set forth under "Financial Highlights" appearing on page 2 of the Annual Report. All such information is incorporated herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Information as to Denbury's financial condition, changes in financial condition and results of operations and other matters is set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations," appearing on pages 27 through 43 of the Annual Report and is incorporated herein by reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A is set forth under "Market Risk Management" in "Management's Discussion and Analysis of Financial Condition and Results of Operations," appearing on pages 40 through 41 of the Annual Report and is incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Denbury's consolidated financial statements, accounting policy disclosures, notes to financial statements, business segment information, unaudited quarterly information and independent auditors' report are presented on pages 27 through 69 of the Annual Report. All such information is incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
DIRECTORS OF THE COMPANY
Information as to the names, ages, positions and offices with Denbury, terms of office, periods of service, business experience during the past five years and certain other directorships held by each director or person nominated to become a director of Denbury and related information will be set forth in the "Election of Directors" segment of the Proxy Statement ("Proxy Statement") for the Annual Meeting of Shareholders to be held May 20, 2003, ("Annual Meeting") and is incorporated herein by reference.
EXECUTIVE OFFICERS OF THE COMPANY
Information concerning the executive officers of Denbury will be set forth in the "Management" section of the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 and the rules thereunder require the Company's executive officers and directors, and persons who beneficially own more than ten percent (10%) of a registered class of the Company's equity securities, to file reports of ownership and changes in ownership with the Securities and Exchange Commission and exchanges and to furnish the Company with copies. Based solely on its review of the copies of such forms received by it, or written representations from such persons, the Company is not aware of any person who failed to file any reports required by
Section 16(a) to be filed for fiscal 2002.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning remuneration received by Denbury's executive officers and directors will be presented under the caption "Statement of Executive Compensation" in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information as to Denbury's common stock that may be issued under our equity compensation plans and the number of shares of Denbury's common stock beneficially owned as of March 18, 2003, by each of its directors and nominees for director, its five most highly compensated executive officers and its directors and executive officers as a group will be presented under the captions "Equity Compensation Plan Information" and "Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information on related transactions will be presented under the caption "Compensation Committee Interlocks and Insider Participation" and "Interests of Insiders in Material Transactions" in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
ITEM 14. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our chief executive officer and chief financial officer have evaluated our disclosure controls and procedures within 90 days prior to the filing of this Annual Report on Form 10-K and have determined that such disclosure controls and procedures are effective.
Subsequent to their evaluation, there were no significant changes in internal controls that could significantly affect such controls subsequent to the date of their evaluation.
-12-
 
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) FINANCIAL STATEMENTS AND SCHEDULES. Financial statements and schedules filed as a part of this report are presented on pages 27 through 69 of the Annual Report and are incorporated herein by reference.
EXHIBITS. The following exhibits are filed as a part of this report.

EXHIBIT NO.         EXHIBIT

    3(a)            Certificate of Incorporation of Denbury Resources Inc. filed
                    with the  Delaware  Secretary  of State  on April  20,  1999
                    (incorporated   by   reference   as  Exhibit   3(a)  of  the
                    Registrant's  Form  10-Q for the  quarter  ended  March  31,
                    1999).

    3(b)            Bylaws of Denbury  Resources  Inc., a Delaware  corporation,
                    adopted April 20, 1999 (incorporated by reference as Exhibit
                    3(b) of the  Registrant's  Form 10-Q for the  quarter  ended
                    March 31, 1999).

    4(a)            Form of Indenture between Denbury  Management Inc. and Chase
                    Bank   of   Texas,   National   Association,    as   trustee
                    (incorporated  by reference as Exhibit 4(b) of  Registrant's
                    Registration Statement on Form S-3 dated February 19, 1998).

    4(b)            First  Supplemental  Indenture  dated as of April 21,  1999,
                    between Denbury Resources Inc., a Delaware corporation,  and
                    Chase  Bank of  Texas,  National  Association,  as  Trustee,
                    relating   to   Denbury   Management,   Inc.'s   9%   Senior
                    Subordinated  Notes due 2008  (incorporated  by reference to
                    Exhibit 4(a) of the  Registrant's  Form 10-Q for the quarter
                    ended March 31, 1999).

    4(c)            Indenture  dated  as  of  August  15,  2001,  among  Denbury
                    Resources Inc.,  certain of its subsidiaries,  and the Chase
                    Manhattan Bank (incorporated by reference as Exhibit 4(c) of
                    the  Registrant's  Registration  Statement on Form S-4 dated
                    October 23, 2001).

    4(d)            Registration   Rights   Agreement   dated   August  8,  2001
                    (incorporated   by   reference   as  Exhibit   4(d)  of  the
                    Registrant's   Registration  Statement  on  Form  S-4  dated
                    October 23, 2001).

   10(a)            Third Amended and Restated Credit Agreement, dated September
                    12, 2002 between the Company and Bank One, as Administrative
                    Agent, and the financial institutions listed on Schedule 2.1
                    therein  (incorporated  by  reference  to  Exhibit 10 of the
                    Registrant's  Form 10-Q for the quarter ended  September 30,
                    2002).

   10(b)**          Denbury  Resources Inc. Stock Option Plan  (incorporated  by
                    reference as Exhibit 4(f) of the  Registrant's  Registration
                    Statement on Form S-8, No. 333-1006, dated February 2, 1996,
                    and as amended by the Registrant's  Registration  Statements
                    on Forms S-8, Nos. 333-27995, dated May 29, 1997, 333-55999,
                    dated  June  4,  1998,  333-70485,   dated  July  12,  1999,
                    333-63198,  dated June 15, 2001, and  333-90398,  dated June
                    13, 2002).

   10(c)**          Denbury Resources Inc. Stock Purchase Plan  (incorporated by
                    reference as Exhibit 4(g) of the  Registrant's  Registration
                    Statement on Form S-8, No. 333-1006, dated February 2, 1996,
                    and as amended by the Registrant's  Registration  Statements
                    on Forms S-8, No.  333-70485,  dated  January 12, 1999,  No.
                    333-39218, dated June 13, 2000 and No. 333-90398, dated June
                    13, 2002).

   10(d)            Form of indemnification  agreement between Denbury Resources
                    Inc.  and  its  officers  and  directors   (incorporated  by
                    reference  as Exhibit 10 of the  Registrant's  Form 10-Q for
                    the quarter ended June 30, 1999).

   10(e)**          Denbury   Resources   Inc.   Directors   Compensation   Plan
                    (incorporated  by reference as Exhibit 4 of the Registrant's
                    Registration  Statement  on Form S-8, No.  333-39172,  dated
                    June 13, 2000 and amended March 2, 2001).

                                      -13-	

EXHIBIT NO.         EXHIBIT

   10(f)**          Denbury Resources Severance  Protection Plan, dated December
                    6, 2000  (incorporated  by reference as Exhibit 10(f) of the
                    Registrant's  Form  10-K for the  year  ended  December  31,
                    2000).

   10(g)            Stock Purchase Agreement between TPG Partners II, L.L.C. and
                    the Company dated as of December 16, 1998  (incorporated  by
                    reference as Exhibit 99.1 of the Registrant's Form 8-K dated
                    December 17, 1998).

   10(h)            Agreement  and Plan of  Merger  and  Reorganization,  by and
                    among Denbury Resources Inc.,  Denbury  Offshore,  Inc., and
                    Matrix Oil & Gas, Inc., and its shareholders,  as of June 4,
                    2001   (incorporated  by  reference  as  Exhibit  2  of  the
                    Registrant's  Current  Report  on Form 8-K,  dated  June 15,
                    2001).

   13*              Annual Report to Shareholders.

   21*              List of Subsidiaries of Denbury Resources Inc.

   23.1*            Consent of Deloitte & Touche LLP.

   23.2*            Consent of DeGolyer and MacNaughton.

   99.1*            Certification of Chief Executive Officer and Chief Financial
                    Officer pursuant to section 906 of the Sarbanes-Oxley Act of
                    2002.

   99.2*            The  summary  of  DeGolyer  and  MacNaughton's  Report as of
                    December 31, 2002,  on oil and gas reserves (SEC Case) dated
                    March 19, 2003.	

* Filed herewith. ** Compensation arrangements.
(b) REPORTS ON FORM 8-K.
On November 15, 2002, we filed a consent issued by DeGolyer and MacNaughton that consents to references to its firm and to its report effective December 31, 2001 in Denbury's Registration Statement on Form S-3 declared effective by the Securities and Exchange Commission on March 21, 2001, and in the Prospectus Supplement thereto.
On November 22, 2002, we announced that Denbury and the Texas Pacific Group ("TPG") entered into an underwriting agreement, pursuant to which TPG would sell up to 7.5 million shares of Denbury's common stock. Denbury did not receive any proceeds from this transaction.
-14-
 
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Denbury Resources Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DENBURY RESOURCES INC.

March 20, 2003                         /s/ Phil Rykhoek
                          ------------------------------------------------
                                           Phil Rykhoek
                          Sr. Vice President and Chief Financial Officer

March 20, 2003                        /s/ Mark C. Allen
                          ------------------------------------------------
                                          Mark C. Allen
                          Vice President and Chief Accounting Officer	

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Denbury Resources Inc. and in the capacities and on the dates indicated.

March 20, 2003                         /s/ Ronald G. Greene
                          ------------------------------------------------
                                           Ronald G. Greene
                                Chairman of the Board and Director

March 20, 2003                         /s/ Gareth Roberts
                          ------------------------------------------------
                                           Gareth Roberts
                          Director, President and Chief Executive Officer
                                    (Principal Executive Officer)

March 20, 2003                         /s/ Phil Rykhoek
                          ------------------------------------------------
                                           Phil Rykhoek
                          Sr. Vice President and Chief Financial Officer
                                    (Principal Financial Officer)

March 20, 2003                         /s/ Mark C. Allen
                          ------------------------------------------------
                                           Mark C. Allen
                            Vice President and Chief Accounting Officer
                                    (Principal Accounting Officer)

March 20, 2003                         /s/ David I. Heather
                          ------------------------------------------------
                                           David I. Heather
                                               Director

March 20, 2003                         /s/ Wieland F. Wettstein
                          ------------------------------------------------
                                           Wieland F. Wettstein
                                               Director

March 20, 2003                         /s/ David B. Miller
                          ------------------------------------------------
                                           David B. Miller
                                               Director	

-15-
 
CERTIFICATIONS
I, Gareth Roberts, certify that:
1. I have reviewed this annual report on Form 10-K of Denbury Resources Inc. (the "registrant");
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

March 20, 2003                         /s/ Gareth Roberts
                          ------------------------------------------------
                                           Gareth Roberts
                              President and Chief Executive Officer	

-16-
I, Phil Rykhoek, certify that:
1. I have reviewed this annual report on Form 10-K of Denbury Resources Inc. (the "registrant");
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

March 20, 2003                         /s/ Phil Rykhoek
                          ------------------------------------------------
                                           Phil Rykhoek
                          Sr. Vice President and Chief Financial Officer	

-17-
 
EXHIBIT 13
PAGE 2, PAGES 8 THROUGH 11 INCLUSIVE, PAGE 14, PAGES 16 THROUGH 17 INCLUSIVE, PAGES 19 THROUGH 20 INCLUSIVE, PAGES 22 THROUGH 25 INCLUSIVE AND PAGES 27 THROUGH 70, INCLUSIVE, OF THE COMPANY'S ANNUAL REPORT TO SHAREHOLDERS FOR THE YEAR ENDED DECEMBER 31, 2002, BUT EXCLUDING PHOTOGRAPHS AND ILLUSTRATIONS SET FORTH ON THESE PAGES, NONE OF WHICH SUPPLEMENTS THE TEXT AND WHICH ARE NOT OTHERWISE REQUIRED TO BE DISCLOSED IN THIS ANNUAL REPORT ON FORM 10-K.
EX 13-1
 
Financial Highlights

                                                                           YEAR ENDED DECEMBER 31,
                                                   ---------------------------------------------------------- ----------
                                                                                                               AVERAGE
                                                                                                                ANNUAL
AMOUNTS IN THOUSANDS OF U.S. DOLLARS UNLESS NOTED       2002        2001(1)      2000       1999        1998   GROWTH(2)
-------------------------------------------------------------------------------------------------------------  ---------

PRODUCTION (DAILY)
     Oil (Bbls)                                        18,833       16,978      15,219     12,090      13,603         8%
     Natural Gas (Mcf)                                100,443       85,238      37,078     27,948      36,605        29%
     BOE (6:1)                                         35,573       31,185      21,399     16,748      19,704        16%
REVENUES                                              285,152      285,111     181,651     82,990      83,506        36%
UNIT SALES PRICE (excluding hedges)
     Oil (per Bbl)                                      22.36        21.34       25.89      15.03       10.29        21%
     Natural Gas (per Mcf)                               3.31         4.12        4.45       2.42        2.31         9%
UNIT SALES PRICE (including hedges)
     Oil (per Bbl)                                      22.27        21.65       23.50      13.08       10.29        21%
     Natural Gas (per Mcf)                               3.35         4.66        3.57       2.34        2.32        10%
CASH FLOW FROM OPERATIONS                             159,600      185,047      95,972     41,200      20,285        67%
NET INCOME (LOSS) (3)                                  46,795       56,550     142,227      4,614    (287,145)       --
AVERAGE COMMON SHARES OUTSTANDING
     Basic                                             53,243       49,325      45,823     39,928      25,926        20%
     Diluted                                           54,365       50,361      46,352     39,987      25,926        20%
NET INCOME (LOSS) PER SHARE
     Basic                                               0.88         1.15        3.10       0.12      (11.08)       --
     Diluted                                             0.86         1.12        3.07       0.12      (11.08)       --
OIL AND GAS CAPITAL INVESTMENTS                       155,637      327,175     134,021     54,967     102,652        11%
CO2 CAPITAL INVESTMENTS                                16,445       45,555           -          -           -        --
TOTAL ASSETS                                          895,292      789,988     457,379    252,566     212,859        43%
LONG-TERM LIABILITIES                                 432,616      360,882     202,428    154,976     226,436        18%
STOCKHOLDERS' EQUITY (DEFICIT) (4)                    366,797      349,168     216,165     72,428     (32,265)       --
PROVED RESERVES
     Oil (MBbls)                                       97,203       76,490      70,667     51,832      28,250        36%
     Natural Gas (MMcf)                               200,947      198,277     100,550     50,438      48,803        42%
     MBOE (6:1)                                       130,694      109,536      87,425     60,238      36,383        38%
     Discounted future cash flow - 10%              1,426,220      574,328   1,158,969    462,870     115,019        88%
PER BOE DATA (6:1)
     Oil and natural gas revenues                       21.17        22.88       26.13      14.88       11.36        17%
     Gain (loss) on settlements of derivative contracts  0.07         1.64       (3.23)     (1.54)       0.02        37%
     Lease operating expenses                           (5.48)       (4.84)      (4.94)     (4.25)      (3.49)       12%
     Production taxes and marketing expenses            (0.92)       (0.96)      (1.02)     (0.60)      (0.56)       13%
------------------------------------------------------------------------------------------------------------------------
       Production netback                               14.84        18.72       16.94       8.49        7.33        19%
     CO2 operating margin                                0.48         0.38        -          -           -           --
     General and administrative expense                 (0.96)       (0.89)      (1.09)     (1.21)      (1.02)       -2%
     Net cash interest expense                          (1.73)       (1.74)      (1.54)     (2.22)      (2.13)       -5%
     Current income taxes and other                      0.04        (0.06)      (0.07)      0.11        -           --
     Changes in assets and liabilities                  (0.38)       (0.15)      (1.99)      1.57       (1.36)       --
------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS                               12.29        16.26       12.25       6.74        2.82        44%
------------------------------------------------------------------------------------------------------------------------	

(1) We acquired Matrix Oil and Gas, Inc. in July 2001. See Note 2 to the Consolidated Financial Statements.
(2) Four-year compounded annual growth rate computed using 1998 as a base year.
(3) In 2000, we recorded a deferred income tax benefit of $67.9 million related to the reversal of the valuation allowance on our net deferred tax assets. In 1998, we recorded a $280.0 million writedown of our oil and natural gas properties under the full cost ceiling test.
(4) We have never paid any dividends on our common stock.
Reporting Format
Unless otherwise noted, the disclosures in this report have (i) production volumes expressed on a net revenue interest basis, and (ii) gas volumes converted to equivalent barrels at 6:1.
-2-
SELECTED OPERATING DATA
OIL AND GAS RESERVES
Estimates of our net proved oil and natural gas reserves as of December 31, 2002, 2001 and 2000 have been prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. The reserves were prepared using constant prices and costs in accordance with the guidelines of the Securities and Exchange Commission ("SEC"), based on the prices received on a field-by-field basis as of December 31 of each year. The reserves do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
Our proved non-producing reserves relate primarily to additional potential from producing zones that are currently behind pipe or are associated with waterfloods and tertiary recovery (CO2) floods. Since a majority of our properties are in areas with multiple pay zones or are fields with secondary or tertiary recovery operations, most of our properties have both proved producing and proved non-producing reserves.
Reserves associated with our CO2 operations in West Mississippi and our Heidelberg waterfloods in East Mississippi account for approximately 84% of our proved undeveloped oil reserves. We consider these reserves to be lower risk than proved undeveloped reserves that require drilling at locations offsetting existing production because the reservoir has already been defined by wells that produced during primary production. All of our reserves associated with secondary recovery and tertiary recovery operations are in fields and reservoirs that produced substantial volumes of oil under primary production. The main reason they are classified as undeveloped is because they require significant additional capital to drill wells or install facilities in order to produce the reserves, or they are required to demonstrate a production response after the water or CO2 is injected before their classification from proved undeveloped can be changed. The remaining 16% of our undeveloped oil reserves are located well within the currently producing regions of our fields, many of which are up-dip to existing production.
Our proved undeveloped natural gas reserves are not as concentrated as our oil reserves. Approximately 62% of our proved undeveloped natural gas reserves are on offshore properties located in six fields, from our latest discovery at North Padre A-9, offshore Texas, to West Delta 27 located offshore eastern Louisiana. These natural gas reserves are confirmed by both sub- surface geology and 3D seismic that covers these areas. An additional 15% of our proved undeveloped natural gas reserves are located in Heidelberg Field where we continue to have success in-fill drilling the Selma Chalk formation. The remaining significant undeveloped natural gas reserves are in our Thornwell/Lakeside and Newark, East (Barnett Shale) areas. In Thornwell/Lakeside our undeveloped reserves are primarily associated
-8-
with the Bol Perc reservoir where we drilled and completed one additional well during 2002, bringing our total number of successful Bol Perc wells to seven without a dry hole. The Newark, East (Barnett Shale) field is a new and growing area for us. We have now drilled nine wells that have confirmed the presence of commercial gas reserves in this part of the field. We plan to drill an additional six wells during 2003 and assuming gas prices remain strong, we are planning larger development programs in this area in future years. We plan to develop most of our proved undeveloped natural gas reserves during 2003.

                                                                              December 31,
                                                               -------------------------------------------
                                                                    2002           2001           2000
                                                               ------------    ------------   ------------
ESTIMATED PROVED RESERVES:
    Oil (MBbls)................................................      97,203          76,490         70,667
    Natural gas (MMcf).........................................     200,947         198,277        100,550
    Oil equivalent (MBOE)......................................     130,694         109,536         87,425
PERCENTAGE OF TOTAL MBOE:
    Proved producing...........................................          43%             53%            57%
    Proved non-producing.......................................          23%             23%            18%
    Proved undeveloped.........................................          34%             24%            25%
REPRESENTATIVE OIL AND NATURAL GAS PRICES: (1)
    Oil - NYMEX................................................$      31.20    $      19.84    $     26.80
    Natural gas - NYMEX Henry Hub..............................        4.79            2.57           9.78
PRESENT VALUES:(2)
    Discounted estimated future net cash flow before
        income taxes ("PV10 Value") (thousands)................$  1,426,220    $    574,328    $ 1,158,969
    Standardized measure of discounted estimated future net
        cash flow after income taxes (thousands)...............$  1,028,976    $    505,795    $   841,299	

(1) The oil prices as of each respective year-end were based on NYMEX prices per Bbl and NYMEX Henry Hub ("NYMEX") prices per MMBtu, with these representative prices adjusted by field to arrive at the appropriate corporate net price.
(2) Determined based on year-end unescalated prices and costs in accordance with the guidelines of the SEC, discounted at 10% per annum.

-9-
FIELD SUMMARIES
Denbury operates in four primary core areas, Louisiana, offshore Gulf of Mexico, Eastern Mississippi and Western Mississippi. Our 15 largest fields constitute approximately 80% of our total proved reserves on a BOE basis and 76% on a PV10 Value basis. Within these 15 fields we own an average 88% working interest and operate all of the fields. The concentration of value in a relatively small number of fields allows us to benefit substantially from any operating cost reductions or production enhancements we achieve and allows us to effectively manage the properties from our three primary field offices in Houma and Covington, Louisiana, and Laurel, Mississippi.

                                                                                                         2002
                                            PROVED RESERVES AS OF DECEMBER 31, 2002 (1)          AVERAGE DAILY PRODUCTION
                                    ------------------------------------------------------------- ------------------------
                                                                                                              NATURAL   AVERAGE NET
                                         OIL    NATURAL GAS    MBOE'S        BOE      PV10 VALUE    OIL         GAS       REVENUE
                                       (MBBLS)     (MMcf)      (000's)    % OF TOTAL   ($ 000's)  (Bbls/d)    (Mcf/d)   INTEREST(2)
------------------------------------------------------------------------------------------------------------------------------------

MISSISSIPPI - CO2 FLOODS
   Mallalieu........................    10,639          -     10,639           8.1%     108,518       568            -         80.9%
   Little Creek.....................     7,541          -      7,541           5.8%     120,883     3,393            -         82.5%
   McComb...........................     8,293          -      8,293           6.3%      53,633         1            -         82.5%
   Other Mississippi CO2 floods.....     1,397          -      1,397           1.1%      18,159         8            -         82.2%
                                    ----------  ---------  ---------    ----------  -----------  --------    ---------    ----------
      Total Mississippi - CO2 floods    27,870          -     27,870          21.3%     301,193     3,970            -         81.9%
                                    ---------- ----------  ---------    ----------  -----------  --------    ---------    ----------

OFFSHORE GULF OF MEXICO
   W.Delta 27.......................       929     12,278      2,975           2.3%      49,307       350        9,132         58.9%
   South Marsh Island 48............       172     22,609      3,940           3.0%      67,307        65        7,379         83.3%
   Brazos A-22......................        88     11,174      1,950           1.5%      21,081        11        1,695         35.7%
   N. Padre A-9.....................        11     10,965      1,838           1.4%      26,067         -            -         41.5%
   Other offshore...................        84     34,099      5,768           4.4%     107,728       177       38,027         28.0%
                                    ---------- ----------  ---------    ----------  -----------  --------    ---------    ----------
      Total offshore................     1,284     91,125     16,471          12.6%     271,490       603       56,233         40.9%
                                    ---------- ----------  ---------    ----------  -----------  --------    ---------    ----------

OTHER MISSISSIPPI - NON-CO2
   Heidelberg......................     37,363     38,518     43,783          33.5%     327,308     6,294        7,114         78.7%
   Eucutta.........................      4,978          -      4,978           3.8%      46,339     1,441           31         67.8%
   King Bee........................      3,536          -      3,536           2.7%      26,894       694            -         78.7%
   Brookhaven (3) .................      2,086          -      2,086           1.6%      28,475       172            -         78.7%
   Laurel (3)......................      7,380          -      7,380           5.6%      69,450       552            -         73.9%
   Other Mississippi...............     10,250      2,656     10,693           8.2%     104,865     2,828        1,237         62.2%
                                    ---------- ----------  ---------    ----------  -----------  --------    ---------    ----------
      Total Other Mississippi......     65,593     41,174     72,456          55.4%     603,331    11,981        8,382         74.5%
                                    ---------- ----------  ---------    ----------  -----------  --------    ---------    ----------
LOUISIANA
   Lirette.........................        349     13,403      2,583           2.0%      58,572       351        7,581         56.2%
   Thornwell.......................        595      9,865      2,239           1.7%      51,231     1,074       17,017         52.6%
   S.Chauvin.......................        369     10,397      2,102           1.6%      34,482       177        2,832         40.4%
   Other Louisiana.................      1,141     25,611      5,409           4.1%      93,545       599        7,664         27.8%
                                    ---------- ----------  ---------    ----------  -----------  --------    ---------    ----------
      Total Louisiana..............      2,454     59,276     12,333           9.4%     237,830     2,201       35,094         36.7%
                                    ---------- ----------  ---------    ----------  -----------  --------    ---------    ----------
OTHER..............................          2      9,372      1,564           1.3%      12,376        78          734         68.9%
                                    ---------- ----------  ---------    ----------  -----------  --------    ---------    ----------

COMPANY TOTAL......................     97,203    200,947    130,694         100.0%   1,426,220    18,833      100,443         63.0%
                                    ========== ==========  =========    ==========  ===========  ========    =========    ==========	

(1) The reserves were prepared using constant prices and costs in accordance with the guidelines of the SEC based on the prices received on a field-by-field basis as of December 31, 2002. The prices at that date were a NYMEX oil price of $31.20 per Bbl adjusted by field and a NYMEX natural gas price of $4.79 per MMBtu, also adjusted by field.
(2) Includes only productive wells in which the Company has a working interest as of December 31, 2002.
(3) These fields were acquired during 2002. The average production during the period they were owned by the Company was 515 Bbls/d at Brookhaven and 1,651 Bbls/d at Laurel. Laurel Field was sold in February 2003.
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OIL AND GAS ACREAGE
The following table sets forth Denbury's acreage position at December 31, 2002:

                                           DEVELOPED                            UNDEVELOPED
                              ----------------------------------     ---------------------------------
                                   GROSS               NET                GROSS               NET
                              --------------     ---------------     ---------------     -------------
Louisiana....................         24,539              15,611              31,062            19,852
Mississippi..................         84,740              75,497              77,864            53,253
Offshore Gulf Coast..........        116,541              63,090              52,820            52,820
Texas........................          3,919               3,563              19,828            16,859
                              --------------     ---------------     ---------------     -------------
            Total............        229,739             157,761             181,574           142,784
                              ==============     ===============     ===============     =============	

PRODUCTIVE WELLS
This table sets forth our gross and net productive oil and natural gas wells at December 31, 2002:

                                                                  PRODUCING NATURAL
                                PRODUCING OIL WELLS                  GAS  WELLS                        TOTAL
                            ---------------------------     ---------------------------     ----------------------------
                               GROSS             NET           GROSS            NET            GROSS             NET
                            -----------      ----------     -----------     -----------     -----------      -----------
Louisiana..................      30              12.1            55             22.4            85               34.5
Mississippi................     460             350.3            76             49.9           536              400.2
Offshore Gulf Coast........       3               1.7            76             31.0            85               35.0
Texas......................       -                 -            10              7.1            10                7.1
                            -----------      ----------     -----------     -----------     -----------      -----------
       Total...............     493             364.1           217            110.4           716              476.8
                            ===========      ==========     ===========     ===========     ===========      ===========	

DRILLING ACTIVITY
The following table sets forth the results of our drilling activities over the last three years:

                                                                 YEAR ENDED DECEMBER 31,
                                              --------------------------------------------------------------
                                                     2002                  2001                 2000
                                              -------------------   ------------------   -------------------
                                               GROSS       NET       GROSS      NET       GROSS       NET
                                              --------   --------   --------  --------   --------   --------

EXPLORATORY WELLS: (1)
     Productive (2)........................      7          3.7        15        8.2        3          1.1
     Nonproductive (3).....................      4          2.5         3        1.2        1          0.2
DEVELOPMENT WELLS: (1)
     Productive (2)........................     33         22.7        60       37.9       38         26.5
     Nonproductive (3)(4)..................      2          1.4         -          -        2          0.2
                                              --------   --------   --------  --------   --------   --------
           Total...........................     46         30.3        78       47.3       44         28.0
                                              ========   ========   ========  ========   ========   ========	

(1) An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A development well is a well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.
(2) A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
(3) A nonproductive well is an exploratory or development well that is not a producing well.
(4) During 2002, 2001 and 2000, an additional 9, 24 and 12 wells, respectively, were drilled for water or CO2 injection purposes.
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OPERATIONS REPORT
WEST MISSISSIPPI AND OUR CO2 ASSETS
Carbon dioxide ("CO2") injection is one of the most efficient tertiary recovery mechanisms for producing crude oil; however, its application requires large quantities of CO2, and therefore its use has been restricted to West Texas, Mississippi and other isolated areas where large quantities of CO2 are available. The CO2 acts as a type of solvent for the oil, removing it from the formation and allowing the oil to be recovered along with the CO2 as it is produced. For example, in a typical oil field, between 40% and 50% of the oil in place can be extracted by primary and secondary (waterflooding) recovery. An additional amount of oil (17% at Little Creek) can be recovered by injecting CO2 into certain wells and then recovering the additional oil and the CO2 from other wells.
One of the few natural sources of CO2 in the United States was discovered around Jackson Dome in Mississippi, a volcanic intrusive, which was emplaced about 80 million years ago. These CO2 reserves are found in structural traps in the Buckner, Smackover and Norphlet formations at depths of about 16,000 feet. Some estimates have suggested that there are 12 Tcf of usable CO2 in this area.
In September 1999 we acquired our first CO2 tertiary recovery project at Little Creek Field in Mississippi, which was originally developed by Shell Oil Company. Since our acquisition of this field, we have increased oil production here from 1,350 Bbls/d to an average of 3,033 Bbls/d during the fourth quarter of 2002. Following our success at Little Creek, we embarked upon a strategic program to build a dominant position in this niche play. We recognized that several other older fields in the area would also be excellent CO2 flood candidates because they produced from the same Lower Tuscaloosa formation, shared very similar reservoir characteristics and were in close proximity to each other. Following are highlights of our activities over the last two years:
o In February 2001, we acquired approximately 800 Bcf of proved producing CO2 reserves for $42.0 million, a purchase that gave us control of almost all 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 because it assured us that CO2 would be available to us at a reasonable and predictable cost. Since February 2001, we have acquired an additional CO2 property and drilled two additional CO2 wells, increasing our estimated proved CO2 reserves to approximately 1.6 Tcf as of December 31, 2002. These additional wells are each capable of producing between 20 and 30 MMcf of CO2 per day. Although the proven and potential reserves are quite large, in order to continue our tertiary development of the old oil fields in the area, incremental production of CO2 is needed. In order to obtain the additional CO2 production we plan to drill several additional wells, including one or two more wells during 2003.
o During the fourth quarter of 2002, we sold an average of 63.1 MMcf/d of CO2 to commercial users and we used an average of 57.4 MMcf/d for our tertiary activities. With the completion of our latest well, currently scheduled for late March 2003, we expect to increase our daily CO2 production to over 165
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MMcf/d and by year-end 2003 we hope to further increase our CO2 production to approximately 200 MMcf/d. We expect to continue our CO2 drilling in 2004 and beyond, with plans to increase the CO2 production to over 300 MMcf/d within the next couple of years. We expect the majority of the incremental production to be used in our tertiary recovery operations, while we expect CO2 sales to industrial customers to continue to provide us with net cash flow of around $6 to $7 million per year for the next several years. As of December 31, 2002, the present value of these industrial contracts discounted at 10% per year was approximately $57 million based on the current life of each contract. We believe the majority of these contracts will be extended beyond their current terms, which would result in the present value of the industrial sales being higher.
o During 2001 and 2002, we acquired several oil fields in our CO2 operating area, including the West Mallalieu and McComb Fields. Typical of mature fields in this area, the acquisition cost of both of these fields was relatively low in comparison to the significant reserve potential as a tertiary recovery project. As an example, we acquired West Mallalieu in May 2001 for $4.0 million, and by year-end 2001 had recognized 10.4 MMBOE of proved reserves, with additional future reserve potential in this field. We acquired McComb Field in 2002 for $2.3 million, and by year-end 2002 had recognized 8.3 MMBOE of proved reserves with additional future reserve potential here also. We expect the development cost at these fields to average around $4.00 per BOE.
o In August 2002, we acquired COHO Energy Inc.'s Gulf Coast properties for $48.2 million, which as of year-end 2002 contained an estimated 15.0 million barrels of oil (excluding any potential reserves from tertiary recovery). Brookhaven Field, another significant tertiary flood candidate along our CO2 pipeline, was included in the properties acquired from COHO. By exploiting our scale, regional competitive advantage and strategic ownership of the general partner interest in Genesis Energy, we were able to increase the average realized price for post-acquisition production from these properties by approximately $3.40 per barrel (relative to NYMEX prices) over the prices that COHO realized earlier in 2002. This translates into a 50% increase in the PV-10 Value of the acquisition, using constant prices and the future price strip as of the time of acquisition. We do not expect to begin development of Brookhaven Field until at least 2004, but believe that this field contains one of the area's most significant opportunities for potential oil reserves using CO2 tertiary recovery. In February 2003, we sold one of the acquired COHO fields, Laurel Field, for $27.0 million and also received an interest in another field and seismic data valued by us at approximately $1.0 million. At December 31, 2002, Laurel Field had 7.4 MMBbls of proven reserves, just less than 50% of the total proved reserves of the COHO properties acquired in August 2002.
o In May 2002, we acquired the 2.0% general partner interest in Genesis Energy, L.P. Genesis is engaged in crude oil gathering, marketing and transportation with three primary pipeline systems in Texas, Alabama/Florida and Mississippi. Genesis' Mississippi pipeline runs near several of our tertiary recovery operations in southwest Mississippi and within 25 miles of our Heidelberg Field and several
-16-
of our other east Mississippi fields. This acquisition has enhanced our marketing position for our Mississippi oil production. Genesis could also function as a financier and operator of new pipelines and gathering systems that are required in order to develop these fields.
With anticipated all-in finding and development costs of approximately $4.00 per BOE and anticipated operating costs of $9.00 to $10.00 per BOE over the life of each field, these tertiary recovery operations in West Mississippi along our pipeline should prove to be highly profitable, even at $18 to $20 oil prices, as they produce light sweet oil that receives near NYMEX pricing. We believe there is also significant potential in the future to extend our pipeline to eastern Mississippi and/or southern Louisiana to exploit the use of CO2 in tertiary recovery operations in these areas.
The western part of Mississippi has produced over 245 MMBbls of light sweet crude oil from Tuscaloosa sandstones at a depth of about 10,000 feet. The application of a theoretical recovery factor of 17% of original oil in place suggests that about 80-100 MMBbls of additional gross reserves may be available in fields in this part of the state. To date, we have booked approximately 38.2 MMBOE (gross) of this potential as proven reserves, of which 4.1 MMBbls (gross) has been produced to date. Obviously, a great deal of work is required before these additional reserves can be recorded as proved reserves, such as additional landwork, reworking/reentering wells and installing production facilities. We plan to spend around $43.0 million in this area during 2003, the largest single portion of our $130 million 2003 exploration and development budget.
LITTLE CREEK, MALLALIEU AND MCCOMB FIELDS
Little Creek Field was discovered in 1958, and by 1962 the field had been unitized and waterflooding had commenced. The pilot phase of CO2 flooding began in 1974 and the first two phases (each in a distinct area of the field) began in 1985. When we acquired the field in 1999, these first two phases were substantially complete and Phase III was in process. We have completed Phase III and Phase IV and have initiated Phase V utilizing CO2 injection. Our plans in 2003 are to continue the development of these phases. Currently there are 39 producing wells and 26 injection wells at Little Creek. Based on the results of the two earliest phases of CO2 flooding at Little Creek, tertiary recovery has increased the ultimate recovery factor in that portion of the field by approximately 17%, as compared to approximately 20% for primary recovery and 18% for secondary recovery. The field has produced a cumulative 61.9 gross MMBbls of light sweet crude and we currently estimate that an additional 9.1 gross MMBbls can be recovered.
Production from Little Creek Field was approximately 1,350 Bbls/d when we acquired it in 1999. During the fourth quarter of 2002, production had increased to an average of 3,033 BOE/d. With our recent increases in CO2 production, we expect the production from Little Creek to increase further during 2003 by another 750 to 1,250 BOE/d.
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In addition to our expansion activities at Little Creek, we purchased West Mallalieu Field in May 2001. West Mallalieu Field was originally unitized by Shell Oil Company, and a subsequent pilot project was commenced in 1986. The pilot project, consisting of four 5-spot patterns, has cumulatively produced approximately 2.3 MMBbls of oil as a result of CO2 flooding. We expanded the pilot project by adding an additional four patterns during 2001 and an additional four patterns in 2002. During 2002 we began to see initial response to CO2 injection as the unit averaged 778 Bbls/d during the fourth quarter of 2002. In contrast to Little Creek Field, West Mallalieu Field was not waterflooded prior to CO2 injection. Therefore, the tertiary recovery of oil from West Mallalieu Field Unit as a result of CO2 injection could exceed the 17% of original oil in place that we expect from Little Creek Field.
McComb Field, purchased in 2002, has not had any pilot programs or tertiary operations to date and has virtually no current oil production, but is close in proximity and analogous to our fields at Little Creek and Mallalieu. We plan to commence tertiary recovery operations in 2003 and expect to see initial oil production responses in early 2004. As of December 31, 2002, we had recognized
8.3 MMBOE of proven reserves at McComb Field. The total potential from McComb Field is estimated to be as much as twice the booked proven reserves and thus we expect the reserves at McComb to increase over the next several years as we develop the field in its entirety.
At December 31, 2002, we had proved reserves of 27.9 MMBOE relating to our tertiary recovery operations. Through December 31, 2002, we had spent a total of $74.4 million on fields in this area, primarily Little Creek and Mallalieu Fields, and have received $50.1 million in net operating income, leaving us a balance of $24.3 million to recover for payout. This compares to a PV-10 Value, using December 31, 2002 SEC pricing of $31.20 per Bbl, of $301.2 million for the proved reserves in these fields.
OFFSHORE GULF OF MEXICO
Denbury's second largest focus area for 2003 is the federal offshore waters of the Gulf of Mexico. Employing the latest 3D seismic techniques and interpretations has allowed us to better understand the complexities of these offshore areas. Denbury owns an interest in 85 wells and operates 68 of these wells (80%) from its regional office in Covington, Louisiana. Based on our initial successful results in the Gulf of Mexico, in July 2001 we purchased Matrix Oil & Gas, Inc. Matrix had followed our same strategy of acquiring offshore fields from the major oil and gas companies that had produced large quantities of oil and natural gas. We believe large fields that have produced hundreds of millions of barrels of oil and hundreds of billions of cubic feet of natural gas generally have an additional 10% to 15% of additional reserves which can be produced when detailed geology and engineering work is applied. The Matrix properties were producing approximately 40 MMcf/d at the time of the acquisition.
Due to the downturn in natural gas prices that occurred late in 2001, we budgeted little drilling activity offshore during 2002, with planned spending limited to workovers, recompletions and other maintenance
-19-
type projects. We drilled only two offshore wells late in the year, both successful exploration wells at North Padre Island A-9. Our total spending during 2002 was approximately $17.1 million in this region, approximately 15% of our total exploration and development budget. During 2002 there were two storms in the Gulf of Mexico, Tropical Storm Isidore and Hurricane Lili, which impacted our offshore production and caused significant damage to one of our offshore platforms. Most of this damage was covered by insurance, but we did expense approximately $750,000 during the fourth quarter of 2002 related to the insurance deductibles and certain items not covered by insurance. Even with the reduced spending and the losses in production caused by the two storms, our production offshore averaged 59.9 MMcfe/d during 2002, slightly higher than the 2001 average of approximately 55 MMcfe/d during the period they were owned by us. During 2003, our offshore spending will be significantly higher, primarily due to several prospects we developed during 2002 and intend to drill in 2003. We expect to spend an estimated $41.0 million on offshore activities, or 32% of our $130.0 million 2003 exploration and development budget.
We booked net proved reserves as of year-end 2002 of approximately 11 Bcf net to our interest in the two wells at North Padre Island A-9 drilled in late 2002. This discovery should be on production in the second half of 2003.
During 2003 we expect to drill eight to ten wells, with unrisked potential target objectives ranging from 5 Bcf to 55 Bcf, net to our interest. These plays are supported with 3D seismic that is enhanced by modern acquisition techniques, the latest processing techniques and seismic modeling. The application of these techniques allows our geoscientists to better image deeper reservoirs and recognize hydrocarbon indicators in and around these mature prolific fields. Our scheduled wells include both development and exploration prospects at Brazos A-21 and A-22, High Island A-6, West Cameron 192, East Cameron 33, West Cameron 427 and West Delta 27.
SOUTH LOUISIANA
Denbury operates on the land and in the marshes of South Louisiana, including state waters. We own interests in 85 wells and operate 63 of these wells (74%) from our regional office in Houma, Louisiana. This region produces primarily natural gas, averaging 34.4 MMcf/d net to our interest in the fourth quarter of 2002, approximately 38% of our total natural gas production. During 2002, we spent approximately $35.0 million in this region, approximately 32% of our total exploration and development budget, drilling approximately 10 wells, primarily in the Thornwell and Terrebonne Parish areas (Lirette, Bay Baptiste, Bayou Rambio and Lake Gero). For 2003, our spending will be reduced somewhat in this area to an estimated $21.0 million, or 16% of our $130.0 million exploration and development budget, as we focus more of our natural gas exploration and development efforts in the offshore Gulf of Mexico.
The majority of our onshore Louisiana fields lie in the Houma embayment area of Terrebonne Parish, including Lirette, Bayou Rambio and South Chauvin Fields, and a recent shallow natural gas play at
-20-
Lake Gero. The advent of 3D seismic data in these geologically complex areas has become a valuable tool in exploration and development. We currently own or have a license covering over 630 square miles of 3D data, and plan to expand our data ownership. During 2002, we expanded our seismic holdings in this area by acquiring an additional 290 square miles of 3D data. We drilled six wells in Terrebonne Parish during 2002, four of which were discoveries. In 2003, we plan to drill around 15 wells, eight of which are planned to further exploit the shallow gas play in the Lake Gero area, five of which we expect to drill in the Thornwell area, primarily targeting additional Bol Perc potential, and the rest of which we expect to be drilled at other fields in the Terrebonne Parish area using similar 3D interpretation techniques.
Our activities in the Lake Gero area of Terrebonne Parish provided strong results during 2002. We re-processed a portion of our Terrebonne seismic to better image the shallower sands in the area. The majority of newer data being shot is to image the deeper sands, thus the processing of the shallow sands has generally been overlooked. This reprocessing indicated there were multiple shallow seismic anomalies present in the area around Lake Gero. We drilled two successful wells at Lake Gero during the year. These reservoirs are shallow, approximately 3000 feet deep, but the two wells produced an average of 4,000 Mcf/d during the fourth quarter of 2002. We plan to drill an additional eight wells in the Lake Gero area during 2003. In addition to the Lake Gero area, through our seismic reprocessing, we have another 12 prospects in the Terrebonne Parish area we are currently reviewing.
We were very active in the Thornwell Field area, located in Cameron and Jeff Davis Parishes, during 2001 and 2002. This field, purchased in late 2000, produced an average of 23.5 MMcfe/d net to our interest during 2002. Our primary interest in purchasing this field was the substantial upside potential that we believe exists in the continued development of the existing producing zones (Bol Perc), and the exploration potential of several deeper zones (Marg Howei and Camerina). All of these prospects were defined by a 110 square mile 3D seismic survey. During 2002 we continued successful development of the Bol Perc sands, with the drilling of one Bol Perc well. During 2002, we also drilled the Lacassane #6-1 (Brenda prospect), which targeted the Camerina formation. We were unsuccessful in our largest target, the Lower Camerina sands, although this well did prove up additional Bol Perc prospects in another fault block and reserves in the shallower Camerina sands. The Lacassane #6-1 produced an average of 3.5 net MMcfe/d during the fourth quarter of 2002. In addition to drilling these two wells, during 2002 we expanded our acreage position over several Bol Perc anomalies, recompleted a well that averaged 2.8 MMcfe/d and purchased one additional well. During 2003, we plan to drill four additional Bol Perc wells and one Marg Howei well, although our total spending in this area, budgeted at approximately $7.0 million, will be less than the $18.8 million spent here in 2002.
HEIDELBERG AND EAST MISSISSIPPI
In the eastern part of the Mississippi salt basin, from our office in Laurel, Mississippi, we operate 418 wells (91%) out of 459 in which we own an interest. These fields produced an average of 14,165 Bbls/d and 9.2 MMcf/d during the fourth quarter of 2002. The largest
-22-
field in the region, and our largest field is Heidelberg Field, which for the fourth quarter of 2002 produced an average of 7,290 BOE/d. We have been active in this area since Denbury was founded in 1990 and are by far the largest producer in the basin as well as in the State of Mississippi. In general, we have owned our Eastern Mississippi properties longer than properties in most of our other regions and thus they are more fully developed and we are spending less in this region than in our other three regions. During 2002, we drilled 28 wells and performed various workovers, recompletions and other maintenance type projects, with total spending (excluding acquisitions) during 2002 of approximately $24.0 million in this region, approximately 21% of our total exploration and development budget. As a result of our reduced spending here during the year, our production in Eastern Mississippi averaged 13,379 BOE/d during 2002, just slightly less than the 2001 average of 13,481 BOE/d. For 2003, our spending will be about the same as in 2002, as we expect to spend an estimated $21.0 million, or 16% of our $130.0 million 2003 exploration and development budget in this region.
The fields in this region are characterized by structural traps that generate prolific production from stacked or multiple pay sands. As such, they provide opportunities to increase reserves through infield drilling, recompletions, improvements in production efficiency, and in some cases, by water flooding producing reservoirs. Most of our wells produce large amounts of saltwater and require large pumps, which increases the operating costs per barrel relative to our properties in Louisiana that are predominantly natural gas producers. We plan to continue our basic strategy in this region, supplemented by additional waterflooding (secondary recovery) and eventually CO2 flooding (tertiary recovery). Future tertiary recovery operations may offer the biggest upside potential in this area. Although the reserve potential here is significant, we are initially developing the fields along our CO2 pipeline (see "West Mississippi and our CO2 Assets" above), as the CO2 is easily delivered to these fields, which produce light sweet oil that commands a higher price (relative to NYMEX) than the production from the Eastern Mississippi properties. To extend our tertiary CO2 operations to Eastern Mississippi will require a pipeline and slightly higher oil prices for this production than production from our Western Mississippi properties. The higher oil price is needed to provide similar rates of return, due to the overall quality of the crude oil and a higher negative differential to NYMEX prices, and in order to cover the additional cost of building a pipeline. However, with the high oil prices prevailing in late 2002 and early 2003, tertiary operations appear to be profitable. We plan to further evaluate this potential during the next couple of years, as this could be part of our future expansion plans.
Our primary interests at Heidelberg Field, our single largest field, were acquired from Chevron in December 1997. This field was discovered in 1944 and has produced an estimated 196 MMBbls of oil and 39 Bcf of gas since its discovery. The field is a large salt-cored anticline that is divided into western and eastern segments due to subsequent faulting. There are 11 producing formations in Heidelberg Field containing 40 individual reservoirs, with the majority of the past and current production coming from the Eutaw, Selma Chalk and Christmas sands at depths of 3,500 to 5,000 feet. When we acquired the property, production was approximately 2,800 BOE/d. As a result of our subsequent development work, production for 2002 averaged 7,479 BOE/d.
-23-
The primary oil production at Heidelberg is from five waterflood units that produce from the Eutaw formation (approximately 4,400 feet). These units are generally developed although they will require additional work and capital for the next few years. In addition, Heidelberg is our single largest gas field. We began extensive development of the Selma Chalk natural gas reservoir at a depth of 3,700 feet in 2000 and 2001. Previous operators had only partially developed this formation in order to provide fuel gas for the rest of the field. We drilled 13 wells here in 2001 and 13 in 2002 that effectively reduced the well spacing to 40 acres in East Heidelberg, and increased the natural gas production at Heidelberg to an average for the year of around 7.1 MMcf/d and a fourth quarter average of 7.9 MMcf/d. We believe that there may be opportunities to further reduce the well spacing and we plan to drill an additional 11 Selma Chalk wells in 2003.
We have pursued the same strategy at our other significant fields in East Mississippi: Eucutta, Quitman, Davis, Sandersville and King Bee Fields. After we acquired each of these oil fields, we initiated a rework program to increase production and reserves. We shot the first 3D seismic survey ever shot over King Bee Field (Cypress Creek Dome) in 2001, a field we acquired from Fina in 1999. King Bee Field is a salt dome with relatively few wells drilled over the years because it underlies a national forest and a U.S. military bombing range. Due to these surface restrictions, wells have to be drilled from sites outside of the bombing area, and thus well costs are higher than normal. The higher costs of drilling and the steeply dipping beds of the producing formations make it imperative to have a very good geologic picture of the subsurface to minimize the risks prior to drilling. We drilled our first well at King Bee during 2002, which we plan to convert to an injection well during the second quarter to begin a pressure maintenance project in the largest reservoir currently in the field. Based on our simulation study, we believe this project will allow us to recover a significant amount of additional oil reserves (up to 1.0 MMBbls) that would not be recovered otherwise. During 2003, we also plan to drill our first well based on the 3D seismic data we shot over the field. This seismic data has revealed a very complex and highly faulted field that will require extremely detailed subsurface geology and geophysical efforts. We have identified an additional four to six prospect leads at this time.
BARNETT SHALE
Denbury also owns about 22,000 acres of leases in the Fort Worth Basin that is prospective for the Barnett Shale. Six wells were drilled in 2001 and two in 2002, all but one of which were producing as of year-end 2002. Due to low natural gas prices in late 2001, our 2002 development of this area was limited, as we spent only approximately $2.2 million there during 2002. Although we believe this area has a reserve potential in excess of 200 Bcf, it requires natural gas prices greater than $3.00 per Mcf in order to provide us with our minimum acceptable rate of return. As such, our other areas have provided better opportunities to date. We have entered into two joint ventures with business partners to drill up to 60 wells in this area. The addition of these wells, combined with the nine wells we have drilled, will prove up the majority of our acreage, leaving us the opportunity to further exploit this area in 2004 and beyond.
-24-

                                                GLOSSARY AND SELECTED ABBREVIATIONS

Bbl                         One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or
                            other liquid hydrocarbons.

Bbls/d                      Barrels of oil produced per day.

Bcf                         One billion cubic feet of natural gas or CO2.

BOE                         One barrel of oil equivalent using the ratio of one barrel of crude oil, condensate or natural gas
                            liquids to 6 Mcf of natural gas.

BOE/d                       BOEs produced per day.

Btu                         British thermal unit, which is the heat required to raise the temperature of a one-pound mass of
                            water from 58.5 to 59.5 degrees Fahrenheit.

CO2                         Carbon dioxide.

MBbl                        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.

MMBbl                       One million barrels of crude oil or other liquid hydrocarbons.

MMBOE                       One million BOEs.

MMBtu                       One million Btus.

MMcf                        One million cubic feet of natural gas or CO2.

MMcfe                       One thousand Mcfe.

MMcfe/d                     MMcfes produced per day.

PV10 Value                  When used with respect to oil and natural gas reserves, PV10 Value means the estimated future
                            gross revenue to be generated from the production of proved reserves, net of estimated production
                            and future development costs, using prices and costs in effect at the determination date, without
                            giving effect to non-property related expenses such as general and administrative expenses, debt
                            service and future income tax expense or the depreciation, depletion and amortization, discounted
                            to present value using an annual discount rate of 10% in accordance with the guidelines of the
                            Securities and Exchange Commission.

Proved Developed            Reserves that can be expected to be recovered through existing wells with existing equipment
Reserves                    and operating methods.

Proved Reserves             The estimated quantities of crude oil, natural gas and natural gas liquids which 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 that are expected to be recovered from new wells on undrilled acreage or from existing
Reserves                    wells where a relatively major expenditure is required.

Tcf                         One trillion cubic feet of natural gas or CO2.	

-25-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We are a growing independent oil and gas company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas producer in Mississippi, hold key operating acreage onshore Louisiana and have a growing presence in the offshore Gulf of Mexico areas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes. Our corporate headquarters are in Dallas, Texas, and we have three primary field offices located in Houma and Covington, Louisiana, and Laurel, Mississippi.
2002 ACQUISITIONS
Acquisition of COHO Gulf Coast Properties
In late August 2002, we acquired COHO Energy, Inc.'s Gulf Coast properties through a bankruptcy auction. Our net purchase price, adjusted for interim production and purchase adjustments to date, was $48.2 million and included nine fields, eight of which are located in Mississippi and one in Texas. We operate all but one of the smaller Mississippi fields. As of December 31, 2002, these properties had net proved reserves of approximately 15.1 million barrels of oil equivalent with net production of approximately 4,000 barrels of oil per day. The Mississippi fields include interests in the Brookhaven, Laurel, Martinville, Soso and Summerland Fields, with working interests in excess of 90%, plus interests in the smaller Bentonia, Cranfield and Glazier Fields. At the time of the acquisition, we hedged nearly 100% of the forecasted proved developed production relating to this acquisition through the end of 2004 with no-cost oil swaps (i.e., forward sales). The average fixed price of these swaps for 2003 is $24.27 per barrel and for 2004 is $22.94 per barrel.
Subsequent to the purchase, we elected to sell several of the acquired properties, primarily to reduce debt. The largest of these is Laurel Field, a field with approximately 7.4 MMBbls of proved reserves as of December 31, 2002. This disposition closed in February 2003. We received $27.0 million and other consideration which included an interest in Atchafalaya Bay Field (where we already own an interest) and seismic over that area. We have reached an agreement to sell two other fields, Bentonia and Glazier Fields, for approximately $2.0 million combined, which is expected to close in late March. Both of these are much smaller fields with approximately 269,000 Bbls of proven reserves at year-end 2002. The proceeds from the sale of Laurel Field were applied to our bank debt, reducing our total debt to $325 million of as February 28, 2003.
We have been able to substantially improve the pricing (relative to NYMEX) for the crude oil sold from the COHO properties since their acquisition. Our sales prices one month after acquiring these properties (October 2002) increased by approximately $3.40 per barrel over the prices that COHO was receiving per barrel earlier in the year. This translated into a 50% increase in the PV10 Value of the acquisition, using constant prices and the futures price strip as of early September 2002. This additional value was possible due to our prominence in the area (we are the largest oil and natural gas producer in Mississippi), coupled with the strategic benefits of acquiring the general partner of Genesis Energy, L.P., which provides us an alternative market for our production because of their pipeline in the area. These improved prices had not changed substantially as of year-end 2002.
Acquisition of Genesis General Partner
On May 14, 2002, a newly formed subsidiary of Denbury acquired Genesis Energy, L.L.C. (which was converted to Genesis Energy, Inc.), the general partner of Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership, for total consideration, including expenses and commissions, of approximately $2.2 million. The general partner owns a 2% interest in the limited partnership. Genesis is engaged in two primary lines of business: crude oil gathering and marketing and pipeline transportation. Genesis was a strategic acquisition for us because of a crude oil pipeline they own in Mississippi near several of our significant oil fields. We believe that Genesis may be in the position to serve as a future financier and developer of our gathering systems, CO2 and crude oil pipelines and other midstream assets. We are also considering the economic transfer of certain of our assets, such as value of our industrial CO2 sales, to Genesis in exchange for cash or a combination of cash and partnership units. Whether such a transaction will occur, and if so, the pricing, form and timing, are still being evaluated.
We are accounting for our investment in Genesis under the equity method of accounting, which increased our 2002 net income by $55,000. We have included in the footnotes to the consolidated financial statements summarized financial information of Genesis (see Note 2 to the consolidated financial statements). Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which was $5.5 million as of December 31, 2002, and also included $26.3 million in letters of credit of which $3.2 million are for Denbury's benefit to secure purchases from Denbury. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CAPITAL RESOURCES AND LIQUIDITY
During 2002, we spent $99.3 million on oil and natural gas exploration and development expenditures, $16.4 million on CO2 capital investments, and approximately $56.4 million on oil and natural gas property acquisitions, the largest being the acquisition of properties from COHO Energy, Inc. (see "Acquisition of COHO Gulf Coast properties"). Our cash flow from operations for the year totaled $159.6 million, and we sold properties for aggregate proceeds of approximately $7.7 million. The combined funds of $167.3 million funded all but $4.8 million of our 2002 expenditures, the balance of which was funded by a $9.1 million net increase in bank debt.
Graph depicting average NYMEX crude oil price listings by quarter from 2000 through 2002:

                  2000                                2001                                     2002
--------------------------------------- ----------------------------------- ---------------------------------------
   Q1        Q2        Q3        Q4       Q1      Q2       Q3        Q4        Q1        Q2        Q3        Q4
  28.77     28.68     31.77     31.88    28.79   27.98    26.78     20.45     21.68     26.24     28.26     28.20	

Graph depicting average NYMEX natural gas price listings by quarter from 2000 through 2002:

                 2000                                  2001                                  2002
--------------------------------------- ----------------------------------- ---------------------------------------
   Q1        Q2        Q3        Q4       Q1      Q2       Q3        Q4        Q1        Q2        Q3        Q4
  2.61      3.66      4.54      6.50     6.30    4.41     2.81      2.72      2.49      3.41      3.21      4.33	

We anticipate that our capital spending during 2003, excluding any possible acquisitions, will be equal to or less than our cash flow generated from operations, as has been our policy since 1999. We currently have budgeted $130 million of new development and exploratory projects for 2003, plus approximately $7.7 million of projects from 2002. Based on current projections, using futures prices in place as of the first part of March 2003, this spending level is expected to be as much as $50 million to $75 million below our forecasted cash flow, depending on 2003 commodity prices. Initially, we plan to use any excess funds generated from operations to pay down debt or to fund, in whole or in part, possible acquisitions, although we may consider increasing our budget later in 2003 if commodity prices remain high and we reach our debt target of $300 million. We review our capital expenditure budget every quarter and make adjustments as necessary to reflect changes in commodity prices and successes or failures in our drilling program. As a result, since 1999, we have been able to keep our capital spending (excluding acquisitions) at levels equal to or below our cash flow from operations.
Although we have a significant inventory of development and exploration projects in-house, on a long-term basis we will need to make acquisitions in order to continue our growth and to replace our production. We are continuing to pursue small acquisitions that are near our CO2 pipeline in Western Mississippi and Southern Louisiana, plus individual fields in the Gulf of Mexico. Although we now control most of the fields along our CO2 pipeline, there are a few remaining smaller fields with potential that we do not control, plus we are continuing to acquire additional interests in the fields that we do own. We have targeted the acquisition of offshore blocks, which generally consist of one or two fields, where we see additional potential based on our review of 3D seismic or other geologic and geophysical data. Although we are continuing to pursue acquisitions in our other core areas, including larger acquisitions, this activity is a lower priority for us in 2003 than has been the case historically, given our good inventory of projects in-house and our goal of reducing our debt level. Any acquisitions that we make will likely be funded with either our excess cash flow or bank debt.
Debt
As of September 30, 2002, we had total debt of approximately $375 million following the COHO acquisition. It is our goal to limit our leverage. We generally measure leverage by a debt-to-cash flow ratio, cash flow being defined as cash flow from operations. Our target is a debt-to-cash flow ratio of 2 to 1 or less, using a moderate price deck. In today's commodity price environment, we interpret that to be oil prices in between $22.50 and $25.00 per Bbl and natural gas prices between $3.25 and $3.50 per Mcf. Based on these price assumptions, we would be within our targeted debt-to-cash flow ratio during 2003 if our total debt was reduced to $300 million. Thus, since the third quarter of 2002, we have used a portion of our cash flow from operations and proceeds from
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Graph depicting capital expenditures (in millions of dollars):

                                                  Year Ended December 31,
                                       -----------------------------------------------
                                           2000             2001             2002
                                       ------------     ------------     -------------
Acquisitions                               60.3             157.1            60.6
Development and Exploration                73.7             170.1           111.4	

property sales to reduce our bank debt. During the fourth quarter of 2002, we reduced debt by approximately $25 million, and with proceeds from the sale of Laurel Field in February 2003 we paid down another $25 million of debt, resulting in total debt as of February 28, 2003, of approximately $325 million. Due to the high commodity prices in February 2003 and the resulting amounts due on our hedges that were paid in early March, we borrowed $10 million on March 6, 2003 to fund our hedge payments. We expect to pay back this temporary borrowing after we receive our February production revenues, the majority of which will be received during the third week of March. We expect to achieve our debt goal of $300 million during the latter half of 2003 through the application of excess cash flow from operations, assuming that commodity prices do not change substantially, or possibly by the economic transfer of certain of our assets, such as the value of some of our industrial CO2 sales, to Genesis.
Graph depicting the Company's debt to total capitalization (in millions of dollars):

                                                    December 31,
                                       -------------------------------------
                                          2000         2001         2002
                                       ----------  ------------  -----------
Long-Term Debt                            199.0         334.8        344.9
Total Capitalization                      415.2         683.9        711.7	

In September 2002, we extended the maturity of our bank line from December 2003 to April 2006. Our borrowing base was left unchanged at $220 million and generally the same banks remained in the line, although Bank One became the new administrative agent. Our bank borrowing base is set by our banks at their sole discretion based on various factors, some of which are out of our control, such as the oil and natural gas prices used by the banks to value our reserves. As of March 15, 2003, we had approximately $135 million of bank debt outstanding, leaving us $85 million of current bank line availability. The next borrowing base review by the banks will be as of April 1, 2003, based primarily on year-end reserves. We currently do not anticipate any significant change in the borrowing base at the next redetermination, nor do we currently plan to ask for an increase, even though we believe such a request would be reasonable based upon the additional properties we acquired from COHO. As discussed above, we expect to reduce our total debt to $300 million, which (assuming completion of our subordinated debt refinancing discussed below) would leave us $145 million of availability on our bank line, which we believe is sufficient credit availability, as we do not expect to spend more than our cash flow on development and exploration for the foreseeable future.
On March 17, 2003, we announced a refinancing of our 9% Senior Subordinated Notes due 2008. We sold $225 million of 7.5% Senior Subordinated Notes due 2013 and called our existing $200 million of 9% notes at 104.5% of face value. Closing on the new notes is scheduled for March 25, 2003, subject to the satisfaction of customary closing conditions, and the redemption of the old notes is expected to occur on April 16, 2003. We intend to use the remaining net proceeds from this offering to reduce bank debt. Once completed, the refinancing is expected to save us around $2.6 million per year in interest expense. Assuming completion, we estimate that we will have a charge to earnings in the second quarter of 2003 of approximately $11.25 million, net of related income taxes, from the early retirement of our currently outstanding 9% notes.
Commitments and Obligations
We have no off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees, other than as disclosed in this section, nor do we have any debt or equity triggers based upon our stock or commodity prices. Subject to semi-annual reaffirmation, our bank debt is not due until April 2006, and our $200 million of subordinated debt is due in March 2008. Our only other obligations that are not currently recorded on our balance sheet are our operating leases, which primarily relate to our office space and minor equipment leases and various obligations for development and exploratory expenditures arising from purchase agreements or 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 as forecasted in the proved reserve reports. Our operating
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
lease obligations total $11.7 million in the aggregate and $1.7 million for 2003. We have committed to another operating lease on a portion of our CO2 facilities equipment at Mallalieu Field with an estimated value of approximately $5.6 million. This lease is expected to commence during mid-2003 with payments of approximately $900,000 per year for seven years. Our capital spending obligations total approximately $13.0 million over the next five years, $2.3 million of which is required in 2003. 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 six months and are part of our ongoing budget process. For a further discussion of our future development costs and proved reserves, see "Results of Operations - Depletion, Depreciation and Site Restoration".
At December 31, 2002, we had a total of $370,000 outstanding in letters of credit. Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which was $5.5 million as of December 31, 2002, and also included $26.3 million in letters of credit of which $3.2 million secured purchases from Denbury. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. We do not have any material transactions with related parties other than sales of production to Genesis Energy, L.P. as discussed in Note 2 to our consolidated financial statements. A summary of our obligations discussed above is presented in the following table:

                                                                   Expected Maturity Dates
---------------------------------------------------------------------------------------------------------------------

Amounts in Thousands                        2003        2004         2005        2006          2007       Thereafter
---------------------------------------------------------------------------------------------------------------------
Bank debt                               $      -   $       -    $       -   $ 150,000      $      -      $         -
Subordinated debt                              -           -            -           -             -          200,000(1)
Operating lease obligations                1,708       1,640        1,764       1,766         1,761            3,022
Capital expenditure obligations            2,332       2,500        2,500       2,500         2,500                -
Future development costs on proved
reserves, net of capital obligations      70,747      70,290       43,815      16,201        11,912           42,972
---------------------------------------------------------------------------------------------------------------------
      Total                             $ 74,787   $  74,430    $  48,079   $ 170,467      $ 16,173      $   245,994
---------------------------------------------------------------------------------------------------------------------	

(1) See "Debt" section above regarding a refinancing of this debt.
Long-term contracts require us to deliver CO2 to our industrial CO2 customers at various contracted prices. Based upon the maximum amounts deliverable as stated in the contracts, we estimate that we may be obligated to deliver up to 387 Bcf of CO2 to these customers over the next 18 years; however, based on the current level of deliveries, our commitment would be reduced to approximately 250 Bcf. Given the size of our proven CO2 reserves (approximately
1.6 Tcf), our current production capabilities and our predicted levels of CO2 usage for our own tertiary flooding program, we are confident that we can meet these delivery obligations.
We have oil price floors, collars and swaps that cover 75% to 85% of our currently anticipated 2003 oil and natural gas production, 40% to 50% of our currently anticipated 2004 oil and natural gas production and a minor portion of our anticipated 2005 natural gas production. Nearly 100% of the forecasted proved developed production from the COHO acquisition has been hedged through 2004 and is included in those production estimates (see also Note 7 to our consolidated financial statements for more detail on these hedges). We have entered into these hedges in order to protect our cash flow, so that a majority of our capital program can be implemented, and so that we can achieve a minimum rate of return on acquisitions, provided that our other assumptions related to the acquisitions are correct. While the current market value of almost all of our hedges is negative (i.e., a liability), they do offer significant protection should commodity prices drop in the future (see also "Market Risk Management" and Note 7 to the Consolidated Financial Statements).
Sources and Uses of Funds
During 2002, we spent approximately $99.3 million on exploration and development activities, approximately $56.4 million on acquisitions, the largest being the $48.2 million acquisition of the COHO properties, and approximately $16.4 million on CO2 related capital expenditures. Our exploration and development expenditures included approximately $62.3 million spent on drilling, $17.8 million of geological, geophysical and acreage expenditures and $19.1 million spent on facilities and recompletion costs. The exploration and development expenditures were funded by cash flow from operations, and the acquisitions were primarily funded by cash flow, supplemented by property dispositions totaling $7.7 million and incremental bank debt for the year of $9.1 million.
During 2001, we spent approximately $170.1 million on exploration and development activities and approximately $157.1 million on acquisitions (excluding the $42 million CO2 acquisition), the largest being the acquisition of Matrix. Our exploration and development expenditures included approximately $115.9 million spent on drilling, $18.7 million of geological, geophysical
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and acreage expenditures and $35.5 million spent on facilities and recompletion costs. The exploration and development expenditures were funded by cash flow from operations, and the acquisitions were primarily funded by net incremental debt.
During 2000, we spent approximately $73.7 million on exploration and development activities and approximately $60.3 million on acquisitions. These exploration and development expenditures included approximately $37.8 million spent on drilling, $8.5 million of geological, geophysical and acreage expenditures and $27.4 million spent on facilities and recompletion costs. We funded these exploration and development expenditures with cash flow from operations and funded our acquisitions with cash flow and net incremental bank debt of $46.5 million.
RESULTS OF OPERATIONS
CO2 Operations
Since 1999, when we acquired our first tertiary oil recovery operation at Little Creek Field, we have increasingly emphasized these types of operations and have acquired several fields which are potential flood candidates since that date. More importantly, in February 2001 we acquired the sources of CO2 and a pipeline to transport it to these fields. This acquisition included significant carbon dioxide reserves, production, production facilities located near Jackson, Mississippi and a 183-mile 20-inch pipeline which runs from the Jackson, Mississippi area into southern Louisiana. We acquired nearly 100% of the working interest in the producing CO2 wells and we operate the properties. During 2002, we drilled another CO2 producing well, which as of March 5, 2003, was producing around 28 million cubic feet of CO2 per day. Another well was completed in early March 2003, and we plan to drill two more wells during the remainder of 2003. As of December 31, 2002, we were capable of producing approximately 146 MMcf/d of CO2 and we expect to increase this capacity to around 200 MMcf/d by the end of 2003. Based on our inventory of potential tertiary recovery projects, we will need to drill additional CO2 wells in 2004 and beyond to further increase our production capacity to 350 MMcf/d of CO2 production in order to develop the oil fields along our CO2 pipeline as planned. Although we believe that our plans and projections are reasonable and achievable, there could be delays or unforeseen problems in the future which could delay our overall tertiary development program. We believe that such delays, if any, should only be temporary. As of December 31, 2002, based on a report prepared by DeGolyer and MacNaughton, we estimate that we have approximately 1.6 trillion cubic feet of usable CO2 reserves, net to our working interest.
Although our oil production from our CO2 tertiary recovery activities is still modest, we expect it to be an ever increasing portion of our production (see discussion of production below). In order to develop fields which are tertiary flood candidates and increase our oil production, we must continue to increase our CO2 production. Since we acquired the CO2 properties in February 2001, CO2 production has increased from approximately 65 MMcf/d to 146 MMcf/d as of year-end 2002. We plan for this to further increase during the next few years to over 300 MMcf/d. We are using this CO2 to further develop Little Creek Field, develop Mallalieu Field (acquired in 2001), and we expect to commence tertiary operations at McComb Field during 2003. We have tentatively scheduled tertiary projects at other oil fields along our pipeline, and project that oil production from these tertiary activities will increase from its current level of 3,863 Bbls/d during the fourth quarter of 2002 to as much as 17,000 Bbls/d in 2008. As of December 31, 2002, we had approximately 27.9 MMBbls of proven oil reserves in these fields along our CO2 pipeline and have identified and estimated significantly more potential in fields that we own. In addition to the development of the fields we currently own along our pipeline, we see other potential tertiary recovery projects in fields we own in Eastern Mississippi, including Heidelberg and Eucutta Fields, plus potential in several large old oil fields in Southern Louisiana which we do not currently own. However, in order to develop these areas we would need additional pipeline transportation facilities, and thus these potential projects are not in our short-term plans.
The increasing emphasis on CO2 tertiary recovery projects has made, and will continue to make, an impact on our financial results and certain operating statistics. First, there is a significant delay between the initial capital expenditures and the resulting production increases, as these tertiary operations require the building of facilities before CO2 flooding can commence and usually require six to twelve months before the field responds to the injection of CO2. Secondly, as these tertiary projects are more expensive to operate than our other oil fields because of the cost of injecting and recycling the CO2, our overall operating expenses on a per BOE basis will likely continue to increase as these operations constitute an increasingly larger percentage of our operations. These tertiary recovery fields are expected to average between $9 and $10 per BOE in operating expenses over the life of the field, although the cost per BOE is higher at the beginning of each operation. This compares to a cost of around $5 per BOE for a more traditional oil property. Third, while our operating expense on a per BOE basis may rise, our overall oil prices, measured as a discount to NYMEX prices, should continue to improve. These CO2 operations are all currently conducted in fields that produce light sweet oil and receive oil prices close to (and sometimes actually higher than) NYMEX prices. As this production
-31-
 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Graph depicting development and exploration expenditures vs. cash flow from operations (in millions of dollars):

                                                                      Year Ended December 31,
                                                            -------------------------------------------
                                                               2000            2001            2002
                                                            -----------    ------------    ------------
Development and Exploration Expenditures                       73.7           170.1           111.4
Cash Flow from Operations                                      96.0           185.0           159.6	

becomes a larger percentage of our overall production, our overall average differential to NYMEX should decrease. While our oil prices have historically averaged between $4.00 and $5.00 below NYMEX prices, our 2002 average was $3.73 below NYMEX. This positive trend should continue, subject of course to the normal fluctuations in the marketplace. Despite these high operating costs, due to the high oil price (relative to NYMEX) and the relatively low finding and development costs (anticipated average of approximately $4.00 per BOE), these tertiary recovery operations generate a reasonable rate of return at NYMEX oil prices of $18 to $19 and generate positive cash flow at oil prices significantly lower than that. These tertiary recovery operations are generally lower risk than other types of oil and gas development or exploration, as they are conducted in fields where there has been substantial proven oil production in the past. We anticipate that we will spend between 25% and 50% of our annual development budget on these projects, at least for the next few years, unless there is a significant drop in oil prices or our economics change for some unforeseen reason. We believe that the ownership of our CO2 reserves provides us a significant strategic advantage in the acquisition of other properties in Mississippi and Louisiana that could be further exploited through tertiary recovery.
It cost us approximately $0.13 per thousand cubic feet to produce our CO2 during 2002, higher than the $0.07 average for 2001, primarily due to the incremental cost of compression equipment beginning in the third quarter of 2002 and increased maintenance work performed on the facilities during 2002. We allocate the operating expenses to produce our CO2 and operate and maintain our CO2 pipeline between the sales to commercial users and CO2 used for our own account. We expect these costs to be reduced slightly in the future as a result of the incremental CO2 production from the wells we drilled in 2002 and early 2003 and the anticipated production from the two additional CO2 wells scheduled later in 2003. The estimated total cost per thousand cubic feet of CO2 for us during 2002 was approximately $0.16, after inclusion of depreciation and amortization expense, still less than the $0.25 per thousand cubic feet that we were paying before we acquired the properties in February 2001.
In addition to using CO2 for our own account, we sell CO2 to third party industrial users under long-term contracts. Our net operating margin from these sales was $4.3 million during 2001 and $6.2 million during 2002. Our average CO2 production during 2001 and 2002 was approximately 84 million and 104 million cubic feet per day, of which approximately 53% in 2001 and 54% in 2002 was used in our tertiary recovery operations, with the balance sold to third parties for industrial use.
Operating Income
Since 1998, cash flow from operations improved each year until 2002 because of higher commodity prices and production levels. Even though production increased approximately 14% in 2002 over 2001 production levels, our cash flow from operations decreased 14% due to a 24% decline in the average NYMEX natural gas price, a 95% decrease in the proceeds from derivative contracts and a 5% increase in total expenses.

                                                                         Year Ended December 31,
-----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Share Amounts                         2002            2001            2000
-----------------------------------------------------------------------------------------------------------
Net income                                                     $     46,795   $       56,550   $    142,227
Net income per common share:
   Basic                                                       $       0.88   $         1.15   $       3.10
   Diluted                                                             0.86             1.12           3.07
-----------------------------------------------------------------------------------------------------------
Adjusted cash flow from operations                             $    164,565   $      186,801   $    111,555
Net change in assets and liabilities relating to operations          (4,965)          (1,754)       (15,583)
-----------------------------------------------------------------------------------------------------------
   Cash flow from operations                                   $    159,600   $      185,047   $     95,972
-----------------------------------------------------------------------------------------------------------	

Adjusted cash flow from operations represents cash flow provided by operations before the changes in assets and liabilities. In our discussion of operations herein, we have elected to discuss the two primary components of cash flow provided by operations. Adjusted cash flow from operations measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe that this is important to consider separately, as we believe it
-32-
 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Graph depicting cash flow from operations and adjusted cash flow from operations by quarter (in millions of dollars):

                                             2000                             2001                               2002
                                  --------------------------      ---------------------------       ---------------------------
                                Q1       Q2       Q3      Q4       Q1       Q2      Q3     Q4        Q1      Q2        Q3     Q4
Cash flow from operations      15,201  27,642   26,837  26,292   66,089   30,886  45,097  42,975   12,032   46,572   44,379  55,617
Adjusted cash flow from
 operations*                   19,562  21,340   27,502  43,151   54,982   45,194  48,670  37,955   28,524  43,423    44,177  48,411
*(Cash flow from operations before changes in assets and liabilities.  See prior table.)	

can often be a better way to discuss changes in operating trends in our business caused by changes in production, prices, operating costs, and so forth, without regard to whether the earned or incurred item was collected or paid during that year. We also use this measure because the collection of our receivables and payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, as we have very few uncollectible items and pay all of our obligations.
The net change in assets and liabilities that is a part of cash flow provided by operations is also important as it does require or provide additional cash for use in our business; however, we prefer to discuss its effect separately. For instance, as noted above, during 2002 we used approximately $5.0 million of cash to fund a net increase in working capital. This was primarily caused by a high level of drilling and exploitation activity late in 2001 which was not paid (or even due) until 2002. We also used a significant amount of cash flow from operations in 2000, as our net change in assets and liabilities in that year was a negative $15.6 million, primarily relating to unusually high natural gas prices late in 2000, for which we were not paid until the following month (as is normal in our industry), causing a higher than normal increase at year-end 2000 in production receivables. While both are components of a GAAP measure, we believe that it makes sense to discuss them independently.
During 2002, we set another Company record for production. Certain of our operating statistics are set forth in the following chart.

                                                                       Year Ended December 31,
-----------------------------------------------------------------------------------------------------------
                                                                2002              2001            2000
-----------------------------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION VOLUME
     Bbls                                                          18,833            16,978          15,219
     Mcf                                                          100,443            85,238          37,078
     BOE(1)                                                        35,573            31,185          21,399
OPERATING REVENUES AND EXPENSES (THOUSANDS)
     Oil sales                                             $      153,705    $      132,219   $     144,230
     Natural gas sales                                            121,189           128,179          60,406
     Gain (loss) on settlements of derivative contracts (2)           932            18,654         (25,264)
                                                           --------------    --------------   -------------
           Total oil and natural gas revenues              $      275,826    $      279,052   $     179,372
                                                           ==============    ==============   =============
      Lease operating expenses                             $       71,188    $       55,049   $      38,676
      Production taxes and marketing expenses                      11,902            10,963           8,051
                                                           --------------    --------------   -------------
           Total production expenses                       $       83,090    $       66,012   $      46,727
                                                           ==============    ==============   =============
      CO2 sales to industrial customers                    $        7,580    $        5,210   $           -
      CO2 operating expenses                                        1,400               891               -
                                                           --------------    --------------   -------------
          CO2 operating margin                             $        6,180    $        4,319   $           -
                                                           ==============    ==============   =============
UNIT PRICES-INCLUDING IMPACT OF HEDGES(2)
     Oil price per Bbl                                     $        22.27    $        21.65   $       23.50
     Gas price per Mcf                                               3.35              4.66            3.57
UNIT PRICES-EXCLUDING IMPACT OF HEDGES(2)
     Oil price per Bbl                                     $        22.36    $        21.34   $       25.89
     Gas price per Mcf                                               3.31              4.12            4.45
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1)
     Oil and natural gas revenues (including hedges)       $        21.24    $        24.52   $       22.90
                                                           --------------    --------------   -------------
     Lease operating expenses                                        5.48              4.84            4.94
     Production taxes and marketing expenses                         0.92              0.96            1.02
                                                           --------------    --------------   -------------
            Total production expenses                      $         6.40    $         5.80   $        5.96
-----------------------------------------------------------------------------------------------------------	

(1) Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE").
(2) See also "Market Risk Management" below for information concerning the Company's hedging transactions.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Graph depicting production by quarter (average MBOE per day):

                              2000                              2001                             2002
               ---------------------------------- --------------------------------- -------------------------------
                 Q1       Q2       Q3       Q4       Q1      Q2       Q3      Q4       Q1      Q2     Q3      Q4
               ---------------------------------- --------------------------------- -------------------------------
Oil             14,382   14,809   15,405   16,268   16,269  16,454   16,877  18,292   17,740 17,920  18,931  20,706
Natural Gas      4,739    4,771    5,148   10,028   10,366  11,448   18,235  16,664   17,621 17,606  16,575  15,188
               ---------------------------------- --------------------------------- -------------------------------
   Total BOE    19,121   19,580   20,553   26,296   26,635  27,902   35,112  34,956   35,361 35,526  35,506  35,894	

PRODUCTION. From the first quarter of 1999 through the third quarter of 2001, our average daily production increased each quarter, with production in the fourth quarter of 2001 being only slightly less than our third quarter 2001 peak. Our production during 2002 was relatively constant, with only slight growth during the year. Our 2002 production growth was less than it had been in prior years primarily due to a smaller capital budget because of lower commodity prices, particularly late in 2001 and early 2002. In addition, as discussed in "CO2 Operations" above, our production does not directly correspond with our related capital spending on tertiary recovery projects.
Our production growth over the years has generally been related to acquisitions and subsequent development of the acquired fields. During the last three years, our significant acquisitions of oil and natural gas properties have consisted of the $56.5 million acquisitions of Thornwell, Porte Barre and Iberia Fields in the fourth quarter of 2000, the $4.0 million acquisition of Mallalieu Field in May 2001, the $157.4 million corporate acquisition of Matrix in July 2001, the $2.3 million acquisition of McComb Field in September 2002, and the $48.2 million acquisition of COHO's Gulf Coast properties in August 2002 (see "Acquisition of COHO Gulf Coast Properties" above).
Production by area for 2000, 2001 and each of the quarters of 2002 is listed in the following table.

                                                             Average Daily Production (BOE/d)
                                     --------------------------------------------------------------------------------
                                                                        First        Second       Third      Fourth
                                                                       Quarter       Quarter     Quarter     Quarter
Operating Area                            2000          2001             2002         2002         2002        2002
---------------------------------    -----------  ------------ ---------------- ------------  ----------- -----------
Mississippi - non-CO2 floods              13,179        13,481           12,423       12,124       13,232      15,703
Mississippi - CO2 floods                   2,018         2,560            3,839        4,278        3,895       3,863
Onshore Louisiana                          5,878         9,268            8,405        7,717        8,224       7,859
Offshore Gulf of Mexico                      201         5,691           10,550       11,229        9,863       8,287
Other                                        123           185              144          178          292         182
                                     -----------  ------------ ---------------- ------------  ----------- -----------
    Total Company                         21,399        31,185           35,361       35,526       35,506      35,894
---------------------------------    -----------  ------------ ---------------- ------------  ----------- -----------	

Our average production from our non-CO2 flood properties in Mississippi decreased slightly during 2002, excluding the increases attributable to the acquisition of COHO properties, due to general production declines at most of our significant fields and a reduced level of capital expenditures in this area during 2002. Heidelberg Field, located in Eastern Mississippi, is Denbury's largest single field. At the time of its acquisition in December 1997, Heidelberg Field was producing approximately 2,800 BOE/d. Production under our ownership has subsequently averaged 3,760 BOE/d, 5,708 BOE/d, 7,310 BOE/d, 7,908 BOE/d and 7,479 BOE/d for 1998, 1999, 2000, 2001 and 2002. During 1998, our primary emphasis was implementation of the field's largest waterflood unit, the East Heidelberg Waterflood Unit, plus other developmental drilling. During 1999, we began to see response from our waterflood efforts. We added other waterflood units during 1999 and 2001 and also expanded our drilling for natural gas at Heidelberg in the Selma Chalk formation during the second half of 1999. As a result, natural gas production at Heidelberg increased from 0.5 MMcf/d in 1998 to 1.0 MMcf/d in 1999, 3.8 MMcf/d in 2000 and 7.4 MMcf/d in 2001. Our activity in 2002 was generally related to continued maintenance of the waterfloods in progress, plus the drilling of eight additional natural gas wells in the second half of the year as a result of the higher natural gas prices. Average production at our Heidelberg Field during 2002 was 5% lower than production levels there in 2001. Overall production from this field is expected to remain relatively flat or slightly decline as the waterfloods appear to have reached a plateau, although there may be periodic spikes in the natural gas production as a result of the recently drilled additional natural gas wells.
Since 1999, when we acquired our first tertiary oil recovery operation at Little Creek Field, we have increasingly emphasized these types of operations and have acquired several fields that are potential CO2 flood candidates since that date (see the discussion of
-34-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"CO2 Operations" above). Although production from our CO2 activities is still modest, we expect it to be an ever increasing portion of our production. It has generally increased each period, although in the third and fourth quarters of 2002, average production on our tertiary recovery properties was slightly less than the second quarter 2002 average due to a temporary lack of deliverability of CO2. We have increased our CO2 production since that time and are continuing to drill additional CO2 wells and believe that we have sufficiently increased our CO2 production to meet our current needs for our tertiary recovery operations, although we will require additional CO2 production in the future (see "CO2 Operations" above for further information). As such, production from these fields has begun to respond, averaging approximately 4,019 Bbls/d during February 2003, a 4% increase over the fourth quarter 2002 average. Production at Little Creek Field, our oldest and currently our largest tertiary recovery operation, has also increased since we acquired it in August 1999. At the time of acquisition, Little Creek was producing approximately 1,350 BOE/d, with a 1999 annual average production rate of 587 BOE/d, due to our ownership for a partial year. Since acquiring the field, we have completed phase III of the CO2 flood and implemented phases IV and V, resulting in gradual production increases. Production from Little Creek Field averaged 2,018 BOE/d for 2000, 2,462 BOE/d for 2001, and 3,393 BOE/d in 2002. We are continuing to expand our tertiary recovery operations at Little Creek and anticipate that production will further increase at this field throughout 2003.
Production from our onshore Louisiana area was generally down year over year, although there have been fluctuations up and down on a quarter-to-quarter basis primarily as a result of drilling activity at Thornwell Field. Production at Thornwell Field during 2002 averaged 3,910 BOE/d, a 9% decrease from production levels in 2001. The majority of the production at Thornwell is short-lived natural gas production, and thus volumes can fluctuate significantly from period to period depending on the level of activity, the timing of well completions, and other factors. Overall, we believe the Thornwell acquisition in October of 2000 has performed well, as we recovered our acquisition cost within the first year of ownership. We are continuing development and exploration activities at Thornwell Field in 2003, although at a lower level than in 2002.
Our natural gas production has significantly increased during the last couple of years, primarily due to the acquisition of the offshore Gulf of Mexico properties owned by Matrix Oil and Gas in July 2001. Our development and exploration activities on these properties was minimal in 2002 due to the low natural gas prices at the beginning of the year. Thus offshore production generally declined during the latter half of 2002, although annual average production here was still higher in 2002 than in 2001. Production was also hurt by two storms, Tropical Storm Isidore in September 2002 and Hurricane Lili in October 2002. Although it is difficult to measure the exact impact of the storms, our offshore production declined by 1,366 BOE/d between the second and third quarters of 2002 and further declined by 1,576 BOE/d in the fourth quarter of 2002, a significant portion of which relates to the shut-in of production caused by the two storms. The storm also caused other indirect declines in production, both onshore and offshore, by delaying several projects because of unusually wet conditions, high water, and other storm-related effects. As an example, the incremental CO2 production from a well we drilled in the third quarter was delayed because the wet conditions made it difficult to install a pipeline to hook up the well. These types of delays caused our production to be less than we had originally anticipated in the last half of the year. During 2003, with anticipated higher natural gas prices, we are spending almost 30% of our budget offshore, second only to our CO2 operations expenditures. Since the acquisition of Matrix in July 2001, our production has generally been close to 50/50 oil and natural gas and we anticipate that balance to remain near 50/50 in the near future based on our current development plans.
REVENUE. Our oil and natural gas revenues increased 56% between 2000 and 2001, but decreased slightly (1%) in 2002. The growth in 2001 revenues was primarily due to a 46% increase in production, as our net per BOE prices were almost the same. During 2002, production increased 14%, but the decline in natural gas prices caused our net per BOE price to decline by 7%, thereby limiting the revenue increase between years. Between 2000 and 2001, the overall increase in production volumes contributed $92.8 million in revenue, or a 52% increase, and the incremental cash receipts from hedges contributed $43.9 million, or a 25% increase, partially offset by an overall decrease of $37.0 million in commodity prices (or a negative 21%). Between 2001 and 2002, revenues decreased by 1%, due primarily to lower hedging receipts. The overall increase in production volumes contributed $36.6 million in revenue, or a 13% increase, more than offset by the combined 14% reduction in revenues due to a decrease in cash receipts from hedges of $17.7 million (a negative 6%) and an overall decrease of $22.1 million in commodity prices (or a negative 8%).
During 2000, we paid out $13.3 million ($2.39 per Bbl) on our oil hedges and $11.9 million ($0.88 per Mcf) on our natural gas hedges. In contrast, during 2001, we collected $1.9 million ($0.31 per Bbl) on our oil hedges and $16.7 million ($0.54 per Mcf) on our natural gas hedges. During 2002, we paid out $0.6 million ($0.09 per Bbl) on our oil hedges but collected a net $1.5 million ($0.04 per Mcf) on our natural gas hedges. See "Market Risk Management" for a further discussion of our hedging activities.
-35-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OPERATING EXPENSES. Oil and natural gas lease operating expenses decreased 2% on a per BOE basis between 2000 and 2001, as a result of the addition of the Matrix properties in July 2001 and savings resulting from our ownership of CO2 assets purchased in February 2001. These savings were partially offset by overall higher service and equipment costs in the industry during the year. The Matrix properties predominately consisted of natural gas, which typically have a lower per unit operating cost than oil properties. We also reduced operating expenses by approximately $2.6 million during 2001 because of our acquisition of the CO2 source fields and operations in February 2001 (see "CO2 Operations" above).
Our oil and natural gas lease operating expenses increased 13% on a per BOE basis between 2001 and 2002. This increase was primarily due to higher than usual workover expenses, principally offshore on the Matrix properties, repairs relating to storm damage from Hurricane Lili that was not covered by insurance or was part of the insurance deductible amount, higher per BOE costs due to the lost production from that storm and Tropical Storm Isidore, and higher than average operating expenses on the properties acquired from COHO in August 2002, as significant repairs and clean-up were required. Lastly, as discussed under "CO2 Operations" above, operating expenses are gradually increasing as a result of the increased tertiary recovery operations. Lease operating expenses increased on a gross basis by $16.1 million, or 29%, between the two years.
Operating expenses increased slightly in our non-CO2 flood Mississippi properties from $6.07 per BOE in 2001 to $6.31 per BOE for 2002, primarily due to the addition of the COHO properties in late August 2002. Operating expenses for the COHO properties averaged $9.91 per BOE and are expected to remain unusually high during the first half of 2003 as we continue to clean up these fields and perform necessary repairs and maintenance to return these fields to proper working condition. In comparison, operating costs per BOE for our long-standing non-CO2 Mississippi properties were $5.21 per BOE in 2000, lower than the $6.07 per BOE in 2001, with the increase primarily due to higher overall costs in the industry in 2001. Offshore operating expenses were $5.08 per BOE for 2002, higher than the 2001 average of $3.46 per BOE. The higher operating expenses generally correlate with the increased number of workovers in 2002 and lower production than anticipated due to the suspended production as a result of Tropical Storm Isidore and Hurricane Lili. In addition, we had approximately $750,000 of repairs due to Hurricane Lili which were not covered by insurance or were part of our insurance deductible expensed in the fourth quarter of 2002. Operating costs per BOE for 2000 in our limited offshore operations do not provide a meaningful basis for comparison due to the lower level of activity prior to the Matrix acquisition. Operating expenses at Little Creek Field were $9.45 per BOE in 2002, slightly less than the $9.80 per BOE for 2001, due primarily to higher production rates. In comparison, operating costs per BOE were $11.15 at Little Creek in 2000, with the savings primarily due to the lower cost of CO2 after the CO2 acquisition in February 2001 and higher overall production rates.
Production taxes and marketing expenses on a per BOE basis decreased 6% between 2000 and 2001 and 4% between 2001 and 2002. The decrease in 2002 was primarily due to a reduction in the Louisiana gas severance tax rate effective July 1, 2002. The decrease in production taxes and marketing expenses in 2001 was due to the addition of the Matrix properties, a portion of which are tax exempt due to their offshore location, partially offset by higher marketing expenses on the offshore properties relating to incremental processing and transportation costs.
General and Administrative Expenses
During the last three years, general and administrative ("G&A") expenses on a per BOE basis have fluctuated between $0.89 and $1.09 per BOE. Our gross G&A expense increased each year, but with our significant production increases, net G&A expense on a per BOE basis has remained around $1.00 per BOE.

                                                                               Year Ended December 31,
---------------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE and Employee Data                        2002         2001           2000
---------------------------------------------------------------------------------------------------------------
Gross G&A expense                                                       $    40,149    $  33,727   $     24,941
Operator overhead charges                                                   (23,857)     (20,328)       (13,684)
Capitalized exploration expense                                              (5,325)      (4,102)        (3,202)
---------------------------------------------------------------------------------------------------------------
                                                                             10,967        9,297          8,055
State franchise taxes                                                         1,459          877            467
---------------------------------------------------------------------------------------------------------------
     Net G&A expense                                                    $    12,426    $  10,174   $      8,522
---------------------------------------------------------------------------------------------------------------
Average G&A expense per BOE                                             $      0.96    $    0.89   $       1.09

Employees as of December 31                                                     356          320            242
---------------------------------------------------------------------------------------------------------------	

-36-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We have grown for the last several years from both acquisitions and our own internal development and exploration work. As a result, we have had general increases in consultant fees, hired additional personnel, and have given salary increases and bonuses each year. In particular, we hired additional personnel as part of the Matrix acquisition in July 2001 and COHO acquisition in August 2002. Our bonuses, as authorized by our board of directors, were at the upper end of the bonus plan range in all three years, 2000 through 2002, based primarily on our overall financial and operating results.
Partially offsetting the overall increase in gross G&A costs are the increases in operator overhead charges and capitalized exploration expenses. The respective well operating agreements allow us, when we are the operator, to charge a specified overhead rate during the drilling phase and to charge a monthly fixed overhead rate for each producing well. As a result of the general escalation in activity each year and the addition of more operated wells from our acquisitions, this recovery of G&A increased from $13.7 million in 2000 to $20.3 million in 2001 and to $23.9 million in 2002. Capitalized exploration costs also increased each year as a result of the increase in gross G&A expense and the additional technical personnel added as part of the Matrix and COHO acquisitions. As a result, net G&A expense increased only 19% in 2001 and 22% in 2002, even though gross G&A expense increased 35% and 19% respectively. On a per BOE basis, G&A costs decreased 18% in 2001 but increased 8% in 2002, both changes less than the absolute change in G&A due to the higher production volumes each year.
Interest and Financing Expenses

                                                                    Year Ended December 31,
---------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data                        2002              2001              2000
---------------------------------------------------------------------------------------------------------
Interest expense                                      $        26,833    $       22,335     $      15,255
Non-cash interest expense                                      (2,659)           (1,665)             (945)
---------------------------------------------------------------------------------------------------------
Cash interest expense                                          24,174            20,670            14,310
Interest and other income                                      (1,746)             (849)           (2,279)
---------------------------------------------------------------------------------------------------------
     Net cash interest expense                        $        22,428    $       19,821     $      12,031
---------------------------------------------------------------------------------------------------------

Average net cash interest expense per BOE             $          1.73    $         1.74     $        1.54

Average debt outstanding                              $       350,556    $      264,792     $     160,884

Average interest rate (1)                                         6.9%              7.8%              8.9%
---------------------------------------------------------------------------------------------------------	

(1) Includes commitment fees but excludes amortization of debt issue costs.
We began 2000 with $152.5 million of total outstanding debt. During 2000, we borrowed $61 million to fund property acquisitions and related hedges, but repaid $14.5 million from cash flow, ending the year with $199 million of long-term debt outstanding. During 2001, we had total bank borrowings of $146.0 million, primarily to fund our acquisition of Matrix ($100.0 million) and the CO2 acquisition ($42.0 million). We repaid a total of $79.1 million during the year, (i) $13.0 million of which related to excess cash flow generated from operations early in the year given the unusually high natural gas prices and
(ii) $65.9 million of which represented the net proceeds of our issuance of Series B 9% Senior Subordinated Notes due 2008, in August 2001. These notes were issued at a discount with an estimated yield to maturity of 10 7/8%. Our total outstanding debt increased from $199 million as of December 31, 2000, to $340.9 million as of December 31, 2001 (excluding the unamortized issue discount), a 71% increase. Our average interest rate decreased in 2001 due to an overall drop in interest rates, even though we issued an additional $75 million of subordinated debt in August at a relatively high interest rate. Overall, we had a 65% increase in net cash interest expense in 2001, but only a 13% increase on a BOE basis due to our overall production increases.
During 2002, we borrowed $49.1 million, primarily to fund the COHO acquisition, and repaid $40.0 million during the year from excess cash flow, leaving us with $350 million of total debt outstanding as of December 31, 2002 (excluding the discount). On average our debt balance was $85.8 million higher in 2002 than in 2001 due to the acquisitions during both periods. Our average interest rate was 0.9% lower in 2002 primarily due to decreases throughout 2001 and 2002 in interest rates on our variable rate bank debt, offset in part by the issuance of $75 million of subordinated debt in August 2001 which carries a higher interest rate than the bank debt it replaced. Net cash interest expense on a per BOE basis decreased 1% between 2001 and 2002 due to our higher production, an increase in interest and other income in 2002, and a higher percentage of interest expense relating to non-cash amortization following the issuance of subordinated debt at a discount in August 2001.
-37-
 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depletion, Depreciation and Site Restoration
Depletion, depreciation and amortization ("DD&A") was at its lowest rate on a per BOE basis in our history in 1999 as a result of the full cost pool writedowns in 1998. Since that time, our DD&A rate has increased each year as our overall finding cost has been greater than the abnormally low rate in 1999, particularly the finding cost of certain of our acquisitions.

                                                                      Year Ended December 31,
--------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data                           2002             2001           2000
--------------------------------------------------------------------------------------------------------
Depletion and depreciation                                  $     87,728     $     66,402    $    34,530
Depreciation of CO2 assets                                         1,858            1,572              -
Site restoration provision                                         2,951            1,946            560
Depreciation of other fixed assets                                 1,699            1,425          1,124
--------------------------------------------------------------------------------------------------------
     Total DD&A                                             $     94,236     $     71,345    $    36,214
--------------------------------------------------------------------------------------------------------
DD&A per BOE:
    Oil and natural gas properties                          $       6.98     $       6.01    $      4.48
    CO2 assets and other fixed assets                               0.28             0.26           0.14
--------------------------------------------------------------------------------------------------------
        Total DD&A cost per BOE                             $       7.26     $       6.27    $      4.62
--------------------------------------------------------------------------------------------------------	

The NYMEX oil prices used in our reserve reports have ranged from $26.80 per Bbl as of December 31, 2000 to $19.84 per Bbl as of December 31, 2001, and $31.20 per Bbl as of December 31, 2002. Natural gas prices have been even more volatile, moving from $9.78 per Mcf at December 31, 2000, to $2.57 per Mcf at December 31, 2001, then to $4.79 per Mcf at December 31, 2002. Even though we require our proved undeveloped properties to be economic at relatively low commodity prices, so that their inclusion in our reserves is not dependent on commodity prices, the fluctuating prices do impact DD&A because of the effect commodity prices have on the economic lives of our properties (and thus the changes in reserve quantities). Between 2000 and 2001, the significant reduction in commodity prices, particularly those for oil, reduced the economic lives of our properties and reduced reserve quantities by 8.3 MMBOE. Overall, during 2001 we showed a 25% increase in reserve quantities as we added 41.8 MMBOEs from acquisitions, other development work, and upward revisions. Our total proved reserve quantities increased from 87.4 MMBOE as of December 31, 2000, to 109.5 MMBOE as of December 31, 2001.
Graph depicting our proved reserves (MMBOE):

                                           December 31,
                            -----------------------------------------------
                                 2000             2001             2002
                            ------------     ------------     -------------
Oil                             70.7             76.5              97.2
Natural Gas                     16.7             33.0              33.5
                             ------------     ------------     -------------
   Total                        87.4            109.5             130.7	

During 2002, prices rebounded, increasing our reserve quantities by approximately 3.5 MMBOE due solely to the price changes. During 2002, we also added 35.9 MMBOE, primarily from our COHO acquisition and additional reserves booked on our CO2 tertiary flood properties. Our total proved reserve quantities increased from 109.5 MMBOE as of December 31, 2001, to 130.7 MMBOE as of December 31, 2002.
Reserve quantities are only one side of the DD&A equation, with capital expenditures and projected future development costs making up the remainder of the calculation. During 2001 our DD&A rate increased from $4.62 per BOE in 2000 to an average rate of $6.27 per BOE ($7.19 per BOE during the second half of the year after the Matrix acquisition), primarily as result of our acquisition of Matrix in July 2001. This acquisition had a higher than average cost per BOE ($13.28 per BOE, including unevaluated property costs) because of the high natural gas price environment. The acquisition itself looks positive, as we have increased our reserve quantities from this acquisition since the acquisition closed in July 2001 by 22% (or 55% by adding back production), natural gas prices are currently above price levels at the time of acquisition, and we still have most of the probable and possible reserves remaining to exploit. In addition, the PV10 Value of these properties at December 31, 2002, is approximately $101.7 million more than our net unrecovered cost.
-38-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The DD&A calculation is also affected by our future development costs, which increased from $95.1 million as of December 31, 2000, to $178.5 million as of December 31, 2001, to $268.3 million as of December 31, 2002. These future development costs represent the estimated cost necessary to recover our undeveloped reserves, with the largest single increases relating to the 10.4 MMBbls of reserves recorded at Mallalieu Field in 2001 and 8.3 MMBbls recorded at McComb Field in 2002. As the overall percentage of undeveloped reserves relative to our total reserves has increased from approximately 24% in 2001 to approximately 34% in 2002, so has the amount of future development costs. In addition, at two of our fields, McComb and North Padre Island, pending further development work and/or testing, the reserve quantities booked at year-end are only a portion of what we believe to be each field's ultimate potential. Since the currently booked proven reserves must bear the total cost of these fields' required facilities, the future development costs per BOE are higher here than what we ultimately expect them to be. In summary, even though reserve quantities were 19% higher in 2002 than in 2001, as a result of the other factors discussed above, our DD&A rate per BOE of $7.26 in 2002 was relatively unchanged from the $7.19 DD&A rate per BOE during the last half of 2001 (the rate after the Matrix acquisition).
We provide for the estimated future costs of well abandonment and site reclamation, net of any anticipated salvage, on a unit-of-production basis. This provision is included in DD&A expense and has increased each year, along with the general increase in the number of our properties, especially the acquisition of our offshore properties. Beginning January 1, 2003, we are required to adopt Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." With the adoption of this new accounting standard, we will record the estimated future abandonment cost as an asset and liability on our balance sheet. While there may be some adjustments as a result of the adoption of this accounting pronouncement, we do not expect the adoption to materially impact our income statements going forward as these abandonment costs have historically been amortized as part of our DD&A.
Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. We did not have any full cost pool ceiling test writedowns in 2000, 2001 or 2002 and do not expect to have any such writedowns in the foreseeable future at the current commodity price levels.
Income Taxes
For the year ended December 31, 2000, we had taxable income of $27.6 million, but were able to offset this income with our net operating loss carryforwards ("NOLs"). We did incur $558,000 of current income tax expense during 2000 which related to alternative minimum taxes that could not be offset by NOLs. For the year ended December 31, 2000, a normal tax provision would have resulted in income tax expense of $27.7 million. However, we utilized a portion of our deferred tax assets and the corresponding valuation allowance to offset this provision. We also reevaluated the remaining balance of $67.9 million relating to our net deferred tax asset as of December 31, 2000. We concluded that it was more likely than not that there would be sufficient future taxable income that would allow us to realize the tax benefits of our deferred tax assets, resulting in a deferred tax benefit of $67.9 million and a net deferred tax asset balance as of December 31, 2001, of $67.9 million, none of which was impaired.
With the adjustment to deferred taxes in 2000, we began booking a normal tax provision in 2001. In 2001, we began to recognize the amount of enhanced oil recovery credits that we had earned to date from our tertiary projects, which totaled $5.3 million at year-end 2001. As a result of these credits, our effective tax provision for 2001 was lowered from 37% to 30.5%. Most of this provision was deferred, as we were able to offset our taxable income with our NOLs. The current portion of the tax provision related to alternative minimum taxes that could not be offset by NOLs.
Prior to 2002, our effective tax rate was 37%. During 2002, we determined that our effective rate had increased to 38% and adjusted our provision for the year accordingly. The net effective tax rate for 2002 was lower than 38%, primarily due to the recognition of enhanced oil recovery credits which lowered our overall tax expense. During 2002 we utilized almost all of our alternative minimum tax loss carryforwards. Therefore, in 2003 and beyond, a portion of our tax provision will be current as we will become an alternative minimum tax payer. As of December 31, 2002, we had approximately $84.9 million of regular tax net operating loss carryforwards remaining, to shelter our future income against regular tax.
The overall current income tax credit for 2002 is the result of a tax law change that allowed us to offset 100% of our 2001 alternative minimum taxes with our alternative minimum tax net operating loss carryforwards. Prior to the law change, we were able to offset only 90% of our alternative minimum taxes with these carryforwards. This change resulted in a refund of cash taxes paid for 2001 and a reclassification of tax expense between current and deferred taxes, but did not impact our overall effective tax rate.
-39-
 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

                                                                        Year Ended December 31,
-----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Unit Amounts                        2002             2001              2000
-----------------------------------------------------------------------------------------------------------
Current income tax expense (benefit)                           $    (406)             640         $     558
Deferred income tax provision (benefit)      .                    23,926           24,184           (67,852)
-----------------------------------------------------------------------------------------------------------
     Total income tax provision (benefit)                      $  23,520        $  24,824         $ (67,294)
-----------------------------------------------------------------------------------------------------------
Average income tax provision (benefit) per BOE                 $    1.81        $    2.18         $   (8.59)
Net operating loss carryforwards                                  84,891          100,601           112,690
-----------------------------------------------------------------------------------------------------------
Net deferred tax asset (liability)                             $ (21,777)       $ (17,433)        $  67,852
Valuation allowance                                                    -                -                 -
-----------------------------------------------------------------------------------------------------------
     Total net deferred tax asset (liability)                  $ (21,777)       $ (17,433)        $  67,852
-----------------------------------------------------------------------------------------------------------	

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

                                                                     Year Ended December 31,
-----------------------------------------------------------------------------------------------------
Per BOE Data                                                    2002           2001          2000
-----------------------------------------------------------------------------------------------------
  Oil and natural gas revenues                              $   21.17       $  22.88      $  26.13
  Gain (loss) on settlements of derivative contracts             0.07           1.64         (3.23)
  Lease operating expenses                                      (5.48)         (4.84)        (4.94)
  Production taxes and marketing expenses                       (0.92)         (0.96)        (1.02)
-----------------------------------------------------------------------------------------------------
       Production netback                                       14.84          18.72         16.94
  CO2 operating margin                                           0.48           0.38             -
  General and administrative expenses                           (0.96)         (0.89)        (1.09)
  Net cash interest expense                                     (1.73)         (1.74)        (1.54)
  Current income taxes and other                                 0.04          (0.06)        (0.07)
  Changes in assets and liabilities                             (0.38)         (0.15)        (1.99)
-----------------------------------------------------------------------------------------------------
       Cash flow from operations                                12.29          16.26         12.25
  DD&A                                                          (7.26)         (6.27)        (4.62)
  Deferred income taxes                                         (1.84)         (2.12)         8.66
  Amortization of derivative contracts and other
    non-cash hedging adjustments                                 0.24          (2.90)            -
   Changes in assets and liabilities and other non-cash
      items                                                      0.17              -          1.87
-----------------------------------------------------------------------------------------------------
      Net income                                            $    3.60       $   4.97      $  18.16
-----------------------------------------------------------------------------------------------------	

MARKET RISK MANAGEMENT
We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. The following table presents the carrying and fair values of our debt, along with average interest rates. The fair value of our bank debt is considered to be the same as the carrying value because the interest rate is based on floating short-term interest rates. The fair value of the subordinated debt is based on quoted market prices. None of our debt has any triggers or covenants regarding our debt ratings with rating agencies.

                                                           Expected Maturity Dates
-------------------------------------------------------------------------------------------------------------------------
                                                                                              Carrying           Fair
Amounts in Thousands                      2003-2005      2006         2007        2008          Value            Value
-------------------------------------------------------------------------------------------------------------------------
Variable rate debt:
     Bank debt..........................    $   -    $ 150,000      $   -        $       -      $ 150,000      $  150,000
           The weighted-average interest rate on the bank debt at December 31, 2002 is 3.2%.
Fixed rate debt:
     Subordinated debt, net of discount.    $   -    $       -      $   -        $ 194,889     $  194,889      $  206,580
           The interest rate on the subordinated debt is a fixed rate of 9%.	

-40-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We enter into various financial contracts to hedge our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have historically consisted of price floors, collars and fixed price swaps. We generally attempt to hedge between 50% and 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt. When we make an acquisition, we attempt to hedge a large percentage, up to 100%, of the forecasted production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. Our recent hedging activity has been predominately with collars, although for the recent COHO acquisition, we also used swaps in order to lock in the prices used in our economic forecasts. All of the mark-to-market valuations used for our financial derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification.
At December 31, 2002, our derivative contracts were recorded at their fair value, which was a net liability of approximately $35.6 million, a decrease of approximately $59.1 million from the $23.5 million fair value asset recorded as of December 31, 2001. This change is the result of (i) a decrease in the fair market value of our hedges due to an increase in oil and natural gas commodity prices between December 31, 2001, and December 31, 2002, (ii) the settlement received from our former Enron hedge positions in February 2002, and (iii) the expiration of certain derivative contracts during 2002 for which we recorded amortization expense of $9.7 million. Information regarding our current hedging positions and historical hedging results is included in Note 7 to the Consolidated Financial Statements.
Based on NYMEX natural gas futures prices at December 31, 2002, we would expect to make future cash payments of $17.2 million on our natural gas commodity hedges. If natural gas futures prices were to decline by 10%, the amount we would expect to pay under our natural gas commodity hedges would decrease to $3.7 million, and if futures prices were to increase by 10% we would expect to pay $36.1 million. Based on NYMEX crude oil futures prices at December 31, 2002, we would expect to pay $7.5 million on our crude oil commodity hedges. If crude oil futures prices were to decline by 10%, we would expect to receive $7.6 million under our crude oil commodity contracts, and if crude oil futures prices were to increase by 10%, we would expect to pay $25.2 million under our crude oil commodity hedges. Since December 31, 2002, prices increased substantially on both oil and natural gas, through at least early March 2003.
CRITICAL ACCOUNTING POLICIES
Our significant accounting policies are included in Note 1 to the Consolidated Financial Statements. These policies, along with the underlying assumptions and judgments by our management in their application, have a significant impact on our consolidated financial statements. We consider our most critical accounting policies are those related to property and equipment and hedging activities.
Property, Plant and Equipment, Depletion and Depreciation and Oil and Natural Gas Reserves
We follow the full-cost method of accounting for oil and natural gas properties. Under this method of accounting, the estimated quantities of proved oil and natural gas reserves used to compute depletion and the related present value of estimated future net cash flows therefrom used to perform the full-cost ceiling test have a significant impact on the underlying financial statements. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepare the report, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures.
The changes in commodity prices also affect our reserve quantities. For instance, between 2000 and 2001, the significant reduction in commodity prices, particularly oil, reduced the economic lives of our properties and reduced reserve quantities by 8.3 MMBOE. During 2002, both commodity prices rebounded, resulting in an increase to our reserve quantities of approximately 3.5 MMBOE. These changes in quantities affect our DD&A rate and the combined effect of changes in quantities and commodity
-41-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
prices impacts our full-cost ceiling test calculation. Also, reserve quantities and their ultimate values are the primary factors in determining the borrowing base under our bank credit facility and are determined solely by our banks.
There can also be significant questions as to whether the reserves are sufficiently supported by technical evidence to be considered proven. In some cases our proven reserves are less than what we believe to exist because additional evidence, including production testing, is required in order to classify the reserves as proven. In other cases, properties such as certain of our potential tertiary recovery projects may not have proven reserves assigned to them primarily because we have not yet completed a specific plan for development or firmly scheduled such development. We have a corporate policy whereby we do not book proved undeveloped reserves unless the project is scheduled in our development budget (or at least the commencement of the project in the case of longer-term multi-year projects such as waterfloods and tertiary recovery projects). In most cases, our development budget is prepared only for the next year or so. Therefore, particularly with regard to potential reserves from tertiary recovery (our CO2 operations), there is uncertainty as to whether the reserves should be included as proven or not. We also have a corporate policy whereby proved undeveloped reserves must be economic at long-term historical prices, which we have interpreted during the last several years as $18.50 per Bbl of oil and $2.50 per Mcf of natural gas. This also can have the effect of eliminating certain projects in a high price environment, as was the case at year-end 2002. (See "CO2 Operations" and "Depletion, Depreciation, and Site Restoration" under "Results of Operations" above for a further discussion). All of these factors and the decisions made regarding these issues can have a significant effect on our proven reserves and thus on our DD&A rate, full-cost ceiling test calculation, borrowing base and financial statements.
Hedging Activities
We enter into derivative contracts (i.e., hedges) to mitigate our exposure to commodity price risk associated with future oil and natural gas production. These contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps. With the adoption of SFAS No. 133 in 2001, every derivative instrument must be recorded on the balance sheet as either an asset or a liability measured at its fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the change in fair value of the derivative is recognized in other comprehensive income (equity), to the extent that the hedge is effective and in the income statement to the extent it is ineffective. We recognized ineffectiveness on our hedges of $600,000 for 2002.
With the significant changes in commodity prices over the last two years, the fair value of our hedges has gone from an asset valued at $23.5 million at year-end 2001 to a liability of $35.6 million as of year-end 2002. While most of this change in value is recorded in other comprehensive income, the dramatic swing in commodity prices and the corresponding effect on the fair value of our hedges can cause a dramatic change to our balance sheet. If these hedges were deemed to no longer qualify for hedge accounting at some point in time, as happened to our hedges with Enron in 2001 (see below), then the change in value would be reflected in our income statement.
In order to qualify for hedge accounting, the changes in fair value or cash flows of the hedging instruments and the hedged items must have a high degree of correlation (i.e., be effective). We measure and compute hedge effectiveness on a quarterly basis. If a hedging instrument becomes ineffective, hedge accounting is discontinued and any deferred gains or losses on the cash flow hedge remain in accumulated other comprehensive income until the periods during which the hedges would have otherwise expired. If we determine it probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.
All of our current derivative hedging instruments qualify for hedge accounting. However, during 2001 we had derivative contracts with Enron that initially qualified for hedge accounting, but their status changed when Enron filed bankruptcy, causing us to change our accounting treatment of this asset before the hedge expired. As these hedges no longer qualified for hedge accounting, we recognized a pre-tax write down of $24.4 million in the fourth quarter of 2001. As demonstrated by the prior year impact, these adjustments can be material to our financial statements and are unpredictable.
The preparation of financial statements requires us to make other estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and believe that the ultimate actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties and such risks and uncertainties could cause the actual results to differ materially from our estimates.
-42-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant. The standard is effective for us beginning January 1, 2003. Although we are still finalizing our evaluation of the impact of adopting SFAS No. 143, we currently believe that the adoption of this standard will result in an increase to property and equipment and to our accrual for site reclamation costs, and a charge to income as a cumulative effect adjustment from a change in accounting principle, net of tax. Historically, we have made an accrual each period for our future retirement obligations as a part of our DD&A calculation. The total amount accrued at December 31, 2002 was $6.8 million and is recorded in our Consolidated Balance Sheets as "Provision for site reclamation costs." We are still reviewing certain legal obligations and the estimated future periods in which these costs will be incurred, which information is necessary to calculate the present value of our future retirement obligations. We presently estimate our future retirement obligations, before any salvage value recoupment and before the obligations are discounted for the time value of money, at approximately $75 million. We estimate the net salvage value for the equipment associated with these asset retirement obligations to be approximately $40 million, which will be included in our future DD&A calculations.
In November 2002, FASB issued Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness by Others." FIN No. 45 requires that a guarantor must recognize, at the inception of the guarantee, a liability for the fair value of the obligation that it has undertaken in issuing a guarantee. FIN 45 also addresses the disclosure requirements that a guarantor must include in its financial statements for guarantees issued. The disclosure requirements of this interpretation are effective for financial statements ending after December 15, 2002. The initial recognition and measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We have made all relevant disclosures regarding our guarantees.
FORWARD-LOOKING INFORMATION
The statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not limited to, statements found in this Management's Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, acquisition plans and proposals and dispositions, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters, mark-to- market values, and competition. Such forward-looking statements generally are accompanied by words such as "plan," "estimate," "expect," "predict," "anticipate," "projected," "should," "assume," "believe" or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management's current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company's financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company's oil and natural gas, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital, general economic conditions, competition and government regulations, as well as the risks and uncertainties discussed in this annual report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company's other public reports, filings and public statements.
This Annual Report is not deemed to be "soliciting material" or to be "filed" with the Securities and Exchange Commission or subject to the liabilities of Section 18 of the Securities Act of 1934, except with respect to pages 2, 8-11, 14, 16-17, 19-20, 22-25 and 27-70, which are incorporated into the Company's Annual Report on Form 10-K.
-43-
 
Independent Auditors' Report
To the Stockholders of Denbury Resources Inc.
We have audited the consolidated balance sheets of Denbury Resources Inc. and subsidiaries (the "Company") as of December 31, 2002 and 2001 and the related consolidated statements of operations, stockholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly in all material respects, the financial position of Denbury Resources Inc. and subsidiaries as of December 31, 2002 and 2001 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas
March 3, 2003	

-44-

CONSOLIDATED BALANCE SHEETS

AMOUNTS IN THOUSANDS EXCEPT SHARE AMOUNTS                                          DECEMBER 31,
                                                                          ------------------------------
                                                                              2002             2001
                                                                          -------------   --------------
                                          ASSETS
CURRENT ASSETS
   Cash and cash equivalents...........................................   $      23,940   $       23,496
   Accrued production receivables......................................          34,458           23,411
   Related party accrued production receivable - Genesis...............           3,334                -
   Trade and other receivables, net of allowance of $207 and $233......          16,846           31,924
   Derivative assets...................................................               -           23,458
   Deferred tax asset..................................................          49,886              989
                                                                          -------------   --------------
           Total current assets   .....................................         128,464          103,278
                                                                          -------------   --------------
PROPERTY AND EQUIPMENT
   Oil and natural gas properties (using full cost accounting)
       Proved .........................................................       1,245,896        1,098,263
       Unevaluated.....................................................          45,736           44,521
   CO2 properties and equipment........................................          62,370           45,555
   Less accumulated depletion and depreciation.........................        (609,917)        (520,332)
                                                                          -------------   --------------
          Net property and equipment...................................         744,085          668,007
                                                                          -------------   --------------
INVESTMENT IN GENESIS..................................................           2,224                -
OTHER ASSETS...........................................................          20,519           18,703
                                                                          -------------   --------------
           TOTAL ASSETS................................................   $     895,292   $      789,988
                                                                          =============   ==============

                           LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
   Accounts payable and accrued liabilities............................   $      49,281   $       66,498
   Oil and gas production payable......................................          17,309           13,440
   Derivative liabilities..............................................          29,289                -
                                                                          -------------   --------------
           Total current liabilities...................................          95,879           79,938
                                                                          -------------   --------------
LONG-TERM LIABILITIES
   Long-term debt......................................................         344,889          334,769
   Provision for site reclamation costs................................           6,845            4,318
   Derivative liabilities..............................................           6,281                -
   Deferred tax liability..............................................          71,663           18,422
   Other...............................................................           2,938            3,373
                                                                          -------------   --------------
           Total long-term liabilities.................................         432,616          360,882
                                                                          -------------   --------------
COMMITMENTS AND CONTINGENCIES (NOTE 8)
STOCKHOLDERS' EQUITY
  Preferred stock, $.001 par value, 25,000,000 shares authorized; none
    issued and outstanding.............................................               -                -
  Common stock, $.001 par value, 100,000,000 shares authorized;
    53,539,329 and 52,956,825 shares issued and outstanding at
    December 31, 2002 and December 31, 2001, respectively..............              54               53
  Paid-in capital in excess of par.....................................         395,906          391,557
  Accumulated deficit..................................................          (9,875)         (56,670)
  Accumulated other comprehensive income (loss)........................         (19,288)          14,228
                                                                          -------------   --------------
           Total stockholders' equity..................................         366,797          349,168
                                                                          -------------   --------------
           TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................   $     895,292   $      789,988
                                                                          =============   ==============	

See Notes to Consolidated Financial Statements.
-45-
 
CONSOLIDATED STATEMENTS OF OPERATIONS

                                                                           YEAR ENDED DECEMBER 31,
                                                                 -------------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS                          2002           2001           2000
                                                                 -------------    -----------   ------------
REVENUES
     Oil, natural gas and related product sales
        Unrelated parties....................................... $     251,972    $   260,398   $    204,636
        Related party - Genesis.................................        22,922              -              -
     CO2 sales..................................................         7,580          5,210              -
     Gain (loss) on settlements of derivative contracts.........           932         18,654        (25,264)
     Interest income and other..................................         1,746            849          2,279
                                                                 -------------    -----------   ------------
    Total revenues..........................................           285,152        285,111        181,651
                                                                 -------------    -----------   ------------

EXPENSES
     Lease operating expenses...................................        71,188         55,049         38,676
     Production taxes and marketing expenses....................        11,902         10,963          8,051
     CO2 operating expenses.....................................         1,400            891              -
     General and administrative expenses........................        10,967          9,297          8,055
     Interest expense...........................................        26,833         22,335         15,255
     Depletion and depreciation.................................        94,236         71,345         36,214
     Franchise taxes............................................         1,459            877            467
     Loss on Enron related assets...............................             -         25,164              -
     Amortization of derivative contracts and other non-cash
      hedging adjustments.......................................        (3,093)         7,816              -
                                                                 -------------    -----------   ------------
        Total expenses..........................................       214,892        203,737        106,718
                                                                 -------------    -----------   ------------
Equity in net income of Genesis.................................            55              -              -
                                                                 -------------    -----------   ------------
Income before income taxes......................................        70,315         81,374         74,933

Income tax provision (benefit)
     Current income taxes.......................................          (406)           640            558
     Deferred income taxes......................................        23,926         24,184        (67,852)
                                                                 -------------    -----------   ------------

NET INCOME ..................................................... $      46,795    $    56,550   $    142,227
                                                                 =============    ===========   ============

NET INCOME PER COMMON SHARE
     Basic...................................................... $        0.88    $      1.15   $       3.10
     Diluted....................................................          0.86           1.12           3.07

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
     Basic......................................................        53,243         49,325         45,823
     Diluted....................................................        54,365         50,361         46,352	

See Notes to Consolidated Financial Statements.
-46-
 
CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                             YEAR ENDED DECEMBER 31,
                                                                     ----------------------------------------
AMOUNTS IN THOUSANDS                                                     2002         2001           2000
                                                                     ------------ -------------  ------------

CASH FLOW FROM OPERATING ACTIVITIES:
   Net income ....................................................   $     46,795 $      56,550  $    142,227
       Adjustments needed to reconcile to net cash flow provided
           by operations:
       Depletion and depreciation.................................         94,236        71,345        36,214
       Deferred income taxes......................................         23,926        24,184       (67,852)
       Non-cash loss on Enron related assets......................              -        25,164             -
       Amortization of derivative contracts and other non-cash
          hedging adjustments.....................................         (3,093)        7,816             -
       Amortization of debt issue costs and other.................          2,701         1,742           966

   Changes in assets and liabilities relating to operations:
       Accrued production receivable..............................        (14,381)       19,399       (21,691)
       Trade and other receivables................................         15,078       (17,622)       (2,797)
       Derivative assets and liabilities..........................          8,427       (28,043)            -
       Other assets...............................................            133           863        (5,109)
       Accounts payable and accrued liabilities...................        (17,217)       23,560         8,586
       Oil and gas production payable.............................          3,869        (2,213)        5,038
       Other liabilities..........................................           (874)        2,302           390
                                                                     ------------ -------------  ------------

NET CASH PROVIDED BY OPERATING ACTIVITIES.........................        159,600       185,047        95,972
                                                                     ------------ -------------  ------------

CASH FLOW USED FOR INVESTING ACTIVITIES:
   Oil and natural gas expenditures...............................        (99,273)     (170,109)      (73,736)
   Acquisitions of oil and gas properties.........................        (56,364)      (97,871)      (60,285)
   Investment in Genesis..........................................         (2,170)            -             -
   Acquisition of CO2 assets and capital expenditures.............        (16,445)      (45,555)            -
   Net purchases of other assets..................................         (3,688)       (1,799)       (1,629)
   Increase in restricted cash....................................           (909)       (3,496)         (322)
   Proceeds from sales of oil and gas properties..................          7,688             -         2,932
                                                                     ------------ -------------  ------------

NET CASH USED FOR INVESTING ACTIVITIES............................       (171,161)     (318,830)     (133,040)
                                                                     ------------ -------------  ------------

CASH FLOW FROM FINANCING ACTIVITIES:
   Bank repayments................................................        (40,000)      (79,130)      (14,500)
   Bank borrowings................................................         49,130       146,000        61,000
   Issuance of subordinated debt..................................              -        68,528             -
   Issuance of common stock.......................................          3,594         2,594         1,491
   Costs of debt financing........................................           (719)       (3,026)         (398)
   Other..........................................................              -            20             -
                                                                     ------------ -------------  ------------

NET CASH PROVIDED BY FINANCING ACTIVITIES.........................         12,005       134,986        47,593
                                                                     ------------ -------------  ------------

NET INCREASE IN CASH AND CASH EQUIVALENTS.........................            444         1,203        10,525

Cash and cash equivalents at beginning of year....................         23,496        22,293        11,768
                                                                     ------------ -------------  ------------

CASH AND CASH EQUIVALENTS AT END OF YEAR..........................   $     23,940 $      23,496  $     22,293
                                                                     ============ =============  ============	

See Notes to Consolidated Financial Statements.
-47-
 
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY

                                                                 PAID-IN     RETAINED    ACCUMULATED
                                                               CAPITAL IN    EARNINGS       OTHER          TOTAL
                                          COMMON STOCK          EXCESS OF (ACCUMULATED  COMPREHENSIVE  STOCKHOLDER'S   COMPREHENSIVE
                                       ($.001 PAR VALUE)           PAR       DEFICIT)   INCOME (LOSS)     EQUITY       INCOME (LOSS)
                                     ----------------------    ----------- ------------ -------------- -------------  --------------
DOLLAR AMOUNTS IN THOUSANDS             SHARES        AMOUNT
                                     -------------  --------
BALANCE - DECEMBER 31, 1999             45,718,486  $     46  $   327,829 $  (255,447)  $         -    $      72,428
                                     -------------  --------  ----------- --------- -   -----------    -------------
Issued pursuant to employee stock
  purchase plan......................      218,493         -        1,305           -             -            1,305
Issued pursuant to employee stock
  option plan........................       40,458         -          186           -             -              186
Issued pursuant to directors
  compensation plan..................        2,544         -           19           -             -               19
Net income and comprehensive income..            -         -            -     142,227             -          142,227  $     142,227
                                     -------------  --------  ----------- -----------   -----------    -------------  -------------

BALANCE - DECEMBER 31, 2000             45,979,981        46      329,339    (113,220)            -          216,165        142,227
                                     -------------  --------  ----------- -----------   -----------    -------------  =============

Issued pursuant to employee stock
  purchase plan......................      189,485         -        1,546           -             -            1,546
Issued pursuant to employee stock
  option plan........................      209,600         -        1,048           -             -            1,048
Issued pursuant to directors
  compensation plan..................        7,829         -           63           -             -               63
Issued in Matrix acquisition.........    6,569,930         7       59,188           -             -           59,195
Tax benefit from stock options.......            -         -          373           -             -              373
Net income...........................            -         -            -      56,550             -           56,550         56,550
Other comprehensive income (loss):
  Change in accounting principle for
    derivative contracts, net of tax
    of $594..........................            -         -            -           -         1,012            1,012          1,012
  Reclassification adjustments for
    derivative contracts, net of tax
    of $594..........................            -         -            -           -        (1,012)          (1,012)        (1,012)
  Change in fair value of derivative
    contracts, net of tax of $8,356..            -         -            -           -        14,228           14,228         14,228
                                     -------------  --------  ----------- -----------   -----------    -------------  -------------
BALANCE - DECEMBER 31, 2001             52,956,825        53      391,557     (56,670)       14,228          349,168         70,778
                                     -------------  --------  ----------- -----------   -----------    -------------  =============
Issued pursuant to employee stock
  purchase plan......................      203,893         -        1,928           -             -            1,928
Issued pursuant to employee stock
  option plan........................      370,120         1        1,665           -             -            1,666
Issued pursuant to directors
  compensation plan..................        8,491         -           82           -             -               82
Tax benefit from stock options.......            -         -          674           -             -              674
Net income...........................            -         -            -      46,795             -           46,795         46,795
Other comprehensive income (loss):
  Reclassification adjustments for
    derivative contracts, net of tax
    of $4,919........................            -         -            -           -        (7,838)          (7,838)        (7,838)
  Amortization of derivative contracts,
    net of tax of $3,598.............            -         -            -           -         6,066            6,066          6,066
  Change in fair value of derivative
    contracts, net of tax of $18,857.            -         -            -           -             -          (31,744)       (31,744)
                                     -------------  --------  ----------- -----------   -----------    -------------  -------------
BALANCE - DECEMBER 31, 2002             53,539,329  $     54  $   395,906 $    (9,875)  $   (19,288)   $     366,797  $      13,279
                                     =============  ========  =========== ===========   ===========    =============  =============	

See Notes to Consolidated Financial Statements.
-48-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
Denbury Resources Inc. is a Delaware corporation, organized under Delaware General Corporation Law, engaged in the acquisition, development, operation and exploration of oil and natural gas properties. Denbury has one primary business segment, which is the exploration, development and production of oil and natural gas in the U.S. Gulf Coast region. In 2001, we acquired carbon dioxide ("CO2" ) reserves that are used in our tertiary oil recovery operations. In addition, we sell some CO2 to third parties for industrial uses.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in accordance with generally accepted accounting principles ("GAAP") and include the accounts of Denbury and its subsidiaries, all of which are wholly owned. In 2002, one of our subsidiaries acquired the general partner of Genesis Energy, L.P. ("Genesis"), a public limited partnership. We account for our 2% interest in Genesis under the equity method. Even though we have significant influence over the limited partnership in our role as general partner, because our control is limited by the general partnership agreement we do not consolidate Genesis. See Note 2 for more information regarding the Genesis acquisition and summary financial information. All material intercompany balances and transactions have been eliminated.
Oil and Natural Gas Operations
A) CAPITALIZED COSTS. We follow the full-cost method of accounting for oil and natural gas properties. Under this method, all costs related to acquisitions, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells and general and administrative expenses directly related to exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.
B) DEPLETION AND DEPRECIATION. The costs capitalized, including production equipment, are depleted or depreciated on the unit-of- production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units based upon the relative energy content which is six thousand cubic feet of natural gas to one barrel of crude oil.
C) SITE RECLAMATION. Estimated future costs of well abandonment and site reclamation, including the removal of production facilities at the end of their useful life, are provided for on a unit-of-production basis. Costs are based on engineering estimates of the anticipated method and extent of site restoration, valued at year-end prices, net of estimated salvage value, and in accordance with the current legislation and industry practice. The annual provision for future site reclamation costs is included in depletion and depreciation expense and reported under long-term liabilities in the Consolidated Balance Sheets as "Provision for site reclamation costs."
D) CEILING TEST. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (i) the present value of estimated future net revenues from proved reserves (discounted at 10%), based on unescalated period-end oil and natural gas prices; (ii) plus the cost of properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; (iv) less related income tax effects. The cost center ceiling test is prepared quarterly.
E) JOINT INTEREST OPERATIONS. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only Denbury's proportionate interest in such activities and any amounts due from other partners are included in trade receivables.
F) PROVED RESERVES. See Note 10 for information on our proved oil and natural gas reserves and the basis on which they are recorded.
-49-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts due from purchasers of oil and natural gas are included in accrued production receivables.
We follow the "sales method" of accounting for our oil and natural gas revenue, whereby we recognize sales revenue on all oil or natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2002 and 2001, our aggregate oil and natural gas imbalances were not material to our consolidated financial statements.
We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements. We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until either the closing or purchase agreement date, depending on the underlying terms and agreements.
Derivative Instruments and Hedging Activities
We enter into derivative contracts to mitigate our exposure to commodity price risk associated with future oil and natural gas production. These contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps. On January 1, 2001, we adopted Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. Upon adoption of SFAS No. 133, we recorded a $1.6 million increase in our derivative assets to reflect the fair value of our derivative instruments in place at that time and a corresponding increase to accumulated other comprehensive income of approximately $1.0 million, net of tax, in the transition adjustment. This transition adjustment was reclassified out of accumulated other comprehensive income to earnings over the remainder of 2001.
SFAS No. 133 requires that every derivative instrument be recorded on the balance sheet as either an asset or a liability measured at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the change in fair value of the derivative is recognized either currently in earnings or deferred in other comprehensive income (equity) depending on the type of hedge and to what extent the hedge is effective. All of our current derivative hedging instruments are cash flow hedges.
In order to qualify for hedge accounting the relationship between the hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis. We measure hedge effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedging instrument becomes ineffective. We assess hedge effectiveness based on total changes in the fair value of options used in cash flow hedges rather than changes of intrinsic value only. As a result, changes in the entire fair value of option contracts are deferred in accumulated other comprehensive income, to the extent they are effective, until the hedged transaction is completed. If a hedge becomes ineffective, any deferred gains or losses on the cash flow hedge remain in accumulated other comprehensive income until the underlying production related to the derivative hedge has been delivered. If it is determined probable that a hedged forecasted transaction will not occur, and the hedge is not redesignated, deferred gains or losses on the hedging instrument are recognized in earnings immediately.
Receipts and payments resulting from settlements of derivative hedging instruments are recorded in "Gain (loss) on settlements of derivative contracts" included in revenues in the Consolidated Statements of Operations. We apply Derivative Implementation Group Issue G20 in accounting for our net purchased puts and collars, which allows the amortization of the cost of net purchased options over the period of the hedge. We record this amortization and any gains or losses resulting from hedge ineffectiveness in "Amortization of derivative contracts and other non-cash hedging adjustments" under expenses in the Consolidated Statements of Operations. Denbury's hedging activities are further discussed in Note 7.
Comprehensive Income (Loss)
Our comprehensive income (loss) information is included in our Consolidated Statements of Stockholders' Equity. All of our adjustments to other comprehensive income and the balances in accumulated other comprehensive income
(loss) at December 31, 2002 and 2001 relate to our derivative hedging contracts which are discussed in Note 7.
-50-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk
Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents and trade and accrued production receivables in addition to the derivative hedging instruments discussed above. Our cash equivalents represent high-quality securities placed with various investment grade institutions. This investment practice limits our exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. Also, most of our significant purchasers are large companies with excellent credit ratings. If customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our derivative hedging contracts through formal credit policies, monitoring procedures and diversification.
CO2 Operations
We own and produce CO2 reserves that are used for our own tertiary oil recovery operations and, in addition, we sell a portion to third party industrial users. We record revenue from our sales of CO2 to third parties when it is produced and sold. CO2 used for our own tertiary oil recovery operations is not recorded as revenue in the Consolidated Statements of Operations. Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes used for our own use. The expenses related to third party sales are recorded in "CO2 operating costs" and the expenses related to our own uses are recorded in "Lease operating costs" in the Consolidated Statements of Operations. We capitalize acquisitions and the costs of exploring and developing CO2 reserves. The costs capitalized are depleted or depreciated on the unit-of-production method, based on proved CO2 reserves as determined by independent engineers.
Cash Equivalents
We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase.
Restricted Cash
At December 31, 2002 and 2001, we had approximately $8.7 million and $7.8 million, respectively, of restricted cash held in escrow for future site reclamation costs. This restricted cash is included in "Other Assets" in the Consolidated Balance Sheets.
Net Income Per Common Share
Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants and any other outstanding convertible securities.
For each of the three years in the period ended December 31, 2002, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share. The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share computations:

                                                             YEAR ENDED DECEMBER 31,
                                                  ---------------------------------------------
AMOUNTS IN THOUSANDS                                    2002            2001            2000
                                                  -------------   -------------   -------------

Weighted average common shares - basic..........         53,243          49,325          45,823

Effect of diluted securities:
         Stock options..........................          1,122           1,036             529
                                                  -------------   -------------   -------------
Weighted average common shares - diluted                 54,365          50,361          46,352
                                                  =============   =============   =============	

We did not include in the diluted shares outstanding calculation 1.7 million options in 2002, 1.8 million options in 2001 and 1.6 million options in 2000 because their inclusion would be antidilutive as their exercise prices exceeded the average market price of our common stock during the respective periods.
-51-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Options
We issue stock options to all of our employees under our stock option plan which is described more fully in Note 6. We account for our stock option plan utilizing the recognition and measurement principles of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees," and its related interpretations. Under these principles, no stock-based employee compensation expense is reflected in net income as long as the stock options have an exercise price equal to the underlying common stock on the date of grant. The following table illustrates the effect on net income and net income per common share if we had applied the fair value provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," in accounting for our stock option plan.

                                                                                YEAR ENDED DECEMBER 31,
                                                                       -----------------------------------------
                                                                           2002          2001           2000
                                                                       ------------   -----------   ------------
NET INCOME: (THOUSANDS)
   Net Income, as reported ............................................$     46,795   $    56,550   $    142,227
       Less: stock-based compensation expense applying fair value
            based method, net of related tax effects..................        2,866         2,763          2,401
                                                                       ------------   -----------   ------------
       Pro forma net income............................................$     43,929   $    53,787   $    139,826
                                                                       ============   ===========   ============
NET INCOME PER COMMON SHARE:
   As reported:
           Basic.......................................................$       0.88   $      1.15   $       3.10
           Diluted.....................................................        0.86          1.12           3.07
   Pro forma:
           Basic.......................................................$       0.83   $      1.09   $       3.05
           Diluted.....................................................        0.83          1.09           3.05	

The fair value of each option grant was estimated with the Black-Scholes option pricing model using the following weighted average assumptions:

                                            2002          2001           2000
                                        ------------  ------------    ----------
Risk-free interest rate.................       4.05%         4.64%          6.5%
Expected life..........................      5 years       5 years       5 years
Expected volatility.....................       61.4%         63.4%         55.0%
Dividend yield..........................           -             -             -	

Income Taxes
Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include the fair value of financial derivative instruments and the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and the related present value of estimated future net cash flows therefrom.
-52-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reclassifications
Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.
Recently Issued Accounting Pronouncements
SFAS No. 143, "Accounting for Asset Retirement Obligations," requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant. The standard is effective for us beginning January 1, 2003. Although we are still finalizing our evaluation of the impact of adopting SFAS No. 143, we currently believe that the adoption of this standard will result in an increase to property and equipment and to our accrual for site reclamation costs, and a charge to income as a cumulative effect adjustment from a change in accounting principle, net of tax. Historically, we have made an accrual each period for our future retirement obligations as a part of our DD&A calculation. The total amount accrued at December 31, 2002 was $6.8 million and is recorded in our Consolidated Balance Sheets as "Provision for site reclamation costs." We are still reviewing certain legal obligations and the estimated future periods in which these costs will be incurred, which information is necessary to calculate the present value of our future retirement obligations. We presently estimate our future retirement obligations, before any salvage value recoupment and before the obligations are discounted for the time value of money, at approximately $75 million. We estimate the net salvage value for the equipment associated with these asset retirement obligations to be approximately $40 million, which will be used in our future DD&A calculations.
In November 2002, FASB issued Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness by Others." FIN No. 45 requires that a guarantor must recognize, at the inception of the guarantee, a liability for the fair value of the obligation that it has undertaken in issuing a gurantee. FIN 45 also addresses the disclosure requirements that a guarantor must include in its financial statements for guarantees issued. The disclosure requirements of this interpretation are effective for financial statements ending after December 15, 2002. The initial recognition and measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We have made all relevant disclosures regarding our guarantees.
NOTE 2. ACQUISITIONS
COHO Gulf Coast Properties
In August 2002, we acquired COHO Energy, Inc's Gulf Coast properties auctioned in the U.S. Bankruptcy Court in Dallas, Texas. Our net purchase price, adjusted for interim cash flow from the June 1, 2002 effective date, together with purchase adjustments through December 31, 2002, was $48.2 million and included nine fields, eight of which are located in Mississippi and one in Texas. We operate all but one of the smaller Mississippi fields. At December 31, 2002, these properties had proved reserves of approximately 15.1 million barrels of oil equivalent with net production of approximately 4,000 barrels of oil per day. The Mississippi fields include interests in the Brookhaven, Laurel, Martinville, Soso and Summerland Fields, with such interests representing operational control with working interests in excess of 90%, plus interests in the smaller Bentonia, Cranfield and Glazier fields. We have hedged nearly 100% of the forecasted proved developed production relating to this acquisition through the end of 2004 with no-cost oil swaps (i.e., forward sales). The average fixed price of these swaps for 2003 is $24.27 per barrel and for 2004 is $22.94 per barrel.
Subsequent to December 31, 2002, we have sold or have reached an agreement to sell certain of these fields, which is further discussed in Note 12.
Genesis Energy, L.L.C.
On May 14, 2002, a newly-formed subsidiary of Denbury acquired Genesis Energy, L.L.C. (which was converted to Genesis Energy, Inc.), the general partner of Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership, for total consideration, including expenses and commissions, of approximately $2.2 million. The general partner owns a 2% interest in the limited partnership. Genesis is engaged in two primary lines of business: crude oil gathering and marketing and pipeline transportation, primarily in Mississippi, Texas, Alabama and Florida.
-53-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We are accounting for our 2% ownership in Genesis under the equity method as we have significant influence over the limited partnership; however, our control is limited under the general partnership agreement and therefore we do not consolidate Genesis. Our equity in Genesis' net income for 2002 was $55,000, representing 2% of Genesis' net income for the period from May 14, 2002 through December 31, 2002. Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which was $5.5 million as of December 31, 2002, and also included $26.3 million in letters of credit of which $3.2 million are for Denbury's benefit to secure purchases from Denbury. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. Our investment of $2.2 million exceeded our percentage of net equity in the limited partnership at the time of acquisition by approximately $1.0 million, which represents goodwill and is not subject to amortization.
Genesis has historically been a purchaser of our crude oil and we anticipate future purchases of our crude oil production by Genesis. For the year ended December 31, 2002, we recorded sales to Genesis of $30.0 million and at December 31, 2002, had a production receivable from Genesis of $3.3 million. Our sales to Genesis from the period May 14, 2002 through December 31, 2002 were $22.9 million and are shown separately as related party sales in our Consolidated Statements of Operations.
Summarized financial information of Genesis Energy, L.P. is as follows (amounts in thousands):

                                            Year Ended
                                           December 31,
                                                2002
                                        -------------------
Revenues...........................     $           911,806
Cost of sales......................                 888,691
Other expenses.....................                  18,023
                                        -------------------
   Net income .....................     $             5,092
                                        ===================

                                           December 31,
                                                2002
                                        -------------------
Current assets.....................     $            92,830
Non-current assets.................                  44,707
                                        -------------------
   Total assets....................     $           137,537
                                        ===================

Current liabilities................     $            96,220
Non-current liabilities............                   5,500
Partners' capital..................                  35,817
                                        -------------------
   Total liabilities and
     partners' capital.............     $           137,537
                                        ===================	

Other 2002 Acquisitions
We completed other minor acquisitions in 2002 for approximately $12.4 million. These acquisitions consisted of an additional CO2 well and reserves for $4.3 million, McComb Field, a new tertiary oil recovery field, for $2.3 million, and other minor acquisitions.
Matrix Oil and Gas, Inc.
On July 10, 2001, we completed the acquisition of Matrix Oil & Gas, Inc.("Matrix"), an independent oil and gas company based in Covington, Louisiana. Under the merger agreement, we paid a total of approximately $157.4 million, comprised of $98.2 million (62%) in cash and $59.2 million (38%) in the form of 6.6 million shares of Denbury's common stock, including post-closing adjustments. The purchase price was allocated to the net assets acquired based on estimated fair market values at the date of acquisition, with the predominant amount allocated to oil and gas properties. As part of our purchase price allocations, we recorded a deferred income tax liability of $53.1 million to reflect the difference between the book and carryover tax basis of the properties acquired, and we allocated $30.0 million of the purchase price to unevaluated property to reflect the significant probable and possible reserves that were identified in the acquisition. Based on subsequent drilling activity and our ongoing evaluation of the undeveloped prospects, we have reclassified $6.0 million of the original $30.0 million to developed property as of December 31, 2002. Denbury's financial statements include the operations of Matrix from July 1, 2001.
-54-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following pro forma information reflects the consolidated financial results of operations for the years ended December 31, 2001 and 2000, based upon adjustments to the historical financial statements of Denbury and the historical financial statements of Matrix as if the acquisition had occurred at the beginning of such periods presented. The effects of other acquisitions in 2002 and 2001 were not significant for inclusion in the pro forma presentation. Pro forma amounts are not necessarily indicative of what the actual results would have been.

                                                                      YEAR ENDED DECEMBER 31,
                                                            ---------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS                           2001                2000
                                                             ------------------  ------------------
Revenues...................................................     $    324,401  $      $   214,473
Expenses...................................................          234,097             147,409
Net income.................................................           62,243             137,387
Income per common share:
   Basic...................................................     $       1.18         $      2.62
   Diluted.................................................             1.16                2.60	

CO2 Acquisition
On February 2, 2001, we purchased certain CO2 reserves, production and associated assets from a division of Airgas, Inc., for $42.0 million. The acquisition included ten producing CO2 wells and production facilities located near Jackson, Mississippi, and a 183-mile, 20-inch pipeline that is currently transporting CO2 to our tertiary oil recovery operations at Little Creek and Mallalieu Fields, as well as to other commercial customers.
Other 2001 Acquisitions
During 2001 we completed other minor acquisitions totaling approximately $5.0 million.
2000 Acquisitions
During the fourth quarter of 2000, Denbury completed acquisitions totaling $56.5 million in the Thornwell, Porte Barre and Iberia Fields located in southwestern Louisiana. Approximately $10.0 million of these acquisition costs were initially recorded as unevaluated property costs at December 31, 2000. The Company also completed other minor acquisitions totaling $3.8 million during 2000.
NOTE 3. PROPERTY AND EQUIPMENT

                                                                           DECEMBER 31,
                                                          ----------------------------------------------
AMOUNTS IN THOUSANDS                                                  2002                     2001
                                                          ---------------------     --------------------
Oil and natural gas properties
   Proved properties.................................    $           1,245,896     $          1,098,263
   Unevaluated properties............................                   45,736                   44,521
                                                          ---------------------     --------------------
       Total..........................................               1,291,632                1,142,784
Accumulated depletion and depreciation................                (606,488)                (518,760)
                                                          ---------------------     --------------------
   Net oil and natural gas properties.................                 685,144                  624,024
                                                          ---------------------     --------------------
CO2 properties........................................                  62,370                   45,555
Accumulated depletion and depreciation................                  (3,429)                  (1,572)
                                                          ---------------------     --------------------
   Net CO2 properties.................................                   58,941                   43,983
                                                          ---------------------     --------------------
Net property and equipment............................    $             744,085     $            668,007
                                                          =====================     ====================	

Unevaluated Oil and Natural Gas Properties Excluded From Depletion
Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties excluded from oil and
-55-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
natural gas properties being amortized at December 31, 2002 and 2001 and the year in which they were incurred follows:

                                            DECEMBER 31, 2002                                 DECEMBER 31, 2001
                            --------------------------------------------------   --------------------------------------------
                            Costs Incurred During:                               Costs Incurred During:
                            -------------------------------------                -----------------------------
                                   2002        2001         2000        Total            2001           2000          Total
                            ------------ ----------- ------------ ------------   --------------  ------------- --------------
AMOUNTS IN THOUSANDS
Property acquisition costs .$     12,459 $    22,128 $        228 $     34,815   $       34,195  $       3,688 $       37,883
Exploration costs...........       7,526       2,938          457       10,921            5,395          1,243          6,638
                            ------------ ----------- ------------ ------------   --------------  ------------- --------------
    Total...................$     19,985 $    25,066 $        685 $     45,736   $       39,590  $       4,931 $       44,521
                            ============ =========== ============ ============   ==============  ============= ==============	

Costs are transferred into the amortization base on an ongoing basis as the projects are evaluated and proved reserves established or impairment determined. Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate. As of December 31, 2002, approximately $24.0 million of the total unevaluated property balance of $45.7 million related to the Matrix acquisition. These costs will be transferred into the amortization base as the undeveloped areas are tested. We anticipate that the majority of this activity should be completed over the next three to five years.
NOTE 4. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS

                                                                          DECEMBER 31,
                                                                  ----------------------------
                                                                      2002           2001
                                                                  ------------   -------------
AMOUNTS IN THOUSANDS
Senior bank loan..................................................$    150,000   $     140,870
9% Senior Subordinated Notes due 2008.............................     125,000         125,000
9% Series B Senior Subordinated Notes due 2008....................      75,000          75,000
Discount on 9% Series B Subordinated Notes due 2008...............      (5,111)         (6,101)
                                                                  ------------   -------------
     Total long-term debt.........................................$    344,889   $     334,769
                                                                  ============   =============	

Senior Bank Loan
In September 2002, we entered into a Third Amended and Restated Credit Agreement with our banks which extended the maturity of our bank credit facility from December 2003 to April 2006. In conjunction with the amended credit agreement, Bank One became the new administrative agent bank. The facility borrowing base remained at $220 million, leaving a borrowing capacity of approximately $70 million as of December 31, 2002, and there were no other significant changes as part of the amendment.
The credit facility is secured by substantially all of our producing oil and natural gas properties and contains several restrictions including, among others: (i) a prohibition on the payment of dividends, (ii) a requirement for a minimum equity balance, (iii) a requirement to maintain positive working capital, as defined, (iv) a minimum interest coverage test and (v) a prohibition of most debt and corporate guarantees. We were in compliance with all of our bank covenants as of December 31, 2002. Our bank credit facility provides for a semi- annual redetermination of the borrowing base on April 1 and October 1. At the April 2001 redetermination, our borrowing base was increased from $150 million to $200 million and was further increased at the October 2001 redetermination to $220 million. It has not changed since that time.
As of December 31, 2002, we had $150.0 million outstanding under the facility, at a weighted average interest rate of 3.2%, $370,000 of letters of credit outstanding and a borrowing base of $220 million. The next scheduled redetermination of the borrowing base will be as of April 1, 2003, based on December 31, 2002 assets and proved reserves.
Subordinated Debt
On February 26, 1998, Denbury Management Inc. ("DMI"), a wholly owned subsidiary of Denbury at that time, issued $125 million in aggregate principal amount of 9% Senior Subordinated Notes due 2008 which require only semi-annual interest payments until maturity. In April 1999, DMI was merged into Denbury Resources Inc., which expressly assumed all liabilities of DMI, including the 9% Senior Subordinated Notes. These notes contain certain debt covenants, including covenants that limit (i) indebtedness, (ii) certain restricted payments including dividends, (iii) sale/leaseback transactions, (iv) transactions with affiliates, (v) liens, (vi) asset sales and (vii) mergers and consolidations. We received net proceeds from the debt offering of approximately $121.8 million before offering expenses.
-56-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During August 2001, Denbury issued an additional $75 million of subordinated debt in a private placement at 91.371% of face amount for an effective yield of 10.875%. The notes were issued under a separate indenture, but on terms substantially identical to the existing 9% Senior Subordinated Notes due 2008. The net proceeds to us were approximately $65.9 million. These notes were subsequently exchanged for a like principal amount of publicly registered notes.
Interest payments on our $200.0 million of subordinated debt are payable on March 1 and September 1. Our subordinated debt is callable at our option beginning March 1, 2003 at the following redemption prices: 104.5% on March 1, 2003, 103.0% on March 1, 2004, 101.5% on March 1, 2005 and 100% on March 1, 2006 and thereafter. There are no sinking fund requirements for our subordinated debt.
On March 17, 2003, we announced a refinancing of our $200 million of 9% Senior Subordinated Notes (see Note 12).
Indebtedness Repayment Schedule
Our indebtedness as of December 31, 2002 is repayable as follows:

AMOUNTS IN THOUSANDS
-------------------------------------------------------
YEAR
2003.......................................$          -
2004.......................................           -
2005.......................................           -
2006.......................................     150,000
2007.......................................           -
Thereafter (2008)..........................     200,000
                                           ------------
       Total indebtedness..................$    350,000
                                           ============	

NOTE 5. INCOME TAXES
Our income tax provision (benefit) is as follows:

                                                                YEAR ENDED DECEMBER 31,
                                                        ---------------------------------------
AMOUNTS IN THOUSANDS                                         2002          2001          2000
                                                        -----------   -----------   -----------
Current income tax expense (benefit)
    Federal.............................................$      (419)  $       614   $       558
    State...............................................         13            26             -
                                                        -----------   -----------   -----------
         Total current income tax expense (benefit).....       (406)          640           558
                                                        -----------   -----------   -----------
Deferred income tax expense (benefit)
    Federal.............................................     23,926        24,184       (67,852)
    State...............................................          -             -             -
                                                        -----------   -----------   -----------
       Total deferred income tax expense (benefit)......     23,926        24,184       (67,852)
                                                        -----------   -----------   -----------
             Total income tax expense (benefit).........$    23,520   $    24,824   $   (67,294)
                                                        ===========   ===========   ===========	

Our income tax benefit for 2000 was primarily the result of the elimination of the valuation allowance on our net deferred tax assets as of December 31, 2000. This valuation allowance was initially recorded at December 31, 1998 and remained fully reserved at December 31, 1999, based upon management's belief that it was more likely than not that we would not be able to generate sufficient taxable income to realize the benefit of our net deferred tax assets. In reaching this conclusion, management considered both historical results and its expectations regarding future taxable income based on oil and gas pricing consistent with our long-term forecasting and anticipated levels of capital spending. As a result of the near-term recovery of oil and natural gas prices that began in the latter part of 1999 and continued throughout 2000, we were able to generate net income for 2000 and taxable income that utilized approximately $27.2 million of our net operating losses. Based on expectations at that time regarding the future and our expectations regarding future taxable income and our ability to realize the benefit of our deferred tax asset, we concluded that the valuation allowance on our net deferred tax assets was no longer necessary and at December 31, 2000 eliminated the entire valuation allowance.
-57-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our current income tax expense in 2001 and 2000 was for alternative minimum taxes that could not be offset by our alternative minimum tax net operating losses and conversely, our current income tax benefit in 2002 is primarily related to tax law changes in 2002 that allowed us to receive a refund of our alternative minimum taxes paid for 2001.
At December 31, 2002, we had net operating loss carryforwards for U.S. federal income tax purposes of $84.9 million and $4.2 million for alternative minimum tax purposes. During 2002 and 2001, we utilized approximately $16 million and $23 million, respectively, of regular and alternative minimum net operating losses to minimize our current tax position. As a result of the acquisition of Matrix and other prior ownership changes, the utilization of some of our net operating loss carryforwards is subject to limitations imposed by the Internal Revenue Code of 1986. However, we do not expect such limitations to have an effect on our ability to use these net operating loss carryforwards. Our net operating loss carryforwards are scheduled to expire as follows:

                                            INCOME        ALTERNATIVE
AMOUNTS IN THOUSANDS                          TAX         MINIMUM TAX
-----------------------------------------------------   ---------------
  YEAR
  2018   .................................  $  61,882       $        -
  2019   .................................     21,080             3,853
  2020   .................................        826               193
  2021   .................................      1,073               127
  2022   .................................         30                30	

In 2001, we began to recognize a benefit for the amount of enhanced oil recovery credits earned from our tertiary recovery projects. The total credits earned to date is approximately $9.9 million. These credits begin to expire in 2020.
Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the December 31, 2002 and 2001 balance sheet dates. At December 31, 2002 and 2001, our deferred tax assets and liabilities were as follows:

                                                                 DECEMBER 31,
                                                          ---------------------------
AMOUNTS IN THOUSANDS                                          2002           2001
                                                          ------------   ------------
Deferred tax assets:
     Loss carryforwards................................   $     32,266   $     37,222
     Tax credit carryover..............................          1,069          1,403
     Enhanced oil recovery credit carryforwards........          9,927          5,280
     Derivative hedging contracts......................         11,822              -
     Other.............................................             79              -
                                                          ------------   ------------
       Total deferred tax assets.......................         55,163         43,905
                                                          ------------   ------------
Deferred tax liabilities:
     Property and equipment............................        (76,940)       (52,449)
     Derivative hedging contracts......................              -         (8,356)
     Other.............................................              -           (533)
                                                          ------------   ------------
       Total deferred tax liabilities..................        (76,940)       (61,338)
                                                          ------------   ------------
       Total net deferred tax liability................   $    (21,777)  $    (17,433)
                                                          ============   ============	

Our income tax provision (benefit) varies from the amount that would result from applying the federal statutory income tax rate to income before income taxes as follows:

                                                                   YEAR ENDED DECEMBER 31,
                                                          -----------------------------------------
AMOUNTS IN THOUSANDS                                          2002          2001          2000
                                                          ------------  ------------  -------------

Income tax provision calculated using the
   federal statutory income tax rate..................... $     24,587  $     28,481  $      26,227
State income taxes and other.............................        2,327         1,623          1,616
Change in valuation allowance............................            -             -        (95,137)
Enhanced oil recovery credits............................       (3,394)       (5,280)             -
                                                          ------------  ------------  -------------
    Total income tax expense (benefit)................... $     23,520  $     24,824  $     (67,294)
                                                          ============  ============  =============	

-58-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6. STOCKHOLDERS' EQUITY
Authorized
We are authorized to issue 100 million shares of common stock, par value $.001 per share, and 25 million shares of preferred stock, par value $.001 per share. The preferred shares may be issued in one or more series with rights and conditions determined by the board of directors.
Stock Option Plan
As of December 31, 2002, we had a total of 7,345,587 shares of common stock authorized for issuance pursuant to our Stock Option Plan, of which 1,117,347 shares were available for issuance. Denbury's board of directors has authorized an additional 850,000 shares for this plan, subject to the approval of shareholders at the May 20, 2003 annual meeting. Under the terms of the plan, incentive and non-qualified options may be issued to officers, key employees and consultants. Options generally become exercisable over a four-year vesting period with the specific terms of vesting determined by the board of directors at the time of grant. The options expire over terms not to exceed ten years from the date of grant, 90 days after termination of employment or permanent disability or one year after the death of the optionee. The options are granted at the fair market value at the time of grant, which is generally defined as the average closing price of our common stock for the ten trading days prior to issuance. The plan is administered by the Stock Option Committee of Denbury's board of directors.
The following is a summary of our stock option activity:

                                                                   YEAR ENDED DECEMBER 31,
                                    ------------------------------------------------------------------------------------
                                               2002                         2001                        2000
                                    --------------------------  ---------------------------- ---------------------------
                                      Number       Weighted        Number       Weighted        Number       Weighted
                                    of Options  Average Price    of Options   Average Price   of Options  Average Price
                                    ----------- --------------  ------------ --------------- ------------ --------------
OUTSTANDING AT BEGINNING OF YEAR...   4,616,333 $     8.40       3,802,122   $        8.03    3,317,384   $      8.66
Granted............................     921,341       7.50       1,222,141            9.00      595,635          4.11
Exercised..........................    (370,120)      4.51        (209,600)           5.00      (40,458)         4.60
Forfeited..........................    (170,079)     10.30        (198,330)           8.53      (70,439)         6.70
                                    ----------- --------------  ------------ --------------- ------------ --------------
OUTSTANDING AT END OF YEAR.........   4,997,475 $     8.46       4,616,333   $        8.40    3,802,122   $      8.03
                                    =========== ==============  ============ =============== ============ ==============
Exercisable at end of year.........   2,267,497 $    10.26       1,858,072   $        9.49    1,310,382   $      9.35
                                    =========== ==============  ============ =============== ============ ==============
Weighted average fair value of
   options granted.................             $     4.17                   $        5.19                $      2.26
                                                ==============               ===============              ==============	

The following is a summary of stock options outstanding at December 31, 2002:

                                              Options Outstanding                       Options Exercisable
                                 ---------------------------------------------     -----------------------------
                                                    Weighted
                                       Number        Average                            Number
                                     of Options     Remaining       Weighted          of Options      Weighted
                                   Outstanding at  Contractual       Average        Exercisable at     Average
   Range of Exercise Prices           12/31/02        Life       Exercise Price       12/31/02     Exercise Price
------------------------------   --------------- --------------  -------------     --------------  -------------

             $ 3.77 - $ 5.50         1,549,501      6.3        $        4.16            694,420  $        4.24
               5.51 -   8.00         1,053,500      7.7                 7.00            238,859           6.75
               8.01 -  11.50         1,393,734      7.8                 9.24            333,478           9.46
              11.51 -  14.50           566,738      3.9                13.38            566,738          13.38
              14.51 -  22.25           434,002      4.8                18.38            434,002          18.38
             ---------------     -------------------------------------------------------------------------------
             $13.77 - $22.25         4,997,475      6.6        $        8.46          2,267,497  $       10.26
             ---------------     -------------------------------------------------------------------------------	

Stock Purchase Plan
We have a Stock Purchase Plan that is authorized to issue up to 1,750,000 shares of common stock to all full-time employees. As of December 31, 2002, there are 593,272 authorized shares remaining to be issued under the plan. In accordance with the plan, employees may contribute up to 10% of their base salary and Denbury matches 75% of their contribution. The combined funds are used to purchase previously unissued Denbury common stock at its current market value at the end of each quarter. We recognize compensation expense for the 75% company matching portion, which totaled $822,000, $666,000 and $560,000 for
-59-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the years ended December 31, 2002, 2001 and 2000, respectively. This plan is administered by the Stock Purchase Plan Committee of Denbury's board of directors.
401(k) Plan
Denbury offers a 401(k) Plan to which employees may contribute tax deferred earnings subject to Internal Revenue Service limitations. Up to 3% of an employee's compensation, as defined by the plan, is matched by Denbury at 100% and an employee's contribution between 3% and 6% of compensation is matched by Denbury at 50%. Denbury's match is vested immediately. During 2002, 2001 and 2000, Denbury's matching contributions were $884,000, $670,000 and $427,000, respectively, to the 401(k) Plan.
NOTE 7. DERIVATIVE HEDGING CONTRACTS
We enter into various financial contracts to hedge our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have historically consisted of price floors, collars and fixed price swaps. We generally attempt to hedge between 50% and 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt. When we make an acquisition, we attempt to hedge a large percentage, up to 100%, of the forecasted production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. Our recent hedging activity has been predominately with collars, although for the recent COHO acquisition, we also used swaps in order to lock in the prices used in our economic forecasts. All of the mark-to-market valuations used for our financial derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification.
The following is a summary of the net gain (loss) representing cash receipts and payments on our hedge settlements:

                                           Year Ended December 31,
                          ---------------------------------------------------------
                                2002                2001                2000
                          -----------------   -----------------   -----------------
Oil hedge contracts       $            (598)   $          1,925   $         (13,332)
Gas hedge contracts                   1,530              16,729             (11,932)
                          -----------------   -----------------   -----------------
     Net gain (loss)      $             932   $          18,654   $         (25,264)
                          =================   =================   =================	

Some of our derivative contracts require us to pay a premium which we amortize over the contract periods. This expense is included in "Amortization of derivative contracts and other non-cash hedging adjustments" in our Consolidated Statements of Operations. For the years ended December 31, 2002 and 2001, we recorded premium amortization expense of $9.7 million and $5.3 million, respectively. Also, for the year ended December 31, 2002, we reclassified $13.4 million related to our former Enron hedges (discussed below) out of accumulated other comprehensive income into income and recorded hedge ineffectiveness of $600,000 which is also included in "Amortization of derivative contracts and other non-cash hedging adjustments."
Loss on Enron Hedges
In conjunction with the acquisition of Matrix in July 2001, we purchased commodity hedges to protect our investment. These hedges, in the form of price floors, covered nearly all of the forecasted production from the acquired properties through the end of 2003 at floor prices ranging from $3.75 to $4.25 per MMBtu. Due to the falling natural gas prices in the latter half of 2001, we collected approximately $12.7 million on these hedges. The price floors relating to 2002 and 2003 were purchased from Enron Corporation, which filed bankruptcy in December 2001. We sold our bankruptcy claim against Enron in February 2002 for net proceeds of approximately $9.2 million. In total, we collected approximately $21.9 million from the price floors relating to the Matrix acquisition, resulting in a net cash gain of approximately $3.9 million over the cost of the floors. Because of the rise in natural gas prices since December 2001, based on the futures prices as of March 1, 2003, we would not have collected anything on the price floors relating to 2003 even if Enron had not filed bankruptcy as the current market price is above $3.75 (the floor price for 2003). We estimate that our total cash loss due to Enron's bankruptcy was approximately $5.4 million, representing the difference between what we would have collected during 2002 and the $9.2 million that we obtained from selling the bankruptcy claim.
-60-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
When Enron filed for bankruptcy during the fourth quarter of 2001, our Enron hedges ceased to qualify for hedge accounting treatment, which changed the accounting treatment for those hedges as of that point in time as required by SFAS No. 133. The result is that any future changes in the current market value of these assets must be reflected in the income statement and any remaining accumulated other comprehensive income at the time of the accounting change must be recognized over the original expected life of the hedges. To adjust the value of the Enron hedges down to the market value at December 31, 2001, which was determined to be the amount that we received from the sale of our claims in February 2002, we recorded a pre-tax write down of $24.4 million in the fourth quarter of 2001. We also had a claim against Enron for production receivables relating to November 2001 natural gas production that was also sold in February 2002, which resulted in an overall total pre-tax loss on our Enron related assets of $25.2 million. The after-tax balance in accumulated other comprehensive income related to these Enron hedges was approximately $11.6 million at the point they no longer qualified for hedge accounting. Accordingly, we recognized pre-tax income attributable to the Enron hedges during 2002 of approximately $13.4 million and will recognize pre-tax income during 2003 of approximately $5.1 million. The three year total pre-tax net loss on the Enron hedges will be approximately $5.9 million, which approximates the difference between the amount collected and paid for the Enron portion of the Matrix price floors.
Hedging Contracts at December 31, 2002

CRUDE OIL CONTRACTS:
-------------------
                                                                     NYMEX Contract Prices Per Bbl
                                                      ------------------------------------------------------------
                                                                                              Collar Prices
                                                                                        --------------------------
                                                                                                                      Fair Value at
Type of Contract and Period               Bbls/d        Swap Price      Floor Price        Floor        Ceiling    December 31, 2002
----------------------------------    --------------  --------------   -------------    -----------   ------------ -----------------
Collar Contracts
     Jan. 2003 - Dec. 2003                10,000      $           -    $           -    $     20.00   $      30.00   $       (2,077)
                                                                                   -
Swap Contracts
     Jan. 2003 - Dec. 2003                 2,500              24.25                -              -              -           (2,403)
     Jan. 2003 - Dec. 2003                 2,000              24.30                -              -              -           (1,886)
     Jan. 2003 - Dec. 2003                 2,000              25.70                -              -              -             (872)
     Jan. 2004 - Dec. 2004                 2,500              22.89                -              -              -             (415)
     Jan. 2004 - Dec. 2004                 4,500              23.00                -              -              -             (571)
     Jan. 2004 - Dec. 2004                 2,500              23.08                -              -              -             (246)

NATURAL GAS CONTRACTS:
---------------------
                                                                    NYMEX Contract Prices Per MMBtu
                                                      -------------------------------------------------------------
                                                                                             Collar Prices
                                                                                       ----------------------------  Fair Value at
Type of Contract and Period             MMBtu/d        Swap Price      Floor Price        Floor         Ceiling    December 31, 2002
-----------------------------------  -------------    --------------   -------------    -------------  ----------- -----------------
Collar Contracts
     Jan. 2003 - Dec. 2003                45,000      $           -    $           -    $      2.75   $       4.00   $      (12,866)
     Jan. 2003 - Dec. 2003                25,000                  -                -           2.75           4.07           (6,738)
     Jan. 2004 - Dec. 2004                30,000                  -                -           3.50           4.45           (3,278)
     Jan. 2004 - Dec. 2004                15,000                  -                -           3.00           5.87             (774)
     Jan. 2004 - Dec. 2004                15,000                  -                -           3.00           5.82             (808)
     Jan. 2005 - Dec. 2005                15,000                  -                -           3.00           5.50             (189)
Swap Contracts
     Jan. 2003 - Dec. 2003                10,000              3.905                -              -              -           (2,448)	

At December 31, 2002, our derivative contracts were recorded at their fair value, which was a net liability of $35.6 million. To the extent our hedges are considered effective, this fair value liability, net of income taxes, is included in Accumulated other comprehensive income (loss) reported under Stockholders' equity in our Consolidated Balance Sheets. The balance in accumulated other comprehensive loss of $19.3 million at December 31, 2002, represents the deficit in the fair market value of our derivative contracts as compared to the cost of our hedges, net of income taxes, and also includes the remaining accumulated other comprehensive income of $3.1 million relating to the Enron hedges that ceased to qualify for hedge accounting treatment when Enron filed for bankruptcy. This $3.1 million relating to the former Enron hedges will be reclassified out of accumulated other comprehensive income during 2003, over the periods that the hedges would have otherwise expired. Of the
-61-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$19.3 million in accumulated other comprehensive loss as of December 31, 2002, $15.4 million relates to current hedging contracts that will expire within the next 12 months and $3.9 million relates to contracts that expire after December 31, 2003.
NOTE 8. COMMITMENTS AND CONTINGENCIES
We have operating leases for the rental of office space, office equipment, and vehicles that totaled $1.7 million, $1.6 million and $1.4 million for the years ended December 31, 2002, 2001 and 2000, respectively. At December 31, 2002, long-term commitments for these items require the following future minimum rental payments:

AMOUNTS IN THOUSANDS

2003.............................     $    1,708
2004.............................          1,640
2005.............................          1,764
2006.............................          1,766
2007.............................          1,761
Thereafter ......................          3,022
                                      ----------
     Total lease commitments.....     $   11,661
                                      ==========	

We have future capital expenditure obligations related to field development costs that total $13.0 million over the next five years, of which $2.3 million is required to be spent in 2003.
Long-term contracts require us to deliver CO2 to our industrial CO2 customers. Based upon the maximum amounts deliverable as stated in the contracts, we estimate that we may be obligated to deliver up to 387 Bcf of CO2 to these customers over the next 18 years; however, based on the current level of deliveries, our commitment would be reduced to approximately 250 Bcf. Also, in the unforeseen circumstance that we could not deliver all of the volumes under these contracts, we could reduce our deliveries to all parties proportionately with the exception of one party, which has preferential rights under their contract. Given the size of our proven CO2 reserves (approximately 1.6 Tcf), our current production capabilities and our predicted levels of CO2 usage for our own tertiary flooding program, we are confident that we can meet these delivery obligations.
Denbury is subject to various possible contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. In the opinion of management, the outcome of such matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
NOTE 9. SUPPLEMENTAL INFORMATION
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. The loss of any purchaser would not be expected to have a material adverse effect upon our operations. For the year ended December 31, 2002, we had two significant purchasers that each accounted for 10% or more of our oil and natural gas revenues: Hunt Refining (14%) and Genesis (11%). For the year ended December 31, 2001, four purchasers each accounted for 10% or more of our oil and natural gas revenues: Conoco (14%), Hunt Refining (13%), EOTT Energy (12%), and Dynegy (12%). For the year ended December 31, 2000, four purchasers each accounted for 10% or more of our oil and natural gas revenues: Hunt Refining (24%), Southland Refining (17%), EOTT Energy (16%), and Dynegy (10%).
-62-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accounts Payable and Accrued Liabilities

                                                      DECEMBER 31,
                                               ----------------------------
AMOUNTS IN THOUSANDS                                 2002           2001
                                               -------------  -------------
Accounts payable.............................  $      25,545  $      37,718
Accrued exploration and development costs....          9,935         16,198
Accrued interest.............................          6,248          6,976
Other........................................          7,553          5,606
                                               -------------  -------------
   Total.....................................  $      49,281  $      66,498
                                               =============  =============	

                       Supplemental Cash Flow Information

                                                 YEAR ENDED DECEMBER 31,
                                        ----------------------------------------
AMOUNTS IN THOUSANDS                        2002          2001           2000
                                        ------------  ------------    ----------
Interest paid...........................     $24,636       $17,451       $13,936
Income taxes paid (refunded)............      (1,304)        2,482           275	

In 2001, in connection with our acquisition of Matrix, we recorded non-cash increases to property and equipment resulting from the issuance of common stock in the amount of $59.2 million and the recording of deferred taxes in the amount of $53.1 million.
Fair Value of Financial Instruments

                                                                       DECEMBER 31,
                                                  ------------------------------------------------------
                                                            2002                        2001
                                                  -------------------------  ---------------------------
                                                    Carrying      Estimated      Carrying      Estimated
AMOUNTS IN THOUSANDS                                 Amount      Fair Value        Amount     Fair Value
                                                  ------------ ------------  ------------ --------------
Senior bank debt................................. $    150,000 $    150,000  $    140,870 $      140,870
9% Senior Subordinated Notes due 2008............      125,000      129,113       125,000        117,500
9% Series B Senior Subordinated Notes due 2008...       69,889       77,468        68,899         70,500	

As of December 31, 2002 and 2001, the carrying value of our bank debt approximated fair value based on the fact that our bank debt is subject to short-term floating interest rates that approximated the rates available to us at those periods. The fair values of our senior subordinated notes are based on quoted market prices. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables which approximate fair value due to the nature of the instrument and the relatively short maturities.
NOTE 10. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease, or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas.
-63-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Costs incurred in oil and natural gas activities were as follows:

                                                YEAR ENDED DECEMBER 31,
                                       -----------------------------------------
AMOUNTS IN THOUSANDS                      2002          2001            2000
                                       -----------   -----------     -----------
Property acquisitions:
   Proved (1).......................   $    56,364   $   127,066     $    50,285
   Unevaluated......................         4,342        37,051          11,741
Exploration.........................        13,493        11,692           6,782
Development.........................        81,438       151,366          65,213
                                       -----------   -----------     -----------
   Total costs incurred (2).........   $   155,637   $   327,175     $   134,021
                                       ===========   ===========     ===========	

(1) Excludes deferred taxes recorded in the acquisition of Matrix of $53.1 million in 2001.
(2) Capitalized general and administrative costs that directly relate to exploration and development activities were $5.3 million, $4.1 million and $3.2 million for the years ended December 31, 2002, 2001 and 2000, respectively.
Oil and Natural Gas Operating Results
Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:

                                                                                          YEAR ENDED DECEMBER 31,
                                                                            ----------------------------------------------------
AMOUNTS IN THOUSANDS                                                                  2002              2001              2000
                                                                            -----------------  ---------------  ----------------

Oil, natural gas and related product sales................................. $         274,894  $       260,398  $        204,636
Gain (loss) on settlements of derivative contracts.........................               932           18,654           (25,264)
                                                                            -----------------  ---------------  ----------------
   Total revenues..........................................................           275,826          279,052           179,372
                                                                            -----------------  ---------------  ----------------

Lease operating costs......................................................            71,188           55,049            38,676
Production taxes and marketing expenses....................................            11,902           10,963             8,051
Depletion and depreciation.................................................            90,679           69,773            36,214
Loss on Enron related assets...............................................                 -           25,164                 -
Amortization of derivative contracts and other non-cash hedging
   adjustments.............................................................            (3,093)           7,816                 -
                                                                            -----------------  ---------------  ----------------
   Net operating income....................................................           105,150          110,287            96,431
Income tax provision (benefit).............................................            36,563           35,526           (67,294)
                                                                            -----------------  ---------------  ----------------
Results of operations from oil and natural gas producing activities........ $          68,587  $        74,761  $        163,725
                                                                            =================  ===============  ================

Depletion and depreciation per BOE......................................... $            6.98  $          6.01  $           4.48
                                                                            =================  ===============  ================	

Oil and Natural Gas Reserves
Net proved oil and natural gas reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. The reserves were prepared in accordance with guidelines established by the Securities and Exchange Commission and, accordingly, were based on existing economic and operating conditions. Oil and natural gas prices in effect as of the reserve report date were used without any escalation. (See "Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves" below for a discussion of the effect of the different prices on reserve quantities and values.) Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation.
We have a corporate policy whereby we do not book proved undeveloped reserves unless the project is scheduled in our development budget (or at least the commencement of the project in the case of longer-term multi-year projects such as waterfloods and tertiary recovery projects). In most cases our development budget is only prepared for the next year or so. We also have a corporate policy whereby proved undeveloped reserves must be economic at low to moderate commodity prices, which for 2002 and the prior two years we set at $18.50 per Bbl of oil and $2.50 per Mcf of natural gas.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of our oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. All of our reserves are located in the United States.
-64-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                                              Estimated Quantities of Reserves

                                                                    YEAR ENDED DECEMBER 31,
                                            -----------------------------------------------------------------------
                                                     2002                    2001                     2000
                                            ----------------------  ----------------------   ----------------------
                                               Oil         Gas         Oil          Gas         Oil         Gas
                                             (MBbl)       (MMcf)      (MBbl)      (MMcf)      (MBbl)       (MMcf)
                                            ---------   ----------  ----------   ---------   ---------   ----------
BALANCE AT BEGINNING OF YEAR................   76,490      198,277      70,667     100,550      51,832       50,438
     Revisions of previous estimates........     (408)     (22,975)      4,344        (631)      4,078        8,271
     Revisions due to price changes.........    3,020        2,660      (7,800)     (2,745)        412        1,905
     Extensions and discoveries.............    2,326       51,819       2,308      66,448       2,746       25,593
     Improved recovery (1)..................        -            -       1,667           -      16,466        5,613
     Production.............................   (6,874)     (36,662)     (6,197)    (31,112)     (5,555)     (13,533)
     Acquisition of minerals in place.......   23,383        9,360      11,501      65,767       1,182       23,209
     Sales of minerals in place.............     (734)      (1,532)          -           -        (494)        (946)
                                            ---------   ----------  ----------   ---------   ---------   ----------
BALANCE AT END OF YEAR......................   97,203      200,947      76,490     198,277      70,667      100,550
                                            =========   ==========  ==========   =========   =========   ==========

PROVED DEVELOPED RESERVES
     Balance at beginning of year...........   54,722      169,897      52,353      77,358      32,767       41,635
     Balance at end of year.................   62,398      142,812      54,722     169,897      52,353       77,358	

(1) Improved recovery additions result from the application of secondary recovery methods such as waterflooding or tertiary recovery methods such as CO2 flooding.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does not purport to present the fair market value of our oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. The product prices used in calculating these reserves have varied widely during the three-year period. These prices have a significant impact on both the quantities and value of the proven reserves as the reduced oil price causes wells to reach the end of their economic life much sooner and can make certain proved undeveloped locations uneconomical, both of which reduce the reserves. The following representative oil and natural gas year-end prices were used in the Standardized Measure. These prices were adjusted by field to arrive at the appropriate corporate net price.

                                                    DECEMBER 31,
                                     -------------------------------------------
                                         2002           2001           2000
                                     -------------  ------------  --------------
Oil (NYMEX)..........................$       31.20   $     19.84   $       26.80
Natural Gas (NYMEX Henry Hub)........         4.79          2.57            9.78	

Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre- tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss carryforwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
-65-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                                                                              DECEMBER 31,
                                                                            ------------------------------------------------
AMOUNTS IN THOUSANDS                                                               2002             2001             2000
                                                                            ---------------  --------------   --------------

Future cash inflows.......................................................  $     3,787,077  $    1,786,884   $    2,609,306
Future production costs...................................................       (1,044,193)       (655,363)        (600,195)
Future development costs..................................................         (268,269)       (178,546)         (95,068)
                                                                            ---------------  --------------   --------------
    Future net cash flows before taxes ...................................        2,474,615         952,975        1,914,043
10% annual discount for estimated timing of cash flows....................       (1,048,395)       (378,647)        (755,074)
                                                                            ---------------  --------------   --------------
    Discounted future net cash flows before taxes.........................        1,426,220         574,328        1,158,969
Discounted future income taxes............................................         (397,244)        (68,533)        (317,670)
                                                                            ---------------  --------------   --------------
     STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS.............  $     1,028,976  $      505,795   $      841,299
                                                                            ===============  ==============   ==============	

The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:

                                                                                        YEAR ENDED DECEMBER 31,
                                                                           --------------------------------------------------
AMOUNTS IN THOUSANDS                                                               2002               2001             2000
                                                                           ---------------   ----------------  --------------

BEGINNING OF YEAR.......................................................   $       505,795   $        841,299  $      448,374
Sales of oil and natural gas produced, net of production costs..........          (191,803)          (194,386)       (157,909)
Net changes in sales prices.............................................           694,646           (838,124)        281,181
Extensions and discoveries, less applicable future  development
   and production costs.................................................           151,926            123,214         200,966
Improved recovery (1)...................................................                 -              5,045          77,702
Previously estimated development costs incurred.........................            34,931             64,072          20,623
Revisions of previous estimates, including revised estimates of
   development costs, reserves and rates of production..................           (50,855)           (13,290)         48,018
Accretion of discount...................................................            57,433            115,897          46,287
Acquisition of minerals in place........................................           160,899            152,931         183,634
Sales of minerals in place..............................................            (5,285)                 -          (4,403)
Net change in income taxes..............................................          (328,711)           249,137        (303,174)
                                                                           ---------------   ----------------  --------------
END OF YEAR.............................................................   $     1,028,976   $        505,795  $      841,299
                                                                           ===============   ================  ==============	

(1) Improved recovery additions result from the application of secondary recovery methods such as waterflooding or tertiary recovery methods such as CO2 flooding.
CO2 Reserves
Based on engineering reports prepared by DeGolyer and MacNaughton, our CO2 reserves, on a working interest basis, were estimated at approximately 1.6 Tcf at December 31, 2002 and 815 Bcf at December 31, 2001.
NOTE 11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
As of December 31, 2002, all of our senior subordinated notes were fully and unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries. The following condensed consolidating financial information for Denbury Resources Inc. and its significant subsidiaries includes the results of our equity interest in Genesis, which is recorded under the equity method by Denbury Gathering & Marketing.
-66-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                                             Condensed Consolidating Balance Sheets

                                                                       DECEMBER 31, 2002
                                                ---------------------------------------------------------------
                                                   Denbury                                          Denbury
                                                  Resources                                        Resources
                                                 Inc. (Parent     Guarantor                           Inc.
Amounts in Thousands                             and Issuer)     Subsidiaries    Eliminations     Consolidated
                                                --------------   -------------   -------------   --------------
ASSETS
Current assets..................................$      111,063   $      17,401   $           -   $      128,464
Property and equipment..........................       528,754         215,331               -          744,085
Investment in subsidiaries (equity method)......       169,309           2,224        (169,309)           2,224
Other assets....................................        16,881           3,638               -           20,519
                                                --------------   -------------   -------------   --------------
   Total assets.................................$      826,007   $     238,594   $    (169,309)  $      895,292
                                                ==============   =============   =============   ==============

LIABILITIES AND STOCKHOLDERS'
   EQUITY
Current liabilities.............................$       87,101   $       8,778   $           -   $       95,879
Long-term liabilities...........................       372,109          60,507               -          432,616
Stockholders' equity............................       366,797         169,309        (169,309)         366,797
                                                --------------   -------------   -------------   --------------
   Total liabilities and stockholders' equity...$      826,007   $     238,594   $    (169,309)  $      895,292
                                                ==============   =============   =============   ==============	

                                                                       DECEMBER 31, 2001
                                                ---------------------------------------------------------------
                                                   Denbury                                          Denbury
                                                  Resources                                        Resources
                                                 Inc. (Parent     Guarantor                           Inc.
Amounts in Thousands                             and Issuer)     Subsidiaries     Eliminations    Consolidated
                                                --------------   -------------   --------------  --------------
ASSETS
Current assets..................................$       98,182   $       5,096   $            -  $      103,278
Property and equipment .........................       445,693         222,314                -         668,007
Investment in subsidiaries (equity method)......       164,830               -         (164,830)              -
Other assets....................................        15,684           3,019                -          18,703
                                                --------------   -------------   --------------  --------------
   Total assets.................................$      724,389   $     230,429   $     (164,830) $      789,988
                                                ==============   =============   ==============  ==============

LIABILITIES AND STOCKHOLDERS'
   EQUITY
Current liabilities.............................$       68,937   $      11,001   $            -  $       79,938
Long-term liabilities...........................       306,284          54,598                -         360,882
Stockholders' equity............................       349,168         164,830         (164,830)        349,168
                                                --------------   -------------   --------------  --------------
   Total liabilities and stockholders' equity...$      724,389   $     230,429   $     (164,830) $      789,988
                                                ==============   =============   ==============  ==============	

                                                         Condensed Consolidating Statements of Operations

                                                                YEAR ENDED DECEMBER 31, 2002
                                             ------------------------------------------------------------------
                                                   Denbury                                           Denbury
                                                   Resources                                         Resources
                                                 Inc. (Parent      Guarantor                           Inc.
Amounts in Thousands                             and Issuer)     Subsidiaries      Eliminations    Consolidated
                                               ---------------   --------------    --------------  --------------
Revenues.....................................   $       231,147   $     54,005    $           -  $      285,152
Expenses.....................................           166,805         48,087                -         214,892
                                                ---------------   ------------    -------------  --------------
Income before the following:                             64,342          5,918                -          70,260
   Equity in net earnings of subsidiaries....             3,456             55           (3,456)             55
                                                ---------------   --------------  -------------- --------------
Income (loss) before income taxes............            67,798          5,973           (3,456)         70,315
Income tax provision.........................            21,003          2,517                -          23,520
                                                ---------------   --------------  --------------  ------------
Net income (loss)............................   $        46,795   $      3,456    $      (3,456) $       46,795
                                                ===============   ============    ============== ==============	

-67-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                                                 YEAR ENDED DECEMBER 31, 2001
                                             ------------------------------------------------------------------
                                                 Denbury                                             Denbury
                                                Resources                                           Resources
                                              Inc. (Parent       Guarantor                             Inc.
Amounts in Thousands                           and Issuer)      Subsidiaries     Eliminations     Consolidated
                                             ---------------   --------------   ---------------  --------------
Revenues.....................................$       261,678   $       23,433   $             -  $      285,111
Expenses.....................................        181,346           22,391                 -         203,737
                                             ---------------   --------------   ---------------  --------------
Income before the following:                          80,332            1,042                 -          81,374
   Equity in net earnings of subsidiaries....            653                -              (653)              -
                                             ---------------   --------------   ---------------  --------------
Income (loss) before income taxes............         80,985            1,042              (653)         81,374
Income tax provision.........................         24,435              389                 -          24,824
                                             ---------------   --------------   ---------------  --------------
Net income (loss)............................$        56,550   $          653   $          (653) $       56,550
                                             ===============   ==============   ===============  ==============	

                                                                YEAR ENDED DECEMBER 31, 2000
                                             ------------------------------------------------------------------
                                                 Denbury                                            Denbury
                                              Resources Inc.                                       Resources
                                               (Parent and        Guarantor                           Inc.
Amounts in Thousands                             Issuer)         Subsidiaries     Eliminations    Consolidated
                                             ----------------   --------------   --------------  --------------
Revenues.....................................$        180,538   $        1,113   $            -  $      181,651
Expenses.....................................         106,805              (87)               -         106,718
                                             ----------------   --------------   --------------  --------------
Income before the following:                           73,733            1,200                -          74,933
   Equity in net earnings of subsidiaries....           1,200                -           (1,200)              -
                                             ----------------   --------------   --------------  --------------
Income (loss) before income taxes............          74,933            1,200           (1,200)         74,933
Income tax benefit...........................         (67,294)               -                -         (67,294)
                                             ----------------   --------------   --------------  --------------
Net income (loss)............................$        142,227   $        1,200   $       (1,200) $      142,227
                                             ================   ==============   ==============  ==============	

                                 Condensed Consolidating Statements of Cash Flows

                                                                YEAR ENDED DECEMBER 31, 2002
                                             ------------------------------------------------------------------
                                                  Denbury                                           Denbury
                                              Resources Inc.                                       Resources
                                                (Parent and       Guarantor                           Inc.
Amounts in Thousands                              Issuer)        Subsidiaries     Eliminations    Consolidated
                                             -----------------  --------------   --------------  --------------
Cash flow from operations....................$         146,132  $       13,468   $            -  $      159,600
Cash flow from investing activities..........         (154,908)        (16,253)               -        (171,161)
Cash flow from financing activities..........           12,005               -                -          12,005
                                             -----------------  --------------   --------------  --------------
Net increase (decrease) in cash flow.........            3,229          (2,785)               -             444
Cash, beginning of period....................           17,052           6,444                -          23,496
                                             -----------------  --------------   --------------  --------------
Cash, end of period..........................$          20,281  $        3,659   $            -  $       23,940
                                             =================  ==============   ==============  ==============	

                                                                YEAR ENDED DECEMBER 31, 2001
                                             ------------------------------------------------------------------

                                                  Denbury                                           Denbury
                                              Resources Inc.                                       Resources
                                                (Parent and       Guarantor                           Inc.
Amounts in Thousands                              Issuer)        Subsidiaries     Eliminations    Consolidated
                                             -----------------  --------------   --------------  --------------
Cash flow from operations....................$         154,034  $       31,013   $            -  $      185,047
Cash flow from investing activities..........         (294,253)        (24,577)               -        (318,830)
Cash flow from financing activities..........          134,986               -                -         134,986
                                             -----------------  --------------   --------------  --------------
Net increase (decrease) in cash flow.........           (5,233)          6,436                -           1,203
Cash, beginning of period....................           22,285               8                -          22,293
                                             -----------------  --------------   --------------  --------------
Cash, end of period..........................$          17,052  $        6,444   $            -  $       23,496
                                             =================  ==============   ==============  ==============	

-68-
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                                                YEAR ENDED DECEMBER 31, 2000
                                             ------------------------------------------------------------------
                                                  Denbury                                           Denbury
                                              Resources Inc.                                       Resources
                                                (Parent and       Guarantor                           Inc.
Amounts in Thousands                              Issuer)        Subsidiaries     Eliminations    Consolidated
                                             -----------------  --------------   --------------  --------------
Cash flow from operations....................$          98,004  $       (2,032)  $            -  $       95,972
Cash flow from investing activities..........         (133,040)              -                -        (133,040)
Cash flow from financing activities..........           47,593               -                -          47,593
                                             -----------------  --------------   --------------  --------------
Net increase (decrease) in cash flow.........           12,557          (2,032)               -          10,525
Cash, beginning of period....................            9,728           2,040                -          11,768
                                             -----------------  --------------   --------------  --------------
Cash, end of period..........................$          22,285  $            8   $            -  $       22,293
                                             =================  ==============   ==============  ==============	

NOTE 12. SUBSEQUENT EVENTS (UNAUDITED)
In February 2003, we sold Laurel Field, acquired in the COHO acquisition, for $27.0 million and other consideration which included an interest in Atchafalaya Bay Field (where we already own an interest) and seismic over that area. At December 31, 2002, Laurel Field had approximately 7.4 MMBbls of proved reserves. We have also reached an agreement to sell two other fields that we acquired in the COHO acquisition, Bentonia and Glazier Fields, for approximately $2.0 million combined, and this sale is expected to close in late March. Both of these are much smaller fields with approximately 269,000 Bbls of proved reserves at December 31, 2002. The proceeds from the sale of Laurel Field were used to reduce our bank debt.
On March 17, 2003, we announced a refinancing of our 9% Senior Subordinated Notes due 2008. We sold $225 million of 7.5% Senior Subordinated Notes due 2013 and called our existing $200 million of 9% notes at 104.5% of face value. Closing on the new notes is scheduled for March 25, 2003, subject to the satisfaction of customary closing conditions, and the redemption of the old notes is expected to occur on April 16, 2003. We intend to use the remaining net proceeds from this offering to reduce bank debt. Once completed, the refinancing is expected to save us around $2.6 million per year in interest expense. Assuming completion, we estimate that we will have a charge to earnings in the second quarter of 2003 of approximately $11.25 million, net of related income taxes, from the early retirement of our currently outstanding 9% notes.
NOTE 13. UNAUDITED QUARTERLY INFORMATION

IN THOUSANDS EXCEPT PER SHARE AMOUNTS                MARCH 31         JUNE 30         SEPT. 30        DECEMBER 31
------------------------------------------------ ------------------------------------------------------------------
2002
----
Revenues........................................   $     55,447    $      73,433   $       74,524   $        81,748
Expenses........................................         49,924           53,842           52,906            58,220
Net income......................................          4,546           13,498           13,459            15,292
Net income per share:
   Basic........................................           0.09             0.25             0.25              0.29
   Diluted......................................           0.08             0.25             0.25              0.28

Cash flow from operations ......................         12,032           46,572           44,379            56,617
Cash flow used for investing activities.........        (27,129)         (32,069)         (80,622)          (31,341)
Cash flow provided by (used for) financing
   activities...................................          5,970           (8,697)          38,992           (24,260)

2001
----
Revenues........................................   $     79,180    $      67,407   $       74,318   $        64,206
Expenses........................................         37,960           35,484           52,178            78,115
Net income (loss)...............................         25,969           20,111           13,948            (3,478)
Net income (loss) per share:
      Basic.....................................           0.56             0.44             0.27             (0.07)
      Diluted ..................................           0.55             0.42             0.26             (0.07)

Cash flow from operations ......................         66,089           30,886           45,097            42,975
Cash flow used for investing activities.........        (70,391)         (44,891)        (139,993)          (63,555)
Cash flow provided by financing activities......          8,530           10,820           95,297            20,339	

-69-
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. Denbury de-listed from the Toronto Stock Exchange effective April 15, 2002.
As of February 1, 2003, to the best of our knowledge, the outstanding shares of Denbury's common stock were held by approximately 770 holders of record; however, we estimate that beneficial owners of Denbury's common stock is in excess of 1,500.
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.

                                                                NYSE
------------------------------------------------------------------------------
                                                       HIGH              LOW
------------------------------------------------------------------------------
2002
----
First quarter                                       $     8.50       $    6.20
Second quarter                                           10.42            7.91
Third quarter                                            10.35            7.80
Fourth quarter                                           11.97            9.45
------------------------------------------------------------------------------
   2002 annual                                      $    11.97       $    6.20
------------------------------------------------------------------------------
2001
----
First quarter                                       $    12.00       $    7.90
Second quarter                                           12.30            7.30
Third quarter                                             9.75            7.50
Fourth quarter                                            8.81            6.00
------------------------------------------------------------------------------
   2001 annual                                      $    12.30       $    6.00
------------------------------------------------------------------------------	

-70-
  
EXHIBIT 21
LIST OF SUBSIDIARIES

                                                  JURISDICTION OF
NAME OF SUBSIDIARY                                 INCORPORATION                             STATUS
------------------------------------------  ----------------------------  ---------------------------------------------

Tallahatchie Resources, Inc.                Texas                         Wholly owned subsidiary of Denbury
                                                                          Resources Inc. - dormant

Denbury Marine, L.L.C.                      Louisiana                     Wholly owned subsidiary of Denbury
                                                                          Resources Inc. - marine company

Denbury Energy Services, Inc.               Texas                         Wholly owned subsidiary of Denbury
                                                                          Resources Inc. - marketing company

Denbury Offshore, Inc.                      Delaware                      Wholly owned subsidiary of Denbury
                                                                          Resources Inc. - offshore oil and gas
                                                                          properties

Denbury Gathering & Marketing, Inc.         Delaware                      Wholly owned subsidiary of Denbury
                                                                          Resources Inc. - parent company of Genesis
                                                                          Energy, Inc.

Genesis Energy, Inc.                        Delaware                      Wholly owned subsidiary of Denbury
                                                                          Gathering & Marketing, Inc. - holds 2%
                                                                          general partner interest of Genesis Energy, L.P.
                                                                          and .01% general partner interest of Genesis
                                                                          Crude Oil, L.P.	

EX 21-1
 
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos. 333-1006, 333-27995, 333-55999, 333-70485, 333-39172, 333-39218, 333-63198 and 333-90398 on Forms S-8, and Registration Statement No. 333-57382 on Form S-3 of Denbury Resources Inc. of our report dated March 3, 2003, appearing in this Annual Report on Form 10-K of Denbury Resources Inc. for the year ended December 31, 2002.

/s/ Deloitte & Touche LLP

Dallas, Texas
March 21, 2003	

EX 23 - 1
 
EXHIBIT 23.2
DEGOLYER AND MACNAUGHTON
4925 GREENVILLE AVENUE, SUITE 400
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
March 20, 2003
Denbury Resources Inc.
5100 Tennyson Parkway, Suite 3000
Plano, Texas 75024
Ladies and Gentlemen:
We consent to the use of the name DeGolyer and MacNaughton and to references to our estimates of net proved oil and natural gas reserves or other information contained in our "Appraisal Report as of December 31, 2002 on Certain Properties owned by Denbury Resources Inc. SEC Case"; our "Appraisal Report as of December 31, 2001 on Certain Properties owned by Denbury Resources Inc. SEC Case"; and our "Appraisal Report as of December 31, 2000 on Certain Properties owned by Denbury Resources Inc. SEC Case" (i) under the headings "Item 1. Business - Estimated Net Quantities of Proved Oil and Gas Reserves and Present Value of Estimated Future Net Revenues," and "Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K - (b) Reports on Form 8-K" of Denbury Resources Inc.'s Form 10-K for the fiscal year ended December 31, 2002, and (ii) in Denbury Resources Inc.'s Annual Report to Shareholders under the headings "Financial Highlights," "Selected Operating Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and "Notes to Consolidated Financial Statements Years Ended December 31, 2002, 2001, and 2000" included in such Form 10-K as Exhibit 13 therein.
We further consent to the incorporation of our "Appraisal Report as of December 31, 2002 on Proved Reserves of Certain Properties owned by Denbury Resources Inc. SEC Case" in such Form 10-K as Exhibit 99.2 therein.
Very truly yours,

/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON	

EXHIBIT 99.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the accompanying Annual Report on Form 10-K for the year ended December 31, 2002 (the "Report") of Denbury Resources Inc. ("Denbury") as filed with the Securities and Exchange Commission on March 21, 2003, each of the undersigned, in his capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.        The  information  contained  in the  Report  fairly  presents,  in all
          material respects,  the financial  condition and results of operations
          of Denbury.

Dated:  March 20, 2003                         /s/ Gareth Roberts
                                  ----------------------------------------------
                                                   Gareth Roberts	

President and Chief Executive Officer

Dated:  March 20, 2003                         /s/ Phil Rykhoek
                                  ----------------------------------------------
                                                   Phil Rykhoek
                                  Sr. Vice President and Chief Financial Officer	

EX 99 - 1
 
EXHIBIT 99.2
DEGOLYER AND MACNAUGHTON
4925 GREENVILLE AVENUE, SUITE 400
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
APPRAISAL REPORT
AS OF
 DECEMBER 31, 2002
ON
PROVED RESERVES
OF
CERTAIN PROPERTIES
OWNED BY
DENBURY RESOURCES INC.
SEC CASE

                                         TABLE OF CONTENTS

                                                                                                      PAGE

FOREWORD...........................................................................................      1
  Scope of Investigation...........................................................................      1
  Authority........................................................................................      2
  Source of Information............................................................................      2
CLASSIFICATION OF RESERVES.........................................................................      4
ESTIMATION OF RESERVES.............................................................................      7
VALUATION OF RESERVES..............................................................................      9
SUMMARY AND CONCLUSIONS............................................................................     12	

DEGOLYER AND MACNAUGHTON
4925 GREENVILLE AVENUE, SUITE 400
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
APPRAISAL REPORT
AS OF
 DECEMBER 31, 2002
ON
PROVED RESERVES
OF
CERTAIN PROPERTIES
OWNED BY
DENBURY RESOURCES INC.
SEC CASE
FOREWORD

Scope of Investigation
This report presents an appraisal, as of December 31, 2002, of the extent and value of the proved crude oil, condensate, natural gas liquids, and natural gas reserves of certain properties owned by Denbury Resources Inc. (Denbury). The reserves estimated in this report are located in Louisiana, Mississippi, Texas, and offshore from Louisiana and Texas. The properties appraised are listed in detail in related report entitled "Appraisal Report as of December 31, 2002 on Certain Properties owned by Denbury Resources Inc. SEC Case."
Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2002. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Denbury after deducting royalties and interests owned by others.
This report also presents values that were estimated for proved reserves using initial prices and costs provided by Denbury. Prices are related to NYMEX prices of $31.20 per barrel and $4.79 per million British thermal units (MMBtu). No escalation has been applied to prices and costs. A
2
detailed explanation of the future price and cost assumptions is included in the Valuation of Reserves section of this report.
Values of proved reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating costs, compression charges, and the estimated expenses of direct supervision, but do not include that portion of general administrative costs sometimes allocated to production. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a discount rate of 10 percent are reported.
Estimates of oil, condensate, natural gas liquids, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Authority
This report was prepared at the request of Mr. Ronald T. Evans, Senior Vice President Reservoir Engineering, Denbury.
Source of Information
Data used in the preparation of this report were obtained from Denbury, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Denbury with respect to its property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as
3
represented. A field examination of the properties was not considered necessary for the purposes of this report.
4
CLASSIFICATION OF RESERVES
Petroleum reserves included in this report are classified by degree of proof as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. Proved reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-10(a) (1)-(13) of Regulation S-X of the Securities and Exchange Commission (SEC) of the United States. The petroleum reserves are classified as follows:
Proved oil and gas reserves - Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when
5
successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite, and other such sources.
Proved developed oil and gas reserves - Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves - Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved
6
recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
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ESTIMATION OF RESERVES
Estimates of reserves were prepared by the use of geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic conditions.
In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.
The gas reserves included herein are reported as sales gas. Sales gas is defined as that gas to be delivered into a gas
8
pipeline for sale after separation, processing, fuel use, and flare. All gas volumes are expressed at a temperature base of 60 degrees Fahrenheit ((degree)F) and at the legal pressure base of the state or area in which the reserves are located. Condensate reserves estimated herein are those to be recovered by conventional lease separation. Natural gas liquids reserves are estimated to be those attributable to the leasehold interests appraised based on historical yield information.
In the preparation of this study, as of December 31, 2002, gross production estimated to December 31, 2002, was deducted from gross ultimate recovery to arrive at the estimate of gross reserves. In some fields, this required that the production rates be estimated for up to 3 months, since production data from certain properties were available only through September 2002.
At the request of Denbury, data available from wells drilled on the appraised properties through January 22, 2003, were used to prepare the estimates shown herein. New wells drilled and logged after December 31, 2002, are the OCS G 18863 Block A 9 well JA 2, in North Padre Island Block A-9 field, and the Oak Estates 2 well in Lake Gero North field. Both wells were logged early in January 2003. The reserves attributable to these wells are classified as proved undeveloped.
The table below presents estimates of the proved reserves, as of December 31, 2002, of the properties appraised, expressed in barrels (bbl) or thousands of cubic feet (Mcf):

                                   OIL AND        NATURAL GAS         TOTAL
                                 CONDENSATE         LIQUIDS          LIQUIDS              GAS
                                    (BBL)            (BBL)            (BBL)              (MCF)
                               ---------------- ----------------  --------------- ----------------

Gross Reserves
Developed Producing                 55,039,125          815,950       55,855,075      220,064,172
Developed Nonproducing              29,431,993          174,936       29,606,929      138,692,724
Undeveloped                         43,378,603          287,625       43,666,228      110,949,144
                               ---------------- ----------------  --------------- ----------------

TOTAL GROSS                        127,849,721        1,278,511      129,128,232      469,706,040

Net Reserves
Developed Producing                 40,285,349          442,495       40,727,844       96,136,096
Developed Nonproducing              21,541,648          128,240       21,669,888       46,675,748
Undeveloped                         34,671,539          134,101       34,805,640       58,135,629
                               ---------------- ----------------  --------------- ----------------
TOTAL NET                           96,498,536          704,836       97,203,372      200,947,473	

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VALUATION OF RESERVES
Revenue values in this report were estimated using the initial prices and costs provided by Denbury. Future prices were estimated using guidelines established by the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB).
In this report, values for proved reserves were based on projections of estimated future production and revenue prepared for these properties.
The following assumptions were used for estimating future prices and costs:
Oil and Condensate Prices
Oil and condensate prices were calculated using differentials furnished by Denbury for each lease to a NYMEX price of $31.20 per barrel and held constant thereafter. The weighted average price over the lives of the properties was $28.78 per barrel.
Natural Gas Liquids Prices
Natural gas liquids prices were calculated using the 2002 average ratio to the NYMEX price of $31.20 per barrel. These prices were held constant over the lives of the properties.
Natural Gas Prices
Natural gas prices were calculated for each lease using differentials furnished by Denbury to a NYMEX price of $4.79 per MMBtu and held constant thereafter. The weighted average price over the lives of the properties was $4.96 per thousand cubic feet.
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Operating and Capital Costs
Current operating and capital costs, based on information provided by Denbury, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.
The future revenue to be derived from the production and sale of the proved reserves, as of December 31, 2002, of the properties appraised is estimated as follows:

                                                               PROVED
                                         ----------------------------------------------------
                                            DEVELOPED        DEVELOPED                            TOTAL
                                            PRODUCING       NONPRODUCING      UNDEVELOPED         PROVED
                                         ---------------------------------------------------------------------

Future Gross Revenue, $                    1,607,099,117        864,422,870    1,315,554,606    3,787,076,593
Production and Ad Valorem Taxes, $            61,776,745         32,873,032       42,930,347      137,580,124
Operating Costs, $                           441,454,158        160,089,796      305,069,080      906,613,034
Capital Costs, $                              20,604,511         42,907,557      204,756,464      268,268,532
Future Net Revenue*, $                     1,083,263,703        628,552,485      762,798,715    2,474,614,903
Present Worth at 10 Percent*, $              734,804,064        333,971,626      357,444,166    1,426,219,856	

* Future income taxes have not been taken into account in the preparation of these estimates.
Timing of capital expenditures and the resulting development of production were based on a development plan provided by Denbury.
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 10-13, 15, and 30(a)-(b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the FASB and Rules 4-10(a) (1)-(13) of Regulation S-X and Rule 302(b) of Regulation S-K of the SEC; provided, however, that (i) certain estimated data have not been provided with respect to changes in reserves information and (ii) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.
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To the extent that the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of our report, we are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
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SUMMARY AND CONCLUSIONS
Denbury owns working and royalty interests in certain properties located in Louisiana, Mississippi, Texas, and offshore from Louisiana and Texas. The estimated net proved reserves of the properties appraised, as of December 31, 2002, are summarized as follows, expressed in barrels (bbl) or thousands of cubic feet (Mcf):

                                  OIL AND        NATURAL GAS         TOTAL
                                 CONDENSATE        LIQUIDS          LIQUIDS            GAS
                                   (BBL)            (BBL)            (BBL)            (MCF)
                               ---------------  ---------------  ---------------  --------------

Net Reserves
Developed Producing                40,285,349          442,495       40,727,844      96,136,096
Developed Nonproducing             21,541,648          128,240       21,669,888      46,675,748
Undeveloped                        34,671,539          134,101       34,805,640      58,135,629
                               ---------------  ---------------  ---------------  --------------
TOTAL                              96,498,536          704,836       97,203,372     200,947,473	

The estimated revenue and costs attributable to Denbury's interests in the proved reserves, as of December 31, 2002, of the properties appraised under the aforementioned assumptions concerning future prices and costs are summarized as follows:

                                                               PROVED
                                         ----------------------------------------------------
                                            DEVELOPED        DEVELOPED                            TOTAL
                                            PRODUCING      NONPRODUCING       UNDEVELOPED        PROVED
                                         --------------------------------------------------------------------

Future Gross Revenue, $                    1,607,099,117       864,422,870     1,315,554,606   3,787,076,593
Production and Ad Valorem Taxes, $            61,776,745        32,873,032        42,930,347     137,580,124
Operating Costs, $                           441,454,158       160,089,796       305,069,080     906,613,034
Capital Costs, $                              20,604,511        42,907,557       204,756,464     268,268,532
Future Net Revenue*, $                     1,083,263,703       628,552,485       762,798,715   2,474,614,903
Present Worth at 10 Percent*, $              734,804,064       333,971,626       357,444,166   1,426,219,856	

* Future income taxes have not been taken into account in the preparation of these estimates.
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All gas volumes in this report are expressed at a temperature base of 60 (degree)F and at the legal pressure base of the state or area in which the reserves are located.
Submitted,

                                          /s/ DeGolyer and MacNaughton
                                          DeGOLYER and MacNAUGHTON
SIGNED:  March 19, 2003	

/s/ James W. Hail
--------------------------------------
James W. Hail, Jr., P.E.
Executive Vice President
DeGolyer and MacNaughton