-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, LkRFFxxfDruTK+1EgJHOoVddRnI01NgDy9lh4L4ANqMo7xAgpSadDr1LhpTs/D6w KFZgWuNdSyWJPvDtDHizKA== 0000899078-05-000209.txt : 20050315 0000899078-05-000209.hdr.sgml : 20050315 20050315170436 ACCESSION NUMBER: 0000899078-05-000209 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 22 CONFORMED PERIOD OF REPORT: 20041231 FILED AS OF DATE: 20050315 DATE AS OF CHANGE: 20050315 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DENBURY RESOURCES INC CENTRAL INDEX KEY: 0000945764 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752815171 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-12935 FILM NUMBER: 05682412 BUSINESS ADDRESS: STREET 1: 5100 TENNYSON PARKWAY STREET 2: SUITE 3000 CITY: PLANO STATE: TX ZIP: 75024 BUSINESS PHONE: 9726732000 MAIL ADDRESS: STREET 1: 5100 TENNYSON PARKWAY STREET 2: SUITE 3000 CITY: PLANO STATE: TX ZIP: 75024 FORMER COMPANY: FORMER CONFORMED NAME: NEWSCOPE RESOURCES LTD DATE OF NAME CHANGE: 19950627 10-K 1 fy2004-form10k.txt FORM 10-K, FY 2004
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 2004 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, 2004 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 20-0467835 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 5100 Tennyson Parkway, Suite 3000, Plano, TX 75024 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (972) 673-2000 Securities registered pursuant to Section 12(b) of the Act: ==================================================================================================== Title of Each Class Name of Each Exchange on Which Registered Common Stock $.001 Par Value New York Stock Exchange ==================================================================================================== Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark 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 June 30, 2004, the aggregate market value of the registrant's Common Stock held by non-affiliates was approximately $1.1 billion. The number of shares outstanding of the registrant's Common Stock as of February 28, 2005, was 56,612,005. DOCUMENTS INCORPORATED BY REFERENCE Document Incorporated as to 1. Notice and Proxy Statement for the Annual Meeting 1. Part III, Items 10, 11, 12, 13, 14 of Shareholders to be held May 11, 2005.
Denbury Resources Inc. 2004 Annual Report on Form 10-K Table of Contents Page ---- Glossary and Selected Abbreviations............................ 3 PART I Item 1. Business....................................................... 4 Item 2. Properties..................................................... 22 Item 3. Legal Proceedings.............................................. 22 Item 4. Submission of Matters to a Vote of Security Holders............ 22 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities............ 23 Item 6. Selected Financial Data........................................ 25 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................... 26 Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 46 Item 8. Financial Statements and Supplementary Data.................... 46 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......................... 86 Item 9A. Controls and Procedures........................................ 86 Item 9B. Other Information.............................................. 86 PART III Item 10. Directors and Executive Officers of the Company................ 86 Item 11. Executive Compensation......................................... 87 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters................... 87 Item 13. Certain Relationships and Related Transactions................. 87 Item 14. Principal Accountant Fees and Services......................... 87 PART IV Item 15. Exhibits and Financial Statement Schedules..................... 87 Signatures..................................................... 90 2 Denbury Resources Inc. Glossary and Selected Abbreviations Bbl One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude Oil or other liquid hydrocarbons. Bbls/d Barrels of oil produced per day. Bcf One billion cubic feet of natural gas or CO2. BOE One barrel of oil equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas. BOE/d BOEs produced per day. Btu Btu British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. CO2 Carbon Dioxide. Finding and The average cost per BOE to find and develop proved reserves during a given period. It is Development calculated by dividing costs, which includes the total acquisition, exploration and development Cost costs incurred during the period plus future development and abandonment costs related to the specified property or group of properties, by the sum of (i) the change in total proved reserves during the period plus (ii) total production during that period. MBbls One thousand barrels of crude oil or other liquid hydrocarbons. MBOE One thousand BOEs. MBtu One thousand Btus. Mcf One thousand cubic feet of natural gas or CO2. Mcf/d One thousand cubic feet of natural gas or CO2 produced per day. MCFE One thousand cubic feet of natural gas equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas. MCFE/D MCFEs produced per day. MMBbls One million barrels of crude oil or other liquid hydrocarbons. MMBOE One million BOEs. MMBtu One million Btus. MMcf One million cubic feet of natural gas or CO2. MMCFE One thousand MCFE. MMCFE/D MMCFEs produced per day. PV-10 Value When used with respect to oil and natural gas reserves, PV-10 Value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, and before income taxes, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities and Exchange Commission. Proved Developed Reserves 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 that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved Undeveloped Reserves 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. * This definition is an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X. See www.sec.gov/divisions/corpfin/forms/regsx.htm#gas for the complete definition.
3 Denbury Resources Inc. PART I ITEM 1. BUSINESS - ---------------- WEBSITE ACCESS TO REPORTS We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934 available free of charge on or through our internet website, www.denbury.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. THE COMPANY Denbury Resources Inc. is a Delaware corporation, organized under Delaware General Corporation Law ("DGCL") 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 the Barnett Shale in Texas. Our corporate headquarters is located at 5100 Tennyson Parkway, Suite 3000, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2004, we had 380 employees, 243 of which were employed in field operations or at the field offices. Our employee count does not include the approximately 200 employees of Genesis Energy, Inc. as of December 31, 2004 as its employees exclusively carry out the business activities of Genesis Energy, L.P., which we do not consolidate in our financial statements (See Note 1 to the Consolidated Financial Statements). INCORPORATION AND ORGANIZATION Denbury was originally incorporated in Canada in 1951. In 1992, we acquired all of the shares of a United States operating company, Denbury Management, Inc. ("DMI"), and subsequent to the merger we sold all of its Canadian assets. Since that time, all of our operations have been in the United States. In April 1999, our stockholders approved a move of our corporate domicile from Canada to the United States as a Delaware corporation. Along with the move, our wholly owned subsidiary, DMI, was merged into the new Delaware parent company, Denbury Resources Inc. This move of domicile did not have any effect on our operations or assets. Effective December 29, 2003, Denbury Resources Inc. changed its corporate structure to a holding company format. The purposes of creating the holding company structure were to better reflect the operating practices and methods of Denbury, to improve its economics, and to provide greater administrative and operational flexibility. As part of this restructure, Denbury Resources Inc. (predecessor entity) merged into a newly formed limited liability company, and survived as, Denbury Onshore, LLC, a Delaware limited liability company and an indirect subsidiary of the newly formed holding company, Denbury Holdings, Inc. Denbury Holdings, Inc. subsequently assumed the name Denbury Resources Inc. (new entity). The reorganization was structured as a tax free reorganization to Denbury's stockholders and all outstanding capital stock of the original public company was automatically converted into the identical number of and type of shares of the new public holding company. Stockholders' ownership interests in the business did not change as a result of the new structure and shares of the Company remain publicly traded under the same symbol (DNR) on the New York Stock Exchange. The new parent holding company is co-obligor (or guarantor, as appropriate) regarding the payment of principal and interest on Denbury's outstanding debt securities. BUSINESS STRATEGY As part of our corporate strategy, we believe in the following fundamental principles: o remain focused in specific regions; 4 Denbury Resources Inc. o acquire properties where we believe additional value can be created through a combination of exploitation, development, exploration and marketing, including secondary and tertiary operations; o acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it; o maximize the value of our properties by increasing production and reserves while reducing cost; and o maintain a highly competitive team of experienced and incentivized personnel. ACQUISITIONS Information as to recent acquisitions and divestitures by Denbury is set forth under Note 2, "Acquisitions and Divestitures," to the Consolidated Financial Statements. OIL AND GAS OPERATIONS Our CO2 Assets Just over five years ago, we started a new focus area through an acquisition of a carbon dioxide ("CO2") tertiary flood in an area very familiar to us, Mississippi. We have subsequently acquired other related assets and are making that focus area the major part of our business. We particularly like this tertiary play as (i) it is lower risk and more predictable than most traditional exploration and development activities, (ii) it provides a reasonable rate of return at relatively low oil prices (low to mid twenties), and (iii) we have virtually no competition for this type of activity in our current geographic area. Generally, from East Texas to Florida, there are no known natural sources of carbon dioxide except our own, and these large volumes of CO2 that we own drive the play. Our CO2 comes from an old underground volcano located near Jackson, Mississippi, discovered in the 1960s while companies were drilling for oil and natural gas. These CO2 reserves are found in structural traps in the Haynesville, Buckner, Smackover and Norphlet formations at depths of about 16,000 feet. CO2 injection is one of the most efficient tertiary recovery mechanisms for producing crude oil; however, because it requires large quantities of CO2, its use has been restricted to West Texas, Mississippi and other isolated areas where large quantities of CO2 are available. The CO2 (in liquid form) acts as a type of solvent for the oil, causing the oil to expand and become mobile, allowing the oil to be recovered along with the CO2 as it is produced. The CO2 is then extracted from the oil, compressed back into a liquid state, and re-injected into the reservoir, with this recycling process occurring several times during the life of the tertiary operations. In a typical oil field up to 50% of the oil in place can be extracted during primary and secondary (waterflooding) recovery operations. Through the use of CO2 in tertiary operations, it is possible to recover additional oil (for example, 17% based on historical results at Little Creek), almost as much oil as initially recovered during the primary production phase. We started this play in August 1999, when we acquired our first CO2 tertiary recovery project, Little Creek Field in Mississippi, a project originally developed by Shell Oil Company. Since our acquisition of this field, we have increased oil production here from 1,350 Bbls/d to an average of 2,989 Bbls/d during the fourth quarter of 2004. 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 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 three 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 most of the CO2 supply in Mississippi, as well as ownership and control of a critical 183-mile CO2 pipeline. This acquisition 5 Denbury Resources Inc. provided the platform to significantly expand our CO2 tertiary recovery operations because it assured us that CO2 would be available to us on a reliable basis and at a reasonable and predictable cost. Since February 2001, we have acquired two and drilled seven additional CO2 producing wells, more than tripling our estimated proved CO2 reserves to approximately 2.7 Tcf as of December 31, 2004. The estimate of 2.7 Tcf of proved CO2 reserves is based on 100% ownership of the CO2 reserves, of which Denbury's net ownership is approximately 2.1 Tcf and is included in the evaluation of proven CO2 reserves prepared by DeGolyer & MacNaughton and included as Exhibit 99. In discussing the available CO2 reserves, we make reference to the gross amount of proved reserves, as this is the amount that is available both for Denbury's tertiary recovery programs and for industrial users who are customers of Denbury and others, as Denbury is responsible for distributing the entire CO2 production stream for both of these. Today, we own every producing CO2 well in the region. Although our current proven and potential CO2 reserves are quite large, in order to continue our tertiary development of oil fields in the area, incremental deliverability of CO2 is needed. In order to obtain the additional CO2 deliverability, we plan to drill several additional CO2 wells in the future, including up to four more wells during 2005. 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 properties in this area, the acquisition costs of both of these fields were relatively low in comparison to their significant reserve potential as tertiary recovery projects. As an example, we acquired West Mallalieu Field in May 2001 for $4.0 million, and by year-end 2001 had recognized 10.4 MMBOE of proved reserves, with additional future reserve potential in this field. 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. o In August 2002, we acquired COHO Energy Inc.'s Gulf Coast properties for $48.2 million, which included Brookhaven Field, another significant tertiary flood candidate along our CO2 pipeline. Initial development of the Brookhaven CO2 flood began in late 2004. DeGolyer & MacNaughton has estimated that 18.7 MMBbls of oil reserves can be recovered from Brookhaven field from our CO2 tertiary operations in their December 31, 2004 proved reserve report. o During the fourth quarter of 2004, we sold an average of 69 MMcf/d of CO2 to commercial users and we used an average of 149 MMcf/d for our tertiary activities. We estimate that our current daily CO2 deliverability is approximately 350 MMcf/d, and by year-end 2005 we hope to further increase our CO2 deliverability to between 450 MMcf/d and 500 MMcf/d. We plan to continue our CO2 drilling in 2005 and beyond, as we estimate that we will need up to 700 MMcf/d in the next few years in order to meet the projected timetable for our tertiary projects in Southwest and East Mississippi. During 2004, two of the CO2 wells we drilled tested new structures that increased our CO2 reserves by approximately 1 Tcf of CO2. These wells will be brought online once we install the facilities that are necessary to produce these wells at their maximum rates. With the increase in our CO2 deliverability and reserves, we made the strategic decision to commence with installation of a pipeline to several of our East Mississippi properties, and expect to commence CO2 operations in three East Mississippi fields by mid-2006. As of December 31, 2004, the calculated present value of the remaining industrial sales contracts (using pricing provided in the contracts) discounted at 10% per year was approximately $26.5 million based on the current life of each contract. o In October 2003 and September 2004, we sold 167.5 Bcf and 33.0 Bcf of CO2 to Genesis for $24.9 million and $4.8 million under two separate volumetric production payments. In conjunction with the sale, we included the assignment of four of our existing long-term commercial CO2 supply agreements with our industrial customers. Pursuant to the terms of the volumetric production payments, Genesis has specific maximums on the amount of CO2 they are allowed to take each year, which generally relate to the anticipated volumes of the four industrial customers. We provide Genesis with certain processing and transportation services in connection with these agreements for a fee of approximately $0.16 per Mcf of CO2 delivered to their industrial customers. o During the fourth quarter of 2004, we commenced operations to expand our tertiary program to East Mississippi and have commenced the 6 Denbury Resources Inc. acquisition of leases and right-of-way for the construction of an 84-mile CO2 pipeline from our source wells near Jackson, Mississippi to Eucutta Field in East Mississippi. We believe that this expansion into East Mississippi, labeled Phase II, has significant oil potential beyond the first six fields that we have engineered and plan to flood. Combining the production forecast for both of these areas (Phase I and II) extends the period during which we anticipate significant oil production growth from a few years, for Phase I alone, to five to ten years combined. While it is extremely difficult to accurately forecast future production, we do believe that our tertiary recovery operations provide significant long-term production growth potential at reasonable rates of return, with relatively low risk, and will be the backbone of our Company's growth for the foreseeable future. With anticipated all-in finding and development costs (including future development and abandonment costs) of around $6.00 per BOE and anticipated operating costs of around $10.00 per BOE over the life of each field, our tertiary recovery operations in West Mississippi along our pipeline should provide a reasonable rate of return at oil prices in the low twenties, as they produce light sweet oil that receives near NYMEX pricing. The economics will be a little different in East Mississippi (Phase II) in the following ways: (i) operating costs in East Mississippi are likely to be one to three dollars per BOE higher than it is for those fields along our existing CO2 pipeline, primarily because of the incremental cost of transporting the CO2 to this new area (assuming another party ultimately owns the pipeline and we pay a throughput or transportation fee), (ii) the incremental operating cost may be partially offset by an anticipated lower finding cost, as these East Mississippi fields may not require as many wells to be drilled or re-entered, as more wells are currently active, (iii) there are reservoir related differences, which although not exactly quantified, are expected to improve the overall economics in the eastern area, and (iv) the quality of the oil is different in the two areas. In the eastern part of the state, the oil is generally heavier and usually sour, and thus has a higher negative differential to NYMEX prices, ranging historically from one to six dollars per barrel lower than West Mississippi light sweet oil. During the fourth quarter of 2004, the differentials for these heavier crudes widened to as much as $13 to $16 per barrel, but we expect the differentials to return to their historical levels over time. In summary, while the fields in West Mississippi along our pipeline provide a satisfactory rate of return at NYMEX oil prices in the low twenties, we project that it takes NYMEX oil prices in the mid to high twenties to achieve similar rates of return in East Mississippi. Tentatively, we plan to spend approximately $35 million in 2005 in the Jackson Dome area targeted to add additional CO2 reserves and deliverability for future operations. Approximately $60 million in capital expenditures is budgeted in 2005 for our oil fields with tertiary operations in Southwest Mississippi and approximately $50 million for oil fields in East Mississippi, plus an additional $45 million for the CO2 pipeline to East Mississippi, increasing our combined CO2 and tertiary recovery related expenditures to over 60% of our current 2005 capital budget. Our Tertiary Oil 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, the first two phases were complete and the third phase was in process. We have completed development of the third, fourth and fifth phases and most of the currently planned development work at this field, although we will continue to modify existing patterns and drill wells as necessary to recover the maximum amount of oil or to extend the field into areas that have not benefited from CO2 injection. Currently there are 28 producing wells and 34 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 the flooded portion of the field by approximately 17%, as compared to recoveries of approximately 20% for primary recovery and 18% for secondary recovery. The field has produced a cumulative 16 MMBbls (gross) of light sweet crude, as a result of tertiary operations, and we currently estimate that an additional 6.1 MMBbls (gross) can be recovered. Production from Little Creek Field was approximately 1,350 Bbls/d when we acquired the field in 1999. During the fourth quarter of 2004, production had increased to an average of 2,989 BOE/d (including Lazy Creek). We expect the production from Little Creek to increase further during 2005 by another 150 to 7 Denbury Resources Inc. 250 BOE/d. From inception through December 31, 2004, we had net positive cash flow (revenues less operating expenses and capital expenditures) from Little Creek (including Lazy Creek) of $48.5 million (at the field level), plus the fields have a PV-10 Value, using December 31, 2004 SEC NYMEX pricing, of $122.3 million. We purchased West Mallalieu Field in May 2001. Shell Oil Company unitized West Mallalieu Field and commenced a pilot project in 1986. The pilot project, consisting of four 5-spot patterns, has cumulatively produced approximately 2.1 MMBbls of oil as a result of CO2 flooding. We have expanded the pilot project by adding four additional patterns during 2001, four patterns in 2002, three patterns in 2003, and two patterns in 2004. We also completed our first pattern in East Mallalieu during 2004. During 2002 we began to see initial response to CO2 injection as the West Mallalieu Field averaged 778 Bbls/d during the fourth quarter of 2002. Response continued throughout 2003 and 2004, averaging 3,712 Bbls/d during the fourth quarter of 2004. In contrast to Little Creek Field, West Mallalieu Field was not waterflooded prior to CO2 injection. Therefore, we believe that the tertiary recovery of oil from West Mallalieu Field as a result of CO2 injection could exceed the 17% of original oil in place that we expect from Little Creek Field. We purchased McComb Field in 2002, a field with no pilot programs or tertiary operations at that time and virtually no current oil production. McComb is very close in proximity and analogous to Little Creek and Mallalieu Fields. We commenced tertiary recovery operations in 2003 by substantially completing two patterns, and by November 2003 had started injecting CO2. Significant development occurred during 2004 as we expanded the nearby Olive Field CO2 facility to handle the processing of McComb's produced oil, water and CO2 and developed an additional four patterns. The production response occurred earlier than expected, with the field averaging 540 Bbls/d in the fourth quarter of 2004. During 2005, we expect to add three patterns within McComb Field and further expand the production facilities. In addition, we also started our initial work on an additional CO2 flood at nearby Smithdale Field during 2004 utilizing the same CO2 facilities, with CO2 injections expected to begin in early 2005. We believe that the total potential at McComb and Smithdale Fields is significantly higher than the current proved reserves (at McComb only), and therefore expect to add additional reserves and have upward reserve revisions here over the next several years as we fully develop these fields. Initial development of the Brookhaven Field, a field acquired during 2002 in the COHO acquisition, began in late 2004 with the first injections of CO2 in January 2005. During 2005, we plan to complete development of the two patterns initiated in 2004 and develop an additional seven patterns, but do not expect any significant production response from this field until early 2006. At December 31, 2004, we have proved reserves of 50.5 MMBbls relating to our tertiary recovery operations. Through December 31, 2004, we have spent a total of $155.6 million on fields in this area, and have received $160.0 million in net operating income (revenue less operating expenses), or net positive cash flow of $4.4 million. These amounts do not include the capital costs or related depreciation and amortization of our CO2 producing properties at Jackson Dome, which had a net unrecovered cost balance of $75.4 million as of December 31, 2004. At year-end 2004, the proved oil reserves in our CO2 fields had a PV-10 Value, using December 31, 2004 SEC NYMEX pricing, of $782.9 million. Heidelberg and East Mississippi We own interests in 477 wells in the eastern part of the Mississippi salt basin and operate 436 of these wells (91%) from our regional office in Laurel, Mississippi. These fields produced an average of 10,601 Bbls/d and 17.8 MMcf/d during the fourth quarter of 2004. 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. Since we have generally owned these eastern Mississippi properties longer than properties in our other regions, they tend to be more fully developed. During 2004, we spent a total of approximately $38.4 million (excluding acquisitions), drilling 53 wells and performing various workovers and recompletions. Production in eastern Mississippi averaged 13,085 BOE/d during 2004, down slightly from the 2003 average of 13,638 BOE/d. For 2005, we expect our budget in this region for conventional operations to be a little lower than it was in 2004, approximately $28.6 million, or 9% of our current 2005 exploration and development budget of $305 million (including the 8 Denbury Resources Inc. East Mississippi CO2 pipeline), and as discussed above, we have budgeted an additional $50.2 million to initiate three tertiary recovery projects at Martinville, Soso and Eucutta Fields. 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, recompleting wells, improving production efficiency, and in some cases, by water flooding producing reservoirs. Most of our wells in this area produce large amounts of saltwater and require large pumps, which increase 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 tertiary operations. The largest field in the region, and our largest field corporately, is Heidelberg Field, which for the fourth quarter of 2004 produced an average of 8,266 BOE/d. Heidelberg Field was acquired from Chevron in December 1997. This field was discovered in 1944 and has produced an estimated 204 MMBbls of oil and 57 Bcf of gas since its discovery. The field is a large salt-cored anticline that is divided into western and eastern segments due to subsequent faulting. There are 11 producing formations in Heidelberg Field containing 40 individual reservoirs, with the majority of the past and current production coming from the Eutaw, Selma Chalk and Christmas sands at depths of 3,500 to 5,000 feet. When we acquired the property in 1997, production was approximately 2,800 BOE/d. The primary oil production at Heidelberg is from five waterflood units that produce from the Eutaw formation (at approximately 4,400 feet). These units are generally developed although they will require additional work and capital for the next few years. In addition, Heidelberg is our second 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 to 15 wells each year in 2001, 2002 and 2003, with an additional 24 natural gas wells drilled in 2004, increasing the natural gas production at Heidelberg to an average for 2004 of approximately 13.8 MMcf/d. We believe that there are opportunities to expand the field limits, to continue reducing the well spacing and to stimulate the Upper Selma Chalk to achieve additional gas reserves in the Selma Chalk. We plan to drill 16 additional gas wells here during 2005, including our first horizontal test in the Selma Chalk. Eucutta Field Eucutta Field was purchased from Amerada Hess in 1995. The field is very analogous to Heidelberg field in that the majority of its historical production was produced from the Eutaw formation. Eucutta was unitized for water flooding in 1966 and has gone through several stages of development. During the 1980's, Amerada Hess installed an inverted 5-spot pilot test in the City Bank sand (one of the Eutaw sands) to test the application of CO2 flooding. Although the pilot test only covered approximately 20 acres, the pilot test was successful in recovering an additional 17% of the original oil in place within the pattern. Based on this success, we have designed a CO2 project for the Eucutta Field and plan to build our CO2 facilities and develop three patterns during 2005. Initial injection of CO2 is projected to commence mid-2006, although it could start earlier if our CO2 pipeline to East Mississippi is completed sooner. Soso Field Soso Field was purchased from COHO Resources in 2002. Although this field produces from numerous sands, the majority of our work in 2005 will involve the building of CO2 facilities and establishing two patterns in the Bailey sand and two partial patterns in the Cotton Valley sands. This field has not had any previous CO2 injection or pilot projects. In reviewing Soso Field we studied the Bailey sand which was one of the more prolific reservoirs within the field and exhibited characteristics of a depletion drive reservoir. The Bailey reservoir oil is 43.4 API gravity, similar to our West Mississippi floods, and is at approximately the same depth and has very similar reservoir characteristics, thus we expect the Bailey tertiary flood to perform in a similar manner to our West Mississippi CO2 floods. 9 Denbury Resources Inc. Martinville Field Martinville field was purchased from COHO Resources in 2002. As is the case with all of the East Mississippi fields, Martinville produces from multiple reservoirs. Unlike the majority of our other planned CO2 projects, Martinville does not contain one very large reservoir to CO2 flood, but rather several smaller reservoirs. We have identified three CO2 formations at Martinville on which we plan to initiate CO2 flooding following completion of our East Mississippi CO2 pipeline. The first reservoir to be CO2 flooded is the Mooringsport, which, because it has been waterflooded very successfully, is expected to CO2 flood successfully as well. We plan to install the required CO2 facilities and essentially complete the development of the Mooringsport during 2005. The second reservoir, the Rodessa, has similar reservoir characteristics to the Mooringsport. We expect to initiate injection into the Rodessa with the completion of one injector. The final reservoir is the Wash Fred 8500' reservoir. This reservoir contains a low gravity oil, 15 API, which will clearly not develop miscibility with CO2 at reservoir conditions. Denbury has several fields with similar gravity oils, which like the Wash Fred 8500' have had lower recoveries due to the low gravity oil and a strong water drive which does not drive the oil efficiently. We plan to initiate injection into the Wash Fred 8500' reservoir at the crest of the structure, allow the CO2 to swell the oil, decrease the oil viscosity, and displace the water and oil downward in the reservoir to the producing wells. Successful implemention of a CO2 project in the Wash Fred 8500' reservoir would provide the impetus to look at a whole new set of fields that have historically not been considered for CO2 injection, although there can be no assurance that this technique will be successful or economic. Texas and the Barnett Shale We own about 20,000 acres of leases and working interest in 29 wells in the Fort Worth Basin in North Central Texas that is prospective for natural gas in the Barnett Shale. We currently operate 18 of the producing wells with essentially 100% ownership in most of the remaining development potential. We acquired the majority of this acreage in 2001 and have been working to find the optimum method to drill, complete and produce the Barnett Shale. We drilled six wells in 2001, two in 2002, five in 2003 and 18 in 2004, seven by us and 11 under a farmout arrangement where we retained a 25% working interest. During 2004 we drilled our first three horizontal wells that produced at much higher initial rates and declined slower than our previous vertical wells. As a result of this initial success, we expanded our 2004 capital budget and drilled four additional horizontal wells. The average initial producing rate for these 2004 horizontal wells is approximately 2 MMcf/d. We are still refining our fracturing technique, including an analysis of the best number of fracture treatments to adequately stimulate the entire length of our lateral sections, which can exceed 4,000 feet. Initial reserve estimates for these horizontal wells appear to be 3 to 4 times greater than the vertical wells we initially drilled. Although our production during the fourth quarter of 2004 averaged only 4.4 MMcf/d, we expect production in this area to grow substantially during 2005. During 2005, we plan to drill approximately 25 horizontal wells. Including seismic costs and pipeline infrastructure costs, our planned 2005 capital expenditures in the Barnett Shale is estimated to be $31 million of our $305 million capital budget (including the East Mississippi CO2 Pipeline). During 2004, we also committed the necessary capital to shoot 3-D seismic data over our entire acreage position, 50 to 60 square miles. We received our first seismic data in February 2005 and expect to have the majority of the remaining data by May 2005. The 3-D seismic data should allow us to better locate our wells so that we encounter less faulting and underground sink holes which have been associated with fracture stimulations into zones outside of the Barnett Shale that are typically water bearing. During 2004, we continued to address the issue of pipeline capacity in our area of the Barnett Shale play by installing additional pipelines to relieve some packed lines. The largest gas purchaser in the area is installing a new 20" gas line to handle the increasing volumes of gas in our area. In addition, several other gas buyers and pipeline companies are entering the area and making plans to install additional pipelines to handle the anticipated future volumes of gas. 10 Denbury Resources Inc. South Louisiana We own interests in 84 wells in the land and marshes of south Louisiana and one non-operated offshore well that we did not include in our 2004 sale of offshore properties. We operate 71 of these wells (85%) from our regional office in Houma, Louisiana. This region produces primarily natural gas, averaging 33.7 MMcf/d net to our interest in the fourth quarter of 2004, approximately 60% of our total natural gas production. During 2004, we spent approximately $23.7 million (excluding acquisitions) in this region, approximately 11% of our total exploration and development expenditures, drilling approximately 10 wells, primarily in the Thornwell and Terrebonne Parish areas. For 2005, our spending is expected to be about the same, with a budget of $28.8 million, or 9% of our $305 million exploration and development budget (including our East Mississippi CO2 pipeline). The majority of our onshore Louisiana fields lie in the Houma embayment area of Terrebonne Parish, including Lirette, and South Chauvin Fields, and our recent shallow natural gas plays at Bayou Sauveur and Gibson Fields. 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 1,000 square miles of 3D data, and plan to expand our data ownership during 2005. During 2004, we expanded our seismic holdings in this area by acquiring an additional 188 square miles of 3D data. We drilled seven wells in Terrebonne Parish during 2004, four of which were successful. In 2005, we plan to drill approximately six exploratory wells in Terrebonne Parish and three development wells. Historically we have had good success with a shallow natural gas play in Terrebonne Parish. These shallow gas reservoirs are approximately 3,000 feet deep, but have the ability to produce from 1.0 to 4.0 MMcf/d. During 2004, we drilled one successful and one unsuccessful well. We plan to drill an additional 6 shallow gas prospects in Terrebonne Parish during 2005, with another 5 to 15 additional shallow gas prospects in Terrebonne Parish under review. Thornwell Field is characterized by short-life natural gas properties that have high initial production rates with a good rate of return, but which are depleted in two to three years. The high rates of decline have dramatically impacted our overall production rates the last two years, and are expected to continue to do so throughout 2005. Production at Thornwell Field averaged 4,275 BOE/d in 2001, 3,910 BOE/d in 2002, 2,564 BOE/d in 2003 and 1,487 BOE/d in 2004, and is expected to average approximately 750 BOE/d during 2005. Even though this field has negatively affected our overall production growth, the purchase and development of this field has been profitable. We had significant activity at this field during 2001 and 2002, with positive results, but reduced our activity during 2003 and 2004 as the field became more fully developed. Our plans for 2005 include the drilling of one exploratory well to test the Marg Tex/Bol Mex sands and two development wells in the Bol Perc. From inception through December 31, 2004, we have net positive cash flow (revenue less operating expenses and capital expenditures) to date of $37.0 million from this field, with a remaining proved PV-10 Value, using December 31, 2004 constant SEC NYMEX pricing, of $37.4 million. 11 Denbury Resources Inc. FIELD SUMMARIES Denbury operates in four primary areas: Louisiana, Eastern Mississippi, Western Mississippi and Texas. Our 11 largest fields (listed below) constitute approximately 90% of our total proved reserves on a BOE basis and 89% on a PV-10 Value basis. Within these 11 fields, we own a weighted average 89% working interest and operate all of these fields. The concentration of value in a relatively small number of fields allows us to benefit substantially from any operating cost reductions or production enhancements we achieve and allows us to effectively manage the properties from our two primary field offices in Houma, Louisiana, and Laurel, Mississippi.
Average Daily Proved Reserves as of December 31, 2004 (1) Production (2) -------------------------------------------------------- ---------------------- Natural Average Net Oil Natural Gas MBOE's BOE PV-10 Value Oil Gas Revenue (MBbls) (MMcf) (000's) % of total (000's) (Bbls/d) (Mcf/d) Interest - ---------------------------------------------------------------------------------------- ---------------------- ------------ Mississippi - CO2 floods Brookhaven................... 18,707 - 18,707 14.5% $ 185,962 - - 80.7% Mallalieu (East & West)...... 14,888 - 14,888 11.5% 316,010 3,351 - 80.6% McComb/Olive................. 10,666 - 10,666 8.2% 158,583 285 - 75.1% Little Creek & Lazy Creek.... 6,271 - 6,271 4.8% 122,320 3,148 - 83.2% ---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------ Total Mississippi-CO2 floods 50,532 - 50,532 39.0% 782,875 6,784 - 79.7% ---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------ Other Mississippi Heidelberg (East & West).... 32,577 56,575 42,006 32.5% 364,656 5,476 13,794 76.9% Eucutta..................... 4,485 - 4,485 3.5% 42,391 1,162 - 65.7% King Bee.................... 2,203 - 2,203 1.7% 22,126 460 - 79.9% Brookhaven (non-CO2)........ 1,515 - 1,515 1.2% 25,718 380 - 76.7% Other Mississippi........... 8,047 6,728 9,168 7.1% 98,483 2,991 1,898 10.2% ---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------ Total Other Mississippi... 48,827 63,303 59,377 46.0% 553,374 10,469 15,692 38.1% ---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------ Louisiana Lirette..................... 97 7,029 1,269 1.0% 31,778 300 13,704 61.6% S. Chauvin.................. 372 11,169 2,234 1.7% 47,485 141 3,522 38.7% Thornwell................... 411 6,061 1,421 1.1% 37,437 259 7,367 35.0% Other Louisiana............. 1,048 18,627 4,153 3.2% 90,411 847 11,906 39.9% ---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------ Total Louisiana........... 1,928 42,886 9,077 7.0% 207,111 1,547 36,499 40.7% ---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------ Texas Newark (Barnett Shale)...... - 62,295 10,383 8.0% 99,929 127 2,754 63.1% ---------- ----------- ---------- ----------- ----------- ----------- ---------- ------------ Company Total ................ 101,287 168,484 129,369 100.0% $1,643,289 18,927 54,945 51.5% ========== =========== ========== =========== =========== =========== ========== ============ (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, 2004. The prices at that date were a NYMEX oil price of $43.45 per Bbl adjusted to prices received by field and a NYMEX natural gas price average of $6.15 per MMBtu also adjusted to prices received by field. (2) Does not include production on the Company's offshore properties sold in July 2004. The total average annual production on these properties for 2004 was 319 Bbls/d and 27.3 MMcf/d.
12 Denbury Resources Inc. OIL AND GAS ACREAGE, PRODUCTIVE WELLS, AND DRILLING ACTIVITY In the data below, "gross" represents the total acres or wells in which we own a working interest and "net" represents the gross acres or wells multiplied by Denbury's working interest percentage. For the wells that produce both oil and gas, the well is typically classified as an oil well or gas well based on the ratio of oil to gas production. Oil and Gas Acreage The following table sets forth Denbury's acreage position at December 31, 2004:
Developed Undeveloped Total -------------------------- -------------------------- -------------------------- Gross Net Gross Net Gross Net ------------- ------------ ------------ ------------ ------------ ------------ Louisiana........... 39,867 31,214 25,686 19,440 65,553 50,654 Mississippi......... 92,038 71,416 256,734 36,647 348,772 108,063 Texas, other........ 15,353 10,043 92,478 18,855 107,831 28,898 ------------- ------------ ------------ ------------ ------------ ------------ Total............ 147,258 112,673 374,898 74,942 522,156 187,615 ============= ============ ============ ============ ============ ============
Denbury's net undeveloped acreage that is subject to expiration over the next three years is approximately 7% in 2005, 11% in 2006 and 9% in 2007. Productive Wells The following table sets forth our gross and net productive oil and natural gas wells at December 31, 2004:
Producing Natural Producing Oil Wells Gas Wells Total -------------------------- -------------------------- ------------------------- Gross Net Gross Net Gross Net ------------ ------------- ------------ ------------- ------------ ------------ Operated Wells: Louisiana................ 32 25.7 39 30.9 71 56.6 Mississippi.............. 441 422.0 104 94.1 545 516.1 Offshore Gulf Coast...... - - - - - - Texas, other............. - - 18 17.0 18 17.0 ------------ ------------- ------------ ------------- ------------ ------------ Total.................. 473 447.7 161 142.0 634 589.7 ============ ============= ============ ============= ============ ============ Non-Operated Wells: Louisiana................ - - 13 3.4 13 3.4 Mississippi.............. 24 2.4 17 5.2 41 7.6 Offshore Gulf Coast...... - - 1 0.8 1 0.8 Texas, other............. - - 11 2.8 11 2.8 ------------ ------------- ------------ ------------- ------------ ------------ Total.................. 24 2.4 42 12.2 66 14.6 ============ ============= ============ ============= ============ ============ Total Wells: Louisiana................ 32 25.7 52 34.3 84 60.0 Mississippi.............. 465 424.4 121 99.3 586 523.7 Offshore Gulf Coast...... - - 1 0.8 1 0.8 Texas, other............. - - 29 19.8 29 19.8 ------------ ------------- ------------ ------------- ------------ ------------ Total.................. 497 450.1 203 154.2 700 604.3 ============ ============= ============ ============= ============ ============
13 Denbury Resources Inc. Drilling Activity The following table sets forth the results of our drilling activities over the last three years:
Year Ended December 31, -------------------------------------------------------------------------------- 2004 2003 2002 -------------------------- -------------------------- -------------------------- Gross Net Gross Net Gross Net ------------ ------------ ------------ ------------- ------------ ------------- Exploratory Wells:(1) Production(2) 8 5.8 7 5.3 7 4.9 Non-productive(3) 4 2.3 7 4.8 4 3.2 Development Wells:(1) Productive(2) 68 53.8 37 31.3 33 27.1 Non-productive(3)(4) 1 0.6 3 1.2 2 1.9 ------------ ------------ ------------ ------------- ------------ ------------- Total 81 62.5 54 42.6 46 37.1 ============ ============ ============ ============= ============ ============= (1) An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A developmental well is a well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir. (2) A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. (3) A nonproductive well is an exploratory or development well that is not a producing well. (4) During 2004, 2003 and 2002, an additional 8, 5, and 9 wells, respectively, were drilled for water or CO2 injection purposes.
PRODUCTION AND UNIT PRICES Information regarding average production rates, unit sale prices and unit costs per BOE are set forth under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Operating Income" included herein. TITLE TO PROPERTIES Customarily in the oil and gas industry, only a perfunctory title examination is conducted at the time properties believed to be suitable for drilling operations are first acquired. Prior to commencement of drilling operations, a thorough drill site title examination is normally conducted, and curative work is performed with respect to significant defects. During acquisitions, title reviews are performed on all properties; however, formal title opinions are obtained on only the higher value properties. We believe that we have good title to our oil and natural gas properties, some of which are subject to minor encumbrances, easements and restrictions. GEOGRAPHIC SEGMENTS All of our operations are in the United States. 14 Denbury Resources Inc. SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING Oil and gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The loss of any single purchaser would not be expected to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive. For the year ended December 31, 2004, we had two purchasers that each accounted for 10% or more of our oil and natural gas revenues: Hunt Refining (21%) and Genesis Energy, L.P. (14%). For the year ended December 31, 2003, two purchasers each accounted for more than 10% of our total oil and natural gas revenues: Hunt Refining (15%) and Genesis Energy, L.P. (12%). For the year ended December 31, 2002, two purchasers each accounted for 10% or more of our oil and natural gas revenues: Hunt Refining (14%) and Genesis Energy, L.P. (11%). Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the proximity of our gas production to pipelines, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation. Our production is primarily from developed fields close to major pipelines or refineries and established infrastructure. As a result, we have not experienced any difficulty to date in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to market all of our production or obtain favorable prices. Oil Marketing The quality of our crude oil varies by area as well as the corresponding price received. In Heidelberg Field, our single largest field, and our other Eastern Mississippi properties, our oil production is primarily light to medium sour crude and sells at a significant discount to the NYMEX prices. In Western Mississippi, our current CO2 operations, and in Louisiana, our oil production is primarily light sweet crude, which typically sells at near NYMEX prices, or often at a premium. For the year ended December 31, 2004, the discount for our oil production from Heidelberg Field averaged $9.80 per Bbl and for our Eastern Mississippi properties as a whole the discount averaged $8.84 per Bbl relative to NYMEX oil prices. For Mallalieu Field, the largest producer during 2004 of our CO2 properties in Western Mississippi, we averaged a premium of $1.20 per Bbl over NYMEX oil prices, and $1.13 per Bbl over NYMEX prices for our tertiary oil production in Western Mississippi taken as a whole. Our Louisiana properties averaged $2.39 per Bbl below NYMEX prices during 2004. 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. OPERATING ENVIRONMENT RISK FACTORS 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, especially given current world geopolitical conditions. Our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas. This price volatility also affects the amount of our cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow or have outstanding under our bank credit facility is subject to semi-annual redeterminations. In the short-term, our production is relatively balanced between oil and natural gas, but long-term, oil prices are likely to affect us more than natural gas prices because approximately 78% of our proved reserves are oil. The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These factors include: o the level of consumer demand for oil and natural gas; o the domestic and foreign supply of oil and natural gas; 15 Denbury Resources Inc. o the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; o the price of foreign oil and natural gas; o domestic governmental regulations and taxes; o the price and availability of alternative fuel sources; o weather conditions; o market uncertainty; o political conditions in oil and natural gas producing regions, including the Middle East; 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. Also, oil and natural gas prices do not necessarily move in tandem. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect upon our financial condition, results of operations, oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations or make planned expenditures. Since the end of 1998, oil prices have gone from near historic low prices to historic highs. At the end of 1998, NYMEX oil prices were at historic lows of approximately $12.00 per Bbl, but have generally increased since that time, albeit with fluctuations. For 2004, NYMEX oil prices were high throughout the year, averaging over $41.00 per Bbl, ending the year at $43.45 per Bbl. During 2004, the price we received for our heavier, sour crude oil did not correlate as well with NYMEX prices as it has historically. During 2002 and 2003, our average discount to NYMEX was $3.73 per Bbl and $3.60 per Bbl respectively. During 2004, this differential increased to $4.91 per Bbl for the year as a result of the price deterioration for heavier, sour crudes, and was even higher during the fourth quarter, averaging $6.48 per Bbl. While we attempt to obtain the best price for our crude in our marketing efforts, we cannot control these market price swings and are subject to the market volatility for this type of oil. These price differentials relative to NYMEX prices can have as much of an impact on our profitability as does the volatility in the NYMEX oil prices. Natural gas prices have also experienced volatility during the last few years. During 1999 natural gas prices averaged approximately $2.35 per Mcf and, like crude oil, have generally trended upward since that time, although with significant fluctuations along the way. For 2004, NYMEX natural gas prices averaged over $6.00 per MMBtu, ending the year at $6.15 per MMBtu. Product Price Derivative Hedging Contracts To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently and may in the future enter into hedging arrangements for a portion of our oil and natural gas production. Hedging arrangements expose us to risk of financial loss in some circumstances, including when: o production is less than expected; o the counter-party to the hedging contract defaults on its contract obligations (as was the case with respect to our hedges placed in 2001 with an Enron subsidiary as counterparty, which resulted in our suffering a loss); or o there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. 16 Denbury Resources Inc. In addition, these hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. Information as to these activities is set forth under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Management," and in Note 9, "Derivative Hedging Contracts," to the Consolidated Financial Statements. 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. 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 limits, or, as in the case of environmental fines and penalties, cannot be insured. We could incur significant costs, related to these risks, that could have a material adverse effect on our results of operations, financial condition and cash flows. Use of Carbon Dioxide in Tertiary Recovery Operations The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of carbon dioxide. Our ability to produce this oil would be hindered if our supply of carbon dioxide were limited due to problems with our current CO2 producing wells and facilities, including compression equipment, or catastrophic pipeline failure. Our anticipated future 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. 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 17 Denbury Resources Inc. historically replaced reserves through both drilling and acquisitions. In the future we may not be able to continue to replace reserves at acceptable costs. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investment to maintain or expand our oil and natural gas reserves if our cash flows from operations are reduced, due to lower oil or natural gas prices or otherwise, or if external sources of capital become limited or unavailable. Further, the process of using CO2 for tertiary recovery and the related infrastructure requires significant capital investment, often one to two years prior to any resulting production and cash flows from these projects, heightening potential capital constraints. If we do not continue to make significant capital expenditures, or if outside capital resources become limited, we may not be able to maintain our growth rate. In addition, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves will be 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. We are continually identifying and evaluating acquisition opportunities and we have successfully completed acquisitions throughout our history. 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 our business, including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and obtaining goods, services and labor. Many of our competitors have substantially larger financial and other resources. Factors that affect our ability to acquire producing properties include available funds, available information about prospective properties and our standards established for minimum projected return on investment. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. Because of the long-lived, high margin nature of our oil and gas reserves and management's experience and expertise in exploiting these reserves, we believe that we are effective in competing in the market. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. We cannot be certain when we will experience these issues and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results or restrict our ability to drill those wells and conduct those operations that we currently have planned and budgeted. FEDERAL AND STATE REGULATIONS Numerous federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance. The following section describes some specific laws and regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives. Management believes that we are in substantial compliance with all laws and regulations applicable to our operations and that continued compliance with existing requirements will not have a material adverse impact on us. The future annual capital costs of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including 18 Denbury Resources Inc. future changes to regulatory requirements. However, management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations. Regulation of Natural Gas and Oil Exploration and Production Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled in those units and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability. Federal Regulation of Sales Prices and Transportation The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the U.S. federal government and are affected by the availability, terms and cost of transportation. In particular, the price and terms of access to pipeline transportation are subject to extensive U.S. federal and state regulation. The Federal Energy Regulatory Commission ("FERC") is continually proposing and implementing new rules and regulations affecting the natural gas industry. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. The ultimate impact of the complex rules and regulations issued by FERC cannot be predicted. Some of FERC's proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. While our sales of crude oil, condensate and natural gas liquids are not currently subject to FERC regulation, our ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective and their effect, if any, on our operations. Historically, the natural gas industry has been heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC, Congress and the states will continue indefinitely into the future. Natural Gas Gathering Regulations State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Federal, State or Indian Leases Our operations on federal, state or Indian oil and gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service ("MMS") and other agencies. Environmental Regulations Public interest in the protection of the environment has increased dramatically in recent years. Our oil and natural gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials are subject to stringent regulation. We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures. 19 Denbury Resources Inc. 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"). Management believes that we are in substantial compliance with applicable environmental laws and regulations. To date, we have not expended any material amounts to comply with such regulations, and management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows. ESTIMATED NET QUANTITIES OF PROVED OIL AND GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas, prepared estimates of our net proved oil and natural gas reserves as of December 31, 2004, 2003 and 2002. The reserve estimates were prepared using constant prices and costs in accordance with the guidelines of the Securities and Exchange Commission ("SEC"). The prices used in preparation of the reserve estimates were based on the market prices in effect as of December 31 of each year, with the appropriate adjustments (transportation, gravity, basic sediment and water "BS&W," purchasers' bonuses, Btu, etc.) applied to each field. The reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interests in our properties. Our proved nonproducing reserves primarily relate to reserves that are to be recovered from productive zones that are currently behind pipe. Since a majority of our properties are in areas with multiple pay zones, these properties typically have both proved producing and proved nonproducing reserves. Proved undeveloped reserves associated with our CO2 tertiary operations in West Mississippi and our Heidelberg waterfloods in East Mississippi account for approximately 96% of our proved undeveloped oil reserves. We consider these reserves to be lower risk than other proved undeveloped reserves that require drilling at locations offsetting existing production because all of these proved undeveloped reserves are associated with secondary recovery or tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under primary production. The main reason these reserves are classified as undeveloped is because they require significant additional capital associated with drilling/re-entering wells or additional facilities in order to produce the reserves and/or are waiting for a production response to the water or CO2 injections. 20 Denbury Resources Inc. Our proved undeveloped natural gas reserves, associated with our Selma Chalk play at Heidelberg and the Barnett Shale play in Newark, East fields account for approximately 87% of our proved undeveloped natural gas reserves. The remaining undeveloped natural gas reserves are spread over multiple fields with the single largest field accounting for less than 5% of the total undeveloped natural gas reserves. This particular field's undeveloped reserves are currently being developed with first production expected late in the first quarter of 2005. Our current plans for 2005 include development of 20 to 25 wells in each of our primary natural gas plays, the Barnett Shale and Selma Chalk.
Year Ended December 31, - ----------------------------------------------------------------------------------------------------------------- 2004 2003 2002 ---------------- --------------- ---------------- ESTIMATED PROVED RESERVES: Oil (MBbls).................................................. 101,287 91,266 97,203 Natural gas (MMcf)........................................... 168,484 221,887 200,947 Oil equivalent (MBOE)........................................ 129,369 128,247 130,694 PERCENTAGE OF TOTAL MBOE: Proved producing............................................. 39% 43% 43% Proved non-producing......................................... 16% 18% 23% Proved undeveloped........................................... 45% 39% 34% REPRESENTATIVE OIL AND GAS PRICES:(1) Oil - NYMEX.................................................. $ 43.45 $ 32.52 $ 31.20 Natural gas - NYMEX Henry Hub................................ 6.15 6.19 4.79 PRESENT VALUES:(2) Discounted estimated future net cash flow before income taxes ("PV-10 Value") (thousands)................... $ 1,643,289 $ 1,566,371 $ 1,426,220 Standardized measure of discounted estimated future net cash flow after income taxes (thousands)................... 1,129,196 1,124,127 1,028,976 (1) The prices of each year-end were based on market prices in effect as of December 31 of each year, NYMEX prices per Bbl and NYMEX Henry Hub prices per MMBtu, with the appropriate adjustments (transportation, gravity, BS&W, purchasers' bonuses, Btu, etc.) applied to each field to arrive at the appropriate corporate net price. (2) Determined based on year-end unescalated prices and costs in accordance with the guidelines of the SEC, discounted at 10% per annum.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control. 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. See also Note 13, "Supplemental Oil and Natural Gas Disclosures," to the Consolidated Financial Statements. You should not assume that the present values referred to herein represent 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 costs as of the date of the estimate. Quantities of proved reserves are estimated based on economic conditions, including oil and natural gas prices in existence at the date of assessment. Our 21 Denbury Resources Inc. reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs and other factors. Downward revisions of our reserves could have an adverse affect on our financial condition, operating results and cash flows. ITEM 2. PROPERTIES - -------------------- See Item 1. Business - "Oil and Gas Operations." We also have various operating leases for rental of office space, office and field equipment, and vehicles. See "Off-Balance Sheet Agreements - Commitments and Obligations" in Management's Discussion and Analysis of Financial Condition and Results of Operations, and Note 10, "Commitments and Contingencies," to the Consolidated Financial Statements for the future minimum rental payments. Such information is incorporated herein by reference. ITEM 3. LEGAL PROCEEDINGS - -------------------------- We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses, including those noted below. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position or overall trends in results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that we may have a range of legal exposure that would require accrual. The estimate of the potential impact from the following legal proceedings on our financial position or overall results of operations could change in the future. Along with two other companies, we have been named in a lawsuit styled J. Paulin Duhe, Inc. vs. Texaco, Inc., et al, Cause No. 101,227, filed in late 2003 in the 16th Judicial District Court, Division "E", Terrebonne Parish, Louisiana, seeking restoration to its original condition of property on which oil has been produced over the past 70 years. The contract and tort claims by the plaintiffs allege surface and groundwater damage of 26 acres that are part of our Iberia Field in Iberia Parish, Louisiana. Recently, plaintiff's experts have initially alleged that clean-up of alleged contamination of the property would cost $79.0 million, although settlement offers by plaintiffs have already been made for much smaller sums. The property was originally leased to Texaco, Inc. for mineral development in 1934 and Denbury acquired its interest in the property in August 2000 from Manti Operating Company. Discovery is currently underway, and the April 2005 trial setting has been continued to an unspecified date in the future. We believe that we are indemnified by the prior owner, which we expect to cover our exposure to most damages, if any, found to have occurred prior to the time that we purchased the property. We believe that the allegations of this lawsuit are subject to a number of defenses, are without merit and we and the other defendants plan to vigorously defend this lawsuit, and if necessary, we will seek indemnification from the prior owner. On December 29, 2003, an action styled Harry Bourg Corporation vs. Exxon Mobil Corporation, et al, Cause No. 140749, was filed in the 32nd Judicial District Court, Terrebonne Parish, Louisiana against Denbury and eleven other oil companies and their predecessors alleging damage as the result of mineral exploration activities conducted by these oil and gas operators/companies over the last 60 years. Plaintiff has asked for restoration of the 10,000 acre property and/or damages in claims made under tort law and various oil and gas contracts. The Bourg Corporation recently produced its first preliminary expert reports that allege damages of approximately $100.0 million against Denbury. Discovery is continuing in this case, with trial currently set for January 2006. We believe the allegations of this lawsuit are without merit and plan to vigorously defend this lawsuit along with the other defendants. No provision has been accrued in our financial statements. 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 2004. 22 Denbury Resources Inc. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND - ------------------------------------------------------------------------------- ISSUER PURCHASES OF EQUITY SECURITIES - ------------------------------------- Common Stock Trading Summary The following table summarizes the high and low reported sales prices on days in which there were trades of Denbury's common stock on the New York Stock Exchange ("NYSE"), for each quarterly period for the last two fiscal years. As of February 28, 2005, to the best of our knowledge, Denbury's common stock was held of record by approximately 8,000 holders. On February 28, 2005, the last reported sales price of Denbury's Common Stock, as reported on the NYSE, was $32.90 per share.
2004 2003 - ---------------------------------------------- -------------------------- ------------------------- High Low High Low - ---------------------------------------------- ------------ ------------- ------------ ------------ First Quarter $ 16.93 $ 13.26 $ 11.59 $ 10.18 Second Quarter 21.73 16.72 13.86 10.25 Third Quarter 26.20 18.59 13.95 11.65 Fourth Quarter 29.30 24.05 14.24 11.23 - ---------------------------------------------- -------------------------- ------------------------- Annual $ 29.30 $ 13.26 $ 14.24 $ 10.18 - ---------------------------------------------- -------------------------- -------------------------
We have never paid any dividends on our common stock and we currently do not anticipate paying any dividends in the foreseeable future. Also, we are restricted from declaring or paying any cash dividends on our common stock under our bank loan agreement. No unregistered securities were sold by the Company during 2004. Equity Compensation Plan Information The following table summarizes information about Denbury's equity compensation plans as of December 31, 2004.
Number of securities remaining available for future issuance Number of securities to Weighted average under equity be issued upon exercise exercise price of compensation plans of outstanding options, outstanding options, (excluding securities warrants and rights warrants and rights reflected in column a) Plan Category (a) (b) (c) - ---------------------------------------- ------------------------- ------------------------- ------------------------- Equity Compensation plans approved by security holders: Stock Option Plan..................... 4,440,157 $ 10.49 710,291 2004 Omnibus Plan..................... - - 1,350,000 Employee Stock Purchase Plan.......... - - 291,376 Equity compensation plans not approved by security holders: Director Compensation Plan............ - - 71,930 ------------------------- ------------------------- ------------------------- 4,440,157 $ 10.49 2,423,597 ========================= ========================= =========================
23 Denbury Resources Inc. Our Director Compensation Plan was adopted effective July 1, 2000 for a term of ten years. The Director Plan allows each non-employee director to make an annual election to receive his or her compensation in either cash or in shares of our common stock and to elect to defer receipt of such compensation, if they wish. We anticipate that the Director Plan will be modified in 2005 to no longer allow directors to defer receipt of such compensation due to the American Jobs Creation Act of 2004. The number of shares issued to a director who elects to receive shares of common stock under the Director Plan is calculated by dividing the director fees to be paid to such director by the average price of the Company's common stock for the ten trading days prior to the date the fees are payable. Generally director's fees are paid quarterly. We have reserved 100,000 shares for issuance under the Director Plan, for directors who elect to receive their compensation in stock. Purchases of Equity Securities by the Issuer and Affiliated Purchasers The following table summarizes the Company's purchases of stock in the open market during the three months ended December 31, 2004:
ISSUER PURCHASES OF EQUITY SECURITIES - --------------------------------------------------------------------------------------------------- (c) Total Number of (d) Maximum Number (a) Total Shares Purchased of Shares that May Number of (b) Average as Part of Publicly Yet Be Purchased Shares Price Paid Announced Plans or Under the Plan Or Period Purchased per Share Programs Programs - --------------------------------------------------------------------------------------------------- October 2004.......... 50,000 $ 25.28 50,000 100,000 November 2004......... - - - 100,000 December 2004......... - - - 100,000 ------------ ------------------ Total............... 50,000 $ 25.28 50,000 100,000 ============ ==================
In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase shares of our common stock on the NYSE in order for such repurchased shares to be reissued to our employees who participate in Denbury's Employee Stock Purchase Plan. The Plan originally provided for purchases through an independent broker of 50,000 shares of Denbury's common stock per fiscal quarter for a period of approximately twelve months, or a total of 200,000 shares, beginning August 13, 2003 and ending on July 31, 2004. In May 2004, the Board of Directors renewed the Plan for another year beginning July 1, 2004 and ending June 30, 2005, covering another 200,000 shares at the same 50,000 shares per quarter rate. Purchases are to be made at prices and times determined at the discretion of the independent broker, provided however that no purchases may be made during the last ten business days of a fiscal quarter. 24 Denbury Resources Inc. ITEM 6. SELECTED FINANCIAL DATA - --------------------------------
(In thousands, unless otherwise noted) Year Ended December 31, - ------------------------------------------------------------------------------------------------------------------------------ 2004(1) 2003 2002 2001(1) 2000 --------------- -------------- --------------- -------------- ------------- CONSOLIDATED STATEMENTS OF OPERATIONS DATA: Revenues................................. $ 382,972 $ 333,014 $ 285,152 $ 285,111 $ 181,651 Net income............................... 82,448 56,553 (2) 46,795 56,550 142,227 (3) Net income per common share: Basic.................................. 1.50 1.05 (2) 0.88 1.15 3.10 Diluted................................ 1.44 1.02 (2) 0.86 1.12 3.07 Weighted average number of common shares outstanding: Basic ................................. 54,871 53,881 53,243 49,325 45,823 Diluted................................ 57,301 55,464 54,365 50,361 46,352 CONSOLIDATED STATEMENTS OF CASH FLOW DATA: Cash provided by (used by): Operating activities................... $ 168,652 $ 197,615 $ 159,600 $ 185,047 $ 95,972 Investing activities................... (71,700) (135,878) (171,161) (318,830) (133,040) Financing activities................... (66,251) (61,489) 12,005 134,986 47,593 PRODUCTION (DAILY): Oil (Bbls)............................. 19,247 18,894 18,833 16,978 15,219 Natural gas (Mcf)...................... 82,224 94,858 100,443 85,238 37,078 BOE (6:1).............................. 32,951 34,704 35,573 31,185 21,399 UNIT SALES PRICE (EXCLUDING HEDGES): Oil (per Bbl).......................... $ 36.46 $ 27.47 $ 22.36 $ 21.34 $ 25.89 Natural gas (per Mcf).................. 6.24 5.66 3.31 4.12 4.45 UNIT SALES PRICE (INCLUDING HEDGES): Oil (per Bbl).......................... $ 27.36 $ 24.52 $ 22.27 $ 21.65 $ 23.50 Natural gas (per Mcf).................. 5.57 4.45 3.35 4.66 3.57 COSTS PER BOE: Lease operations....................... $ 7.22 $ 7.06 $ 5.48 $ 4.84 $ 4.94 Production and severance taxes......... 1.55 1.17 0.92 0.96 1.02 General and administrative............. 1.78 1.20 0.96 0.89 1.09 Depletion, depreciation, and amortization......................... 8.09 7.48 7.26 6.27 4.62 PROVED RESERVES: Oil (MBbls)............................ 101,287 91,266 97,203 76,490 70,667 Natural gas (MMcf)..................... 168,484 221,887 200,947 198,277 100,550 MBOE (6:1)............................. 129,369 128,247 130,694 109,536 87,425 CONSOLIDATED BALANCE SHEET DATA: Total assets........................... $ 992,706 $ 982,621 $ 895,292 $ 789,988 $ 457,379 Total long-term liabilities............ 368,128 434,845 432,616 360,882 202,428 Stockholders' equity(4)................ 541,672 421,202 366,797 349,168 216,165 (1) We sold Denbury Offshore, Inc. in July 2004. We acquired Matrix Oil and Gas Inc. in July 2001. (2) In 2003, we recognized a gain of $2.6 million for the cumulative effect adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." The adoption of SFAS No. 143 increased basic and diluted net income per common share by $0.05. (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. (4) We have never paid any dividends on our common stock.
25 Denbury Resources Inc. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS - ------------------------------------------------------------------------------- OF OPERATIONS - ------------- We are a growing independent oil and gas company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas producer in Mississippi, own the largest reserves of carbon dioxide ("CO2") used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage onshore Louisiana and in the Barnett Shale play in Texas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, including secondary and tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have two primary field offices located in Houma, Louisiana, and Laurel, Mississippi. OVERVIEW CONTINUED EXPANSION OF OUR TERTIARY OPERATIONS. Since we acquired our first carbon dioxide tertiary flood in Mississippi over five years ago, we have gradually increased our emphasis on these types of operations. We particularly like this play because of its risk profile, rate of return and lack of competition in our operating area. Generally, from East Texas to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of CO2 that we own drive the play. Please refer to the section entitled "CO2 Operations" for further information regarding these operations, their potential, and the ramifications of this change in focus. During the last few years, we have gradually increased the percentage of our spending dedicated to CO2 and tertiary related operations. During 2002 and 2003, we spent around 25% of our capital budget on tertiary related items, spent approximately 46% during 2004, and we further emphasized this part of our business by budgeting over 60% of our initial 2005 capital budget for tertiary operations. We plan to spend approximately $190 million during 2005 on tertiary operations, including an estimated $45 million for an 84-mile pipeline to transport CO2 from our CO2 source fields located near Jackson, Mississippi to our planned tertiary recovery operations in East Mississippi, an expenditure that may ultimately be financed with sources other than our cash flow. We anticipate that the pipeline will be ready for use during the first half of 2006 to commence what we call Phase II (operations in East Mississippi) of our tertiary recovery program (see "CO2 Operations"). Phase II will initially consist of tertiary recovery operations at six oil fields in that region, but we ultimately plan to expand these operations to several other oil fields in the area, which would also be serviced by the new pipeline. Our focus on CO2 tertiary related operations is expected to impact our financial results and certain operating statistics. See "Results of Operations - CO2 Operations - Financial Statement Impact of CO2 Operations" below. During 2004, we drilled four CO2 wells which added an estimated 1.0 Tcf of proved CO2 reserves, resulting in total proved CO2 reserves at December 31, 2004 of approximately 2.7 Tcf (2.1 Tcf to our net ownership - see "CO2 Operations - CO2 Resources"). We anticipate that year-end 2004 proved CO2 reserves will be sufficient to satisfy the projected CO2 requirements for our first two tertiary operation phases, Phase I, our tertiary operations in Southwest Mississippi, and Phase II, our recently planned expansion into Eastern Mississippi. Following the sale of our offshore operations in July 2004, we updated our development schedule and targeted oil production from these tertiary recovery operations. Based on our current plans, we anticipate that we can continue to show significant growth in our oil production from tertiary operations for the next five to ten years from our planned Phase I and Phase II operations. The model assumes that the first production from tertiary recovery operations in Eastern Mississippi will occur in 2007. During 2004, oil production from our tertiary recovery operations averaged 6,784 BOE/d, averaging 7,242 BOE/d during the fourth quarter. SALE OF OFFSHORE OPERATIONS. On July 20, 2004, we closed the sale of Denbury Offshore, Inc., a subsidiary that held our offshore assets, for $200 million (before adjustments) to Newfield Exploration Company. The sale price was based on the asset value of the offshore assets as of April 1, 2004, which means that the net operating cash flow (defined as revenue less operating expenses and capital expenditures) from these properties which we received between April 1st and closing, as well as expenses of the sale and other contractual adjustments, reduced the purchase price to approximately $187 million. The purchaser also received the net working capital of Denbury Offshore as of the closing date, which primarily consisted of accrued production receivables. 26 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations We excluded two significant items from the sale: (i) a discovery well drilled at High Island A-6 during 2004 and (ii) certain deep rights at West Delta 27. The well at High Island A-6 should be on production during the first half of 2005, and we sold a substantial portion of the deep rights at West Delta 27 during the third quarter of 2004 for $1.8 million but retained a carried interest in a deep exploratory well. Our offshore properties made up approximately 12% of our year-end 2003 proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented approximately 25% (9,114 BOE/d) of our 2004 second quarter production. OPERATING RESULTS. As a result of the sale of our offshore properties early in the third quarter of 2004, our total production was significantly reduced, contributing to a 5% decline in production levels during 2004 as compared to 2003 levels. However, higher commodity prices more than offset the lower production, resulting in net income of $82.4 million during 2004 as compared to $56.6 million of net income during 2003. The increase in adjusted cash flow from operations during 2004 was less significant (5%) primarily due to the $21.0 million of income taxes paid relating to the sale of our offshore properties. See "Results of Operations - Operating Income" for discussion of this non-GAAP measure versus cash flow from operations, which decreased by 15% between the two periods. Payments on our commodity hedges continued to be a significant outflow, totaling $84.6 million for 2004, up from $62.2 million during 2003. Hedge payments should drop significantly during 2005 as most of our out-of-the-money hedges expired at December 31, 2004. See "Results of Operations" for a more thorough discussion of our operating results and "Market Risk Management" for more information regarding our hedge position at year-end 2004 and our new method of accounting for hedges for 2005. CAPITAL RESOURCES AND LIQUIDITY For 2005, our initial capital budget, excluding any potential acquisitions, is $305 million, which at commodity futures prices as of the end of February 2005 will be slightly more than anticipated cash flow from operations. That budget includes an estimated $45 million for a CO2 pipeline being constructed to East Mississippi (see "Expansion of our tertiary operations" under "Overview" above), which we may refinance upon completion by entering into some sort of long-term financing, effectively paying for the cost of the pipeline over time and recouping the cash spent. We monitor our capital expenditures on a regular basis, adjusting them up or down depending on commodity prices and the resultant cash flow. Therefore, during the last few years as commodity prices have increased, we have often increased our capital budget during the year and would likely do so again if commodity prices remain strong or increase further. At year-end 2004, we had approximately $70 million in cash and short-term investments remaining from the sale of our offshore properties, over and above our normal month-end cash balances. We plan to invest this remaining cash and any cash potentially generated from operations in excess of our capital budget (such amount being highly dependent on commodity prices) over the next one to two years on property acquisitions, particularly those that have future tertiary potential. Although we now control most of the fields along our existing CO2 pipeline, there are several fields in East Mississippi that could be acquired to expand our planned tertiary operations there, plus we are continuing to seek additional interests in the fields that we currently own. Further, we would like to add additional phases or areas of tertiary operations by acquiring other old oil fields in other parts of our region of operations, building a CO2 pipeline to those areas and initiating additional tertiary floods. We accelerated the pace and expenditures on our tertiary operations following the offshore sale, and plan to continue to do so as long as it remains economic and practical. We also may seek conventional development and exploration projects in our areas of operations or tertiary operations in other areas of the country. In addition to our cash and short-term investments which may be used for the potential aforementioned projects, we have all of our bank credit line available to us if we were to need additional capital. At December 31, 2004, we had outstanding $225 million (principal amount) of 7.5% subordinated notes due in 2013, approximately $4 million of capital lease commitments, no bank debt, and working capital of $90 million. On September 1, 2004, we amended and restated our bank credit agreement which modified the prior agreement by (i) creating a structure wherein the commitment amount and borrowing base amount are no longer the same, (ii) improving our credit pricing by reducing the interest rate chargeable at certain levels of borrowing, (iii) extending the term by three years to April 30, 2009, (iv) reducing the collateral requirements, (v) authorizing up to $20 million of possible future CO2 volumetric production payment transactions with Genesis Energy ($4.8 million of such transactions occurred in October 2004), and (vi) other minor modifications and corrections. Under the new agreement, our borrowing base was initially set at $200 million, a $25 million increase over the prior borrowing base of $175 million, with an initial commitment amount of $100 million. The borrowing base represents the amount we can borrow from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount we have asked the banks to commit to fund pursuant to the terms of 27 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations the credit agreement. The banks have the option to participate in any borrowing request made by us in excess of the commitment amount, up to the borrowing base limit, although they are not obligated to fund any amount in excess of $100 million, the commitment amount. The advantage to us is that we will pay commitment fees on the lower commitment amount, not the higher borrowing base, thus lowering our overall cost of available credit. Sources and Uses of Capital Resources During 2004, we spent $167.0 million on oil and natural gas exploration and development expenditures, $42.4 million on CO2 exploration and development expenditures, and approximately $18.9 million on property acquisitions, for total capital expenditures of approximately $228.3 million. Our exploration and development expenditures included approximately $138.9 million spent on drilling, $18.9 million of geological, geophysical and acreage expenditures and $51.6 million spent on facilities and recompletion costs. We funded these expenditures with $168.7 million of cash flow from operations, with the balance funded with net proceeds from the sale of our offshore properties. We paid back all of our bank debt during the third quarter of 2004 with the offshore sale proceeds, leaving us with approximately $33.0 million of cash and $57.2 million of short-term investments as of December 31, 2004. We also raised $4.8 million during the third quarter of 2004 from the sale of another volumetric production payment of CO2 to Genesis Energy, L.P. ("Genesis"), along with a related long-term CO2 supply agreement with an industrial customer. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed below under "Results of Operations-Operating Results") was $200.2 million for 2004, while cash flow from operations, the GAAP measure, was $168.7 million. During 2003, we generated approximately $197.6 million of cash flow from operations and generated an additional $29.4 million of cash from sales of oil and gas properties. The largest single asset sale was the sale of Laurel Field, acquired from COHO in August 2002, which netted us approximately $25.9 million. Later in the year, we also sold a volumetric production payment to Genesis, which netted us approximately $23.9 million of cash. During 2003, we spent $146.6 million on oil and natural gas exploration and development expenditures, $22.7 million on CO2 capital investments and acquisitions, and approximately $11.8 million on oil and natural gas property acquisitions, for total capital expenditures of approximately $181.1 million. Our exploration and development expenditures included approximately $115.3 million spent on drilling, $15.7 million of geological, geophysical and acreage expenditures and $35.2 million spent on facilities and recompletion costs. In addition, during 2003 we incurred approximately $15.6 million of costs for our subordinated debt refinancing. The $147.3 million of net total expenditures (including the $15.6 million of debt refinancing costs but net of property sales proceeds) was funded by our cash flow from operations, with the balance used to reduce our total debt by approximately $50.0 million. 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, for a total of approximately $172.1 million. 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. OFF-BALANCE SHEET ARRANGEMENTS Commitments and Obligations We have no off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees, other than as disclosed in this section. We have no debt or equity triggers based upon our stock or commodity prices. Our dollar denominated obligations that are not on our balance sheet include our operating leases, which at year-end 2004 totaled $21.6 million relating primarily to the lease financing of certain equipment for our CO2 recycling facilities at our tertiary oil fields. We also have several leases relating to office space and other minor equipment leases. We also have dollar related 28 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations obligations that are not currently recorded on our balance sheet relating to various obligations for development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs forecasted in our proved reserve reports. For a further discussion of our future development costs and proved reserves, see "Results of Operations - Depletion, Depreciation and Amortization." At December 31, 2004, we had a total of $460,000 outstanding in letters of credit. Genesis Energy, Inc., our 100% owned subsidiary which is the general partner of Genesis, has guaranteed the bank debt of Genesis, which consists of $15.3 million of debt and $22.8 million in letters of credit at December 31, 2004. There were no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. at December 31, 2004. We do not have any material transactions with related parties other than sales of production and transportation arrangements with Genesis made in the ordinary course of business, and volumetric production payments of CO2 ("VPP") sold to Genesis as discussed in Note 3 to our Consolidated Financial Statements. A summary of our obligations is presented in the following table:
Payments Due by Period - ---------------------------------------------------------------------------------------------------------------------------- Amounts in Thousands Total 2005 2006 2007 2008 2009 Thereafter - ---------------------------------------------------------------------------------------------------------------------------- Contractual Obligations: - ----------------------- Subordinated debt (a)................. $ 225,000 $ - $ - $ - $ - $ - $ 225,000 Estimated interest payments on Subordinated debt................... 143,438 16,875 16,875 16,875 16,875 16,875 59,063 Operating lease obligations........... 21,582 3,977 3,967 3,954 3,807 3,064 2,813 Capital lease obligations (b)......... 6,807 806 806 806 806 806 2,777 Capital expenditure obligations (c)... 23,752 23,752 - - - - - Other long-term liabilities reflected in our Consolidated Balance Sheet: Derivative liabilities (d) ......... 4,196 4,196 - - - - - Other Cash Commitments: - ----------------------- Future development costs on proved reserves, net of capital obligations (e) 320,988 110,491 84,686 48,809 36,313 14,629 26,060 Asset retirement obligations (f)..... 52,073 2,197 3,016 958 1,593 398 43,911 - ---------------------------------------------------------------------------------------------------------------------------- Total............................... $ 797,836 $ 162,294 $109,350 $ 71,402 $ 59,394 $ 35,772 $ 359,624 ============================================================================================================================ (a) These long-term borrowings and related interest payments are further discussed in Note 6 to the Consolidated Financial Statements. The table assumes that our long-term debt is held until maturity. (b) Represents future minimum cash commitments under capital leases in place at December 31, 2004, primarily for transportation of crude oil and CO2. Agreements are with Genesis. Approximately $2.2 million of these payments represents interest. (c) Represents future minimum cash commitments under contracts in place as of December 31, 2004, primarily for drilling rig services and well related costs. As is common in our industry, we commit to make certain expenditures on a regular basis as part of our ongoing development and exploration program. These commitments generally relate to projects that occur during the subsequent several months and are usually part of our normal operating expenses or part of our capital budget, which for 2005 is currently set at $305 million (including the CO2 pipeline). In addition, we have recurring expenditures for such things as accounting, engineering and legal fees, software maintenance, subscriptions, and other overhead type items. Normally these expenditures do not change materially on an aggregate basis from year to year and are part of our general and administrative expenses. We have not attempted to estimate these types of expenditures in this table as most could be quickly cancelled with regard to any specific vendor, even though the expense itself may be required for ongoing normal operations of the Company. (d) Represents the estimated future payments under our derivative obligations based on the futures market prices as of December 31, 2004. These amounts will change as oil and natural gas commodity prices change. The estimated fair market value of our oil and natural gas commodity derivatives at December 31, 2004 was a $4.9 million liability. See further discussion of our derivative contracts in "Market Risk Management" contained in this Management's Discussion and Analysis of Financial Condition and in Note 9 to the Consolidated Financial Statements. (e) Represents projected capital costs as scheduled in our December 31, 2004 proved reserve report that are necessary in order to recover our proved undeveloped reserves, but these are not current contractual commitments. Amount is net of capital obligations shown above.
29 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations (f) Represents the estimated future asset retirement obligations on an undiscounted basis. The discounted asset retirement obligation of $21.5 million, as determined under SFAS No. 143, is further discussed in Note 4 to the Consolidated Financial Statements.
Long-term contracts require us to deliver CO2 to our industrial CO2 customers at various contracted prices, plus we have a CO2 delivery obligation to Genesis pursuant to two volumetric production payments ("VPP") contracts entered into during 2003 and 2004. Based upon the maximum amounts deliverable as stated in the contracts and the volumetric production payment, we estimate that we may be obligated to deliver up to 398 Bcf of CO2 to these customers over the next 17 years; however, since the group as a whole has historically taken less CO2 than the maximum allowed in their contracts, based on the current level of deliveries we project that our commitment would likely be reduced to approximately 332 Bcf. The maximum volume required in any given year is approximately 101 MMcf/d, although based on our current level of deliveries; this would likely be reduced to approximately 78 MMcf/d. Given the size of our proven CO2 reserves at December 31, 2004 (approximately 2.7 Tcf before deducting approximately 178.7 Bcf for the two VPPs), our current production capabilities and our projected levels of CO2 usage for our own tertiary flooding program, we believe that we will be able to meet these delivery obligations. RESULTS OF OPERATIONS CO2 Operations OVERVIEW. Over five years ago we began our focus upon tertiary operations with the purchase of Little Creek Field, a tertiary recovery operation that was already underway. Subsequently, we have greatly expanded this program in Southwest Mississippi (Phase I of our tertiary operations), acquiring several more oil fields and most importantly the CO2 resources used to flood these fields (see "CO2 Resources" below). The focus has increased to the point that approximately 60% of our 2005 capital budget is dedicated to tertiary related operations, including the CO2 pipeline currently under construction to East Mississippi (the area where we will conduct Phase II of our tertiary operations). We particularly like this play as (i) it is lower risk and more predictable than most traditional exploration and development activities, (ii) it provides a reasonable rate of return at relatively low oil prices (down to prices in the low twenties per Bbl in Phase I of our tertiary operations in Southwest Mississippi), and (iii) we have virtually no competition for this type of activity in our geographic area. Generally, from East Texas to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of CO2 that we own drive the play. CO2 RESOURCES. In February 2001, we acquired the sources of CO2 located near Jackson, Mississippi, and a pipeline to transport it to our oil fields. Since February 2001, we have acquired two producing wells and drilled seven CO2 producing wells, tripling our initial proven CO2 reserves to 2.7 Tcf as of December 31, 2004 (including the 178.7 Bcf of reserves dedicated to two VPPs with Genesis). The estimate of 2.7 Tcf of proved CO2 reserves is based on total CO2 reserves in the fields, of which Denbury's net ownership is approximately 2.1 Tcf and is included in the evaluation of proven CO2 reserves by DeGolyer & MacNaughton included as Exhibit 99. In discussing the available CO2 reserves, we make reference to the gross amount of proved reserves as that is the amount that is available both for Denbury's tertiary recovery programs and for industrial users who are customers of Denbury and others, as we are responsible for distributing the entire CO2 production stream for both of these purposes. We currently estimate that it will take approximately 711 Bcf of CO2 to develop and produce the proved tertiary recovery reserves we have recorded at December 31, 2004. Today, we own every known producing CO2 well in the region, providing us a significant strategic advantage in the acquisition of other properties in Mississippi and Louisiana that could be further exploited through tertiary recovery. As of January 2005, we are capable of producing approximately 350 MMcf/d of CO2, about four times the production capacity at the time of our initial acquisition of the Jackson Dome field. We continue to drill additional CO2 wells, with four more wells planned for 2005, which are expected to further increase our production capacity and potentially increase our proven CO2 reserves. We believe we have sufficient CO2 reserves for our first two phases of tertiary operations in Western Mississippi and Eastern Mississippi, but would like to add additional reserves for future phases, plus we need to further increase our production capacity as our current model for phases I and II requires almost 700 MMcf/d of CO2 production by 2009. 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. In addition to using CO2 for our tertiary operations, we sell CO2 to third party industrial users under long-term contracts. Our net operating margin from 30 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations these sales was $6.2 million during 2002, $6.5 million during 2003, and $4.9 million during 2004. Our average CO2 production during 2002, 2003 and 2004 was approximately 104 million, 170 million, and 218 million cubic feet per day, of which approximately 54% in 2002, 62% in 2003, and 73% in 2004 was used in our tertiary recovery operations, with the balance sold to third parties for industrial use. We spent approximately $0.12 per Mcf to produce our CO2 during 2004, slightly less than our 2003 annual average of $0.15 per Mcf, primarily due to the lack of any significant workover expenses like we had in 2003, partially offset by higher royalty expenses because certain of our royalties are adjusted based on oil prices. During 2002, we spent approximately $0.13 per Mcf to produce our CO2. Our estimated total cost per thousand cubic feet of CO2 during 2004 was approximately $0.21, after inclusion of depreciation and amortization expense related to the CO2 production. OIL POTENTIAL. Although our oil production from our CO2 tertiary recovery activities is still relatively modest (approximately 25% of fourth quarter 2004 production), we expect it to be an ever increasing portion of our production. We currently have tertiary operations on-going at Little Creek, Mallalieu, McComb and Brookhaven Fields, as well as various smaller adjacent fields. We project that our oil production from these operations will increase substantially over the next several years, along with our tentatively scheduled tertiary projects at other oil fields along our pipeline. As of January 2005, these fields were producing approximately 8,300 Bbls/d. As of December 31, 2004, we had approximately 50.5 MMBbls of proven oil reserves related to tertiary operations in these fields along our CO2 pipeline and have identified and estimated significant additional potential in fields that we own in this area. In addition, we have commenced operations to expand this program to East Mississippi and have commenced the acquisition of leases and right-of-way for the construction of an 84-mile CO2 pipeline from our source wells near Jackson, Mississippi to Eucutta Field in East Mississippi. While our current tertiary operations in the Southwest part of Mississippi are economic at NYMEX per barrel oil prices in the low twenties, due predominately to the lower quality of oil in East Mississippi, we estimate that it requires a NYMEX oil price in the mid to upper twenties for the same rate of return in this part of the state. We believe that this expansion, labeled Phase II, has significant other oil potential well beyond the first six fields that we have engineered and currently plan to flood. Combining the production forecast for both of these areas extends the period during which we anticipate significant oil production growth from a few years, for Phase I alone, to five to ten years combined. While it is extremely difficult to accurately forecast production, we do believe that our tertiary recovery operations provide significant long-term production growth potential at reasonable rates of return with relatively low risk and will be the backbone of our Company's growth for the foreseeable future. FINANCIAL STATEMENT IMPACT OF CO2 OPERATIONS. The increasing emphasis on CO2 tertiary recovery projects has made, and will continue to make, an impact on our financial results and certain operating statistics different from conventional development activities. First, there is a significant delay between the initial capital expenditures and the resulting production increases, as these tertiary operations require the building of facilities before CO2 flooding can commence and it usually takes six-to-twelve months before the field responds (i.e. oil production commences) to the injection of CO2. Further, as we expand to other areas beyond Phase I, there will be times when we spend significant amounts of capital before we can recognize any proven reserves as these other areas, for the most part, will require an oil production response to the CO2 injections before any oil reserves can be recorded. We plan to spend over $50 million on Phase II oil fields during 2005, plus an additional $45 million on the CO2 pipeline to East Mississippi. Secondly, these tertiary projects are more expensive to operate than our other oil fields because of the cost of injecting and recycling the CO2 (primarily due to the significant energy requirements to re-compress the CO2 back into a liquid state for re-injection purposes). As commodity and energy prices increase, so does our operating expenses in these fields. As such, 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. Our operating cost for our tertiary operations during 2004 averaged $9.90 per BOE, as compared to an estimated cost of around $5 to $7 per BOE for a more traditional oil property. We allocate the cost to produce and transport the CO2 between CO2 used in our own oil fields and CO2 sold to commercial users. The CO2 operating expenses allocated to our oil fields are recorded as lease operating expenses on those fields. Third, all of our current CO2 operations are in fields that produce light sweet oil and receive oil prices close to, and sometimes actually higher than, NYMEX prices. As this production becomes a larger percentage of our overall production, the overall average difference between the prices we receive and published NYMEX prices should decrease, assuming other market conditions do not 31 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations change. While our oil prices have historically averaged between $4.00 and $5.00 below NYMEX prices, our 2002 average was $3.74 below NYMEX and our 2003 average decreased further to $3.60 below NYMEX. During 2004, the market for sour and heavy crude oil (predominately our East Mississippi production) deteriorated, causing our overall average differential to increase to $4.91 per barrel for the year and to $6.48 per barrel for the fourth quarter of 2004. While we cannot predict what will happen to the market for heavy and sour crude, we do expect our light sweet oil production to increase as a percentage of our total oil production over the next few years. However, this trend could reverse in future years as the anticipated oil production from Phase II of our tertiary operations is primarily heavy and sour oil. 2004 CO2 Tertiary Recovery Operating Activities. Our oil production from our CO2 tertiary recovery activities has steadily increased during the last few years, from 3,970 Bbls/d in 2002 to 4,671 Bbls/d during 2003, and to 6,784 Bbls/d during 2004, with a fourth quarter 2004 rate of 7,242 Bbls/d. This represents approximately 37% of our total corporate oil production during the fourth quarter of 2004 and approximately 25% of our total corporate production on a BOE basis. We expect that this oil production will continue to increase, although the increases are not always predictable or consistent. While we did experience higher energy costs to operate our tertiary recycling facilities as a result of higher commodity prices, we were able to lower our operating cost per BOE in our tertiary operations from $11.34 per BOE in 2003 to $9.90 per BOE during 2004 because of the higher tertiary oil production levels. In addition to higher energy costs, we experienced general cost inflation in the industry and also commenced lease payments on certain of our recycling facilities (see "Commitments and Obligations" above). As a result, the absolute amount of operating expenses related to tertiary operations increased from $14.3 million during 2002 to $19.3 million during 2003 and $24.6 million during 2004. At December 31, 2004, we had proved reserves of 50.5 MMBbls relating to our tertiary recovery operations. Through December 31, 2004, we had spent a total of $155.6 million on fields involved in this process, and had received $160.0 million in net cash flow (revenue less operating expenses and capital expenditures), or net positive cash flow of $4.4 million. The proved oil reserves in our CO2 fields have a PV-10 Value of $782.9 million, using December 31, 2004 constant NYMEX pricing of $43.45 per Bbl. These amounts do not include the capital costs or related depreciation and amortization of our CO2 producing properties. Through December 31, 2004, we have spent a total of $132.8 million on our CO2 producing properties, received a total of $57.4 million in net cash flow (revenue less operating expenses and capital expenditures, consisting solely of sales to industrial customers and Genesis volumetric production payment receipts), leaving us a balance of approximately $75.4 million of unrecovered costs for the CO2 assets. CO2 Related Capital Budget for 2005. Tentatively, we plan to spend approximately $35 million in 2005 in the Jackson Dome area with the intent to add additional CO2 reserves and deliverability for future operations. Approximately $60 million in capital expenditures is budgeted in 2005 for our oil fields with tertiary operations in Southwest Mississippi and approximately $50 million for oil fields in East Mississippi, plus an additional $45 million for the CO2 pipeline to East Mississippi, increasing our combined CO2 related expenditures to over 60% of our 2005 capital budget. Operating Income Cash flow from operations and net income have been strong for the last three years, primarily because of higher than historical commodity prices. Production declined slightly (2%) from 2002 to 2003 and approximately 5% from 2003 to 2004, with most of the current year decrease related to the sale of our offshore properties (see also "Overview"). The higher commodity prices each year more than offset the production decline, resulting in higher overall net income and adjusted cash flow from operations each year from 2002 through 2004 (see discussion below regarding this non-GAAP measure, adjusted cash flow from operations).
Year Ended December 31, - ---------------------------------------------------------------------------------------------------------- Amounts in Thousands Except Per Share Amounts 2004 2003 2002 - ---------------------------------------------------------------------------------------------------------- Net income................................................... $ 82,448 $ 56,553 $ 46,795 Net income per common share: Basic ..................................................... $ 1.50 $ 1.05 $ 0.88 Diluted ................................................... 1.44 1.02 0.86 - ---------------------------------------------------------------------------------------------------------- Adjusted cash flow from operations........................... $ 200,193 $ 189,802 $ 164,565 Net change in assets and liabilities relating to operations.. (31,541) 7,813 (4,965) - ---------------------------------------------------------------------------------------------------------- Cash flow from operations (GAAP measure)................... $ 168,652 $ 197,615 $ 159,600 ==========================================================================================================
32 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by operations before changes in assets and liabilities, as calculated from our Consolidated Statements of Cash Flows. Cash flow from operations is the GAAP measure as presented in our Consolidated Statements of Cash Flows. In our discussion herein, we have elected to discuss these two components of cash flow provided by operations. Adjusted cash flow from operations, the non-GAAP measure, measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe that it is important to consider adjusted cash flow from operations separately, as we believe it can often be a better way to discuss changes in operating trends in our business caused by changes in production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during that year. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices or significant changes in drilling activity. The net change in assets and liabilities relating to operations is also important as it does require or provide additional cash for use in our business; however, we prefer to discuss its effect separately. For instance, as noted above, during 2003, our accounts payable and accrued liabilities increased as a result of our higher drilling activity level late in the year, particularly offshore, increasing our available cash from operations. During 2004, we had a $31.5 million difference between our adjusted cash flow from operations and our GAAP cash flow from operations. The most significant factor was the transfer of approximately $12.5 million of accrued production receivables relating to our offshore properties that existed as of the closing date to the offshore property purchaser. This reduction in accrued production receivables during 2004 was not considered a collection of receivables for our GAAP cash flow from operations. In addition to the effect of transferred receivables, our other accrued production receivables increased during the year due to the increase in commodity prices and we reduced our accounts payable and accrued liabilities by approximately $10.5 million, as a result of less overall activity as of year-end, both of which contributed to the significant difference between our 2004 adjusted cash flow and GAAP cash flow from operations. 33 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations Certain of our operating statistics for the each of last three years are set forth in the following chart:
Year Ended December 31, - ---------------------------------------------------------------------------------------------------------- (In Thousands, Except per BOE Amounts) 2004 2003 2002 - ---------------------------------------------------------------------------------------------------------- AVERAGE DAILY PRODUCTION VOLUME Bbls................................................ 19,247 18,894 18,833 Mcf................................................. 82,224 94,858 100,443 BOE (1)............................................. 32,951 34,704 35,573 OPERATING REVENUES Oil sales........................................... $ 256,843 $ 189,442 $ 153,705 Natural gas sales................................... 187,934 196,021 121,189 -------------- --------------- -------------- Total oil and natural gas sales................... $ 444,777 $ 385,463 $ 274,894 ============== =============== ============== HEDGE CONTRACTS Cash gain (loss) on effective hedge contracts $ (70,469) $ (62,210) $ 932 Cash gain (loss) on ineffective hedge contracts (14,088) - - -------------- --------------- -------------- Total cash gain (loss) (84,557) (62,210) 932 Non-cash hedging adjustments (1,270) 3,578 3,093 -------------- --------------- -------------- Total gain (loss) on derivative contracts $ (85,827) $ (58,632) $ 4,025 ============== =============== ============== OPERATING EXPENSES Lease operating expenses............................ $ 87,107 $ 89,439 $ 71,188 Production taxes and marketing expenses (3)......... 18,737 14,819 11,902 -------------- --------------- -------------- Total production expenses......................... $ 105,844 $ 104,258 $ 83,090 ============== =============== ============== CO2 sales and transportation fees (4)............... $ 6,276 $ 8,188 $ 7,580 CO2 operating expenses.............................. 1,338 1,710 1,400 -------------- --------------- -------------- CO2 operating margin.............................. $ 4,938 $ 6,478 $ 6,180 ============== =============== ============== UNIT PRICES-INCLUDING IMPACT OF HEDGES (2) Oil price per Bbl................................... $ 27.36 $ 24.52 $ 22.27 Gas price per Mcf................................... 5.57 4.45 3.35 UNIT PRICES-EXCLUDING IMPACT OF HEDGES (2) Oil price per Bbl................................... $ 36.46 $ 27.47 $ 22.36 Gas price per Mcf................................... 6.24 5.66 3.31 OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1) Oil and natural gas revenues (including hedge settlements) $ 29.87 $ 25.52 $ 21.24 -------------- --------------- -------------- Lease operating expenses............................ $ 7.22 $ 7.06 $ 5.48 Production taxes and marketing expenses............. 1.55 1.17 0.92 -------------- --------------- -------------- Total production expenses......................... $ 8.77 $ 8.23 $ 6.40 ========================================================================================================== (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. (3) For 2004, includes transportation expenses paid to Genesis of $1.2 million. (4) For 2004 and 2003, includes deferred revenue of $2,399,000 and $322,000, respectively, associated with volumetric production payments and transportation income of $2,694,000 and $355,000, respectively, both from Genesis.
34 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations PRODUCTION. Average daily production by area for 2002, 2003 and 2004, and each of the quarters of 2004 is listed in the following table (BOE/d).
Average Daily Production (BOE/d) -------------------------------------------------------------------------------- First Second Third Fourth Quarter Quarter Quarter Quarter Operating Area 2002 2003 2004 2004 2004 2004 2004 - ---------------------------------- -------------------------------------------------------------------------------- Mississippi - non-CO2 floods 13,378 13,638 12,754 13,048 12,969 13,564 13,085 Mississippi - CO2 floods 3,970 4,671 6,318 6,603 6,967 7,242 6,784 Onshore Louisiana 8,050 8,222 8,825 7,492 7,033 7,182 7,630 Barnett Shale and other 200 224 229 345 803 963 587 -------------------------------------------------------------------------------- Total production excl. offshore 25,598 26,755 28,126 27,488 27,772 28,951 28,086 Offshore Gulf of Mexico 9,975 7,949 8,521 9,114 1,885 26 4,865 -------------------------------------------------------------------------------- Total Company 35,573 34,704 36,647 36,602 29,657 28,977 32,951 - ---------------------------------- =================================================================================
As a result of the sale of our offshore properties in July 2004, third and fourth quarter 2004 production decreased significantly from prior periods as listed in the above table. Adjusting for the offshore sale, overall production increased approximately 5% on a BOE/d basis during both 2003 and 2004, anchored by the increased production from our tertiary operations and Barnett Shale play, generally offset by overall declines in our onshore natural gas wells in Louisiana. However, other factors that caused fluctuations between the various periods should also be noted as outlined below. The addition of properties acquired from COHO during August 2002 contributed to the majority of the increase in our overall production in the Mississippi-non-CO2 flood properties from 2002 to 2003, as most of these pre-existing non-CO2 fields in Mississippi have been on a slow decline as a result of normal depletion. Heidelberg Field, our single largest field that is located in this area, has partially offset this decline, as its production increased each year, from 7,479 BOE/d during 2002 to 7,535 BOE/d during 2003 to 7,775 BOE/d during 2004. Most of this increase at Heidelberg is attributable to additional natural gas drilling in the Selma Chalk formation as Heidelberg's oil production has been slowly decreasing. Natural gas production at this field averaged 7.1 MMcf/d in 2002, 10.3 MMcf/d in 2003 and 13.8 MMcf/d in 2004, making Heidelberg Field our single largest natural gas producing field during 2004. As more fully discussed in "CO2 Operations" above, oil production from our tertiary operations has increased each year. Production from our offshore properties averaged 1,885 BOE/d in the third quarter, representing the production during the first 19 days of July prior to the sale. As evidenced in the above table, production from this area has fluctuated over the last three years primarily due to the level of activity and the fluctuations caused by the short-lived nature of these natural gas reserves. As an example, offshore production increased in early 2004 as a result of 15 well completions made late in the fourth quarter of 2003, four at Brazos A-21, three at North Padre A-9, three at Chandeleur Sound 69, two at West Cameron 192 and three at West Cameron 427. Some of our natural gas properties in onshore Louisiana have similar characteristics as is evident by the steep declines during 2004. While the production from onshore Louisiana only declined 7% on an annual basis, there was a 19% drop between the first quarter of 2004 and last quarter of 2004. A significant portion of this decline was at Thornwell Field, an onshore Louisiana field, which averaged 926 BOE/d during the fourth quarter of 2004, down from 2,526 BOE/d in the first quarter of 2004 and 2,487 BOE/d during 2003. Production from this field is in a steep decline due to its short-lived nature, and is expected to further decline in the future. In spite of its short remaining life, we have generated a good return on investment at Thornwell, generating $37.0 million of net positive cash flow (operating revenues less operating expenses and capital expenditures) through December 31, 2004, with a remaining PV-10 Value of $37.4 million as of December 31, 2004 (based on SEC proved reserve report at year-end 2004 prices). 35 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations Production in the Barnett Shale area has just recently begun to increase as a result of five horizontal wells drilled and completed in this area during the latter part of 2004. We plan to drill around 25 more wells there in 2005 and expect production from this area to further increase during 2005. Our production for 2004 was weighted slightly toward oil (58%), although the fourth quarter 2004 average was 68% oil following the sale of the offshore properties in July 2004. It appears that we will remain similarly weighted toward oil in 2005 due to our increasing emphasis on tertiary operations, unless we make an acquisition that is predominantly natural gas. OIL AND NATURAL GAS REVENUES. Our oil and natural gas revenues have increased for each of the last two years. Two factors cause the change in pre-hedging revenues: commodity prices and production levels. Between 2003 and 2004, revenues increased by 15%, primarily due to higher commodity prices. The overall increase in commodity prices contributed $77.8 million in additional revenues, a 20% increase; partially offset by an overall decrease of $18.5 million (a 5% decrease) related to the 5% lower production volumes. Between 2002 and 2003, revenues increased by 40%, also primarily due to higher commodity prices. The overall increase in commodity prices contributed $117.3 million in additional revenues, a 43% increase; partially offset by an overall decrease in revenues of $6.7 million (a 2% decrease) related to the 2% lower production volumes. During 2004, we paid out $64.1 million on our oil hedges ($9.10 per Bbl) and $20.4 million ($0.68 per Mcf) on our natural gas hedges relating to swaps and collars we purchased one to two years earlier when commodity prices were lower. About $30.5 million of the hedge payments related to swaps originally put in place to protect the rate of return for the COHO acquisition in August 2002. The payments in 2003 were similar in nature, but slightly less due to lower overall commodity prices. During 2003, we paid out $20.3 million on our oil hedges ($2.95 per Bbl) and $41.9 million ($1.21 per Mcf) on our natural gas hedges on generally the same swaps and collars. During 2002, we had total net receipts on our hedges of $932,000, paying out $0.6 million ($0.09 per Bbl) on our oil hedges, but collecting a net $1.5 million ($0.04 per Mcf) on our natural gas hedges. For 2005, we have hedged a lower percentage of our overall production, predominately with puts or price floors, so we anticipate that our hedge payments will be substantially lower than the payments made in 2004. See "Market Risk Management" for a further discussion of our hedging activities and position. Our net oil and natural gas prices have fluctuated as outlined on the prior table. During 2004, we received the highest weighted average net price per BOE in our history, netting $29.87 per BOE even after paying out approximately $7.01 per BOE for hedge losses. This resulted from average NYMEX prices of over $41.00 per Bbl and $6.00 per MMBtu during the year. Prices were also strong during 2003, although not quite as high, netting Denbury $25.52 per BOE, net of the $4.91 per BOE hedge losses. During 2003 we also had one of our best years with regard to our realized net price relative to NYMEX prices. During 2002, we received an average discount to NYMEX of $3.74 per Bbl. This improved in 2003 to an average discount of $3.60 per Bbl. This trend was reversed in 2004 as the heavy, sour crude market (which predominately applies to our Eastern Mississippi production) deteriorated significantly, increasing our average oil differentials for the year to $4.91 per Bbl and $6.48 per Bbl for the fourth quarter of 2004. If market conditions for the heavy, sour crude remained consistent, we would expect to gradually improve the overall NYMEX discount as the amount of light sweet oil production from our tertiary operations is expected to increase, improving the overall quality of our product mix. However, as evident in 2004, the oil market can change substantially. Year over year, there is generally less fluctuation in our natural gas prices relative to NYMEX. Normally, we are at, or slightly above, the NYMEX market, primarily because of the high Btu content of our natural gas. For 2004, we had an average $0.02 premium to NYMEX, a little less than the $0.18 premium during 2003, but higher than the $0.05 discount in 2002. As we increase our emphasis on the Barnett Shale area in 2005, the overall price we receive for our natural gas could decline slightly as our properties in this area have historically received a price that is $0.50 to $0.75 less than NYMEX prices. OPERATING EXPENSES. Lease operating expenses increased to $7.22 per BOE in 2004, a 2% increase over the $7.06 per BOE average during 2003, and an increase of 32% from the $5.48 per BOE average during 2002. During 2004, our workover expenses decreased as compared to 2003, when we spent $2.8 million on two individually significant workovers relating to mechanical failures of two onshore Louisiana wells, plus several smaller workovers. Operating expenses on our tertiary operations increased from $14.3 million during 2002 to $19.3 million in 2003 to $24.6 million in 2004 as a result of increased activity at Mallalieu and McComb Fields. However, with the 45% higher production from these tertiary operations between the same periods, operating expenses for our tertiary operations on a per BOE basis decreased from $11.34 per BOE in 2003 to $9.90 per BOE in 2004. Nonetheless, our tertiary operations are steadily increasing our aggregate dollar costs and our costs per BOE on a total corporate 36 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations basis as our tertiary operations constitute a more significant portion of our total production and operations. The balance of cost increases during 2004 is generally attributable to higher energy costs to operate our tertiary recovery properties, a provision for potential litigation losses, and general cost inflation in our industry. In general, we expect our operating costs per BOE to further increase in the future as the operating costs of our tertiary operations are higher than the costs of our other operations. Most of the increase from 2002 to 2003 was attributable to the aforementioned workovers, with several other smaller workovers, including one on a CO2 well. The growth of our tertiary operations also contributed to an overall increase, as well as higher lease fuel costs and a full year of expenses on the properties acquired from COHO, which have typically had higher expenses on a per BOE basis than our other oil properties due to their age. Production taxes and marketing expenses generally change in proportion to commodity prices and therefore, were higher in 2004 along with the record high commodity prices. The sale of our offshore properties also contributed to the increase in production taxes and marketing expenses on a per BOE basis during 2004, as most of our offshore properties were tax exempt. General and Administrative Expenses During the last three years, general and administrative ("G&A") expenses on a per BOE basis have increased from $0.96 per BOE during 2002, to $1.20 per BOE during 2003, to $1.78 per BOE during 2004, increasing even faster than the gross aggregate dollar increases in G&A expense as production has declined each year due primarily to property sales.
Year Ended December 31, - --------------------------------------------------------------------------------------------------------- Amounts in Thousands Except Per BOE and Employee Data 2004 2003 2002 - --------------------------------------------------------------------------------------------------------- Gross G&A expense $ 53,658 $ 46,031 $ 40,149 Operator overhead charges (28,048) (26,823) (23,857) Capitalized exploration expense (5,072) (5,507) (5,325) - --------------------------------------------------------------------------------------------------------- 20,538 13,701 10,967 State franchise taxes 923 1,488 1,459 - --------------------------------------------------------------------------------------------------------- Net G&A expense $ 21,461 $ 15,189 $ 12,426 ========================================================================================================= Average G&A expense per BOE $ 1.78 $ 1.20 $ 0.96 Employees as of December 31 380 374 356 - ---------------------------------------------------------------------------------------------------------
Gross G&A expenses increased $7.6 million, or 17%, between 2003 and 2004. The largest component of the increase was approximately $2.4 million of employee severance payments for the offshore professional and technical staff terminated in conjunction with our offshore property sale. We also incurred additional G&A expenses associated with our corporate restructuring in December 2003, compliance with the requirements of the Sarbanes-Oxley Act, the sale of stock by the Texas Pacific Group in March 2004, a provision for potential litigation losses, restricted stock grants, higher bonus levels for employees than in 2003 due to the strong performance during 2004, and overall increases in most other categories of G&A due to general cost inflation. During the third and fourth quarters of 2004, we granted a total of 1,150,000 million shares of restricted stock to our officers and independent directors, generating deferred compensation expense of approximately $23.3 million, the market value of the shares on the date of grant. A portion of this restricted stock vests over five years and a smaller portion vests upon retirement (in addition to vesting upon death, disability or a change of control). We are amortizing the non-cash $23.3 million of compensation expense of this restricted stock over the five year vesting period and over the projected retirement date vesting period, expensing approximately $1.6 million during 2004. We estimate that amortized compensation expense for the restricted stock will be approximately $1.0 million per quarter through 2006. Gross aggregate dollar G&A expenses increased $5.9 million, or 15%, between 2002 and 2003. The largest component of the increase was approximately $1.4 million of expenses spent for consultants hired to help document and test our system of internal controls, a requirement of the Sarbanes-Oxley Act of 2002. The second largest source of the increase was approximately $630,000 of legal, accounting, bank and other fees associated with the conversion to a holding 37 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations company organizational structure during December 2003 which reduced our franchise taxes by $565,000 between 2003 and 2004. Other factors also contributed to the increase, the most significant being expenses associated with the sale of stock by the Texas Pacific Group in the first and last quarters of 2003, higher year-end expenses for engineering and audit fees, and an overall increase in personnel and associated expenses primarily related to cost of living salary increases. Partially offsetting these increases was a reduction in our 2003 bonuses due to less positive operating results during 2003 in certain areas. Higher operator overhead recovery charges resulting from the incremental development activity helped to partially offset the increase in gross G&A, partially reduced by the impact of the offshore property sale. Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. As a result of the additional operated wells from acquisitions, additional tertiary operations, and drilling activity during the past year, the amount we recovered as operator overhead charges increased by 12% between 2002 and 2003 and 5% between 2003 and 2004. Capitalized exploration costs increased slightly between 2002 and 2003, along with increases in employee related costs, but decreased in 2004 as a result of the personnel reductions in our offshore area as a result of the property sale. The net effect of the increases in gross G&A expenses, operator overhead recoveries and capitalized exploration costs was a 41% increase in net G&A expense between 2003 and 2004 and a 22% increase between 2002 and 2003. The increase was even higher on a per BOE basis as a result of lower production, primarily related to the offshore property sale. Interest and Financing Expenses
Year Ended December 31, - ---------------------------------------------------------------------------------------------- Amounts in Thousands Except Per BOE Data 2004 2003 2002 - ---------------------------------------------------------------------------------------------- Interest expense $ 19,468 $ 23,201 $ 26,833 Non-cash interest expense (962) (1,251) (2,659) - ---------------------------------------------------------------------------------------------- Cash interest expense 18,506 21,950 24,174 Interest and other income (2,388) (1,573) (1,746) - ---------------------------------------------------------------------------------------------- Net cash interest expense $ 16,118 $ 20,377 $ 22,428 ============================================================================================== Average net cash interest expense per BOE $ 1.34 $ 1.61 $ 1.73 Average debt outstanding $ 270,770 $ 341,496 $ 350,556 Average interest rate (1) 6.8% 6.4% 6.9% - ----------------------------------------------------------------------------------------------
(1) Includes commitment fees but excludes amortization of debt issue costs. Interest expense for 2004 decreased from 2003 primarily due to lower average debt levels as a result of our $50 million reduction in debt during 2003 and the payoff of our bank debt in the third quarter of 2004 with the proceeds from our offshore property sale. Our non-cash interest expense in 2004 decreased as a result of the subordinated debt refinancing in March 2003, which eliminated the amortization of discount on our old subordinated debt, which was higher than the discount and related amortization on our new subordinated debt issue. Interest and other income increased as a result of the cash generated from the offshore property sale. Interest expense for 2003 decreased from levels in the prior year for similar reasons, (i) lower overall interest rates, resulting from an overall drop in market interest rates on our bank debt and due to the refinancing of our subordinated debt, (ii) lower average outstanding debt balance during 2003, as we reduced debt by $50 million during the year, and (iii) reduced debt issue cost amortization resulting from the complete amortization of costs associated with the original maturity of our bank credit line in December 2002 after we refinanced and extended the bank credit line to April 2006. 38 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations Depletion, Depreciation and Amortization ("DD&A")
Year Ended December 31, - ------------------------------------------------------------------------------------------------------- Amounts in Thousands, Except Per BOE Data 2004 2003 2002 - ------------------------------------------------------------------------------------------------------- Depletion and depreciation of oil and natural gas properties $ 88,505 $ 87,842 $ 87,728 Depletion and depreciation of CO2 assets 4,664 2,542 1,858 Asset retirement obligations 2,408 2,852 2,951 Depreciation of other fixed assets 1,950 1,472 1,699 - ------------------------------------------------------------------------------------------------------- Total DD&A $ 97,527 $ 94,708 $ 94,236 ======================================================================================================= DD&A per BOE: Oil and natural gas properties $ 7.54 $ 7.16 $ 6.98 CO2 assets and other fixed assets 0.55 0.32 0.28 - ------------------------------------------------------------------------------------------------------- Total DD&A cost per BOE $ 8.09 $ 7.48 $ 7.26 =======================================================================================================
But for the property sales, our total proved reserve quantities would have increased each of the last three years. Our proved reserves decreased from 130.7 MMBOE as of December 31, 2002, to 128.2 MMBOE as of December 31, 2003 and increased slightly to 129.4 MMBOE as of December 31, 2004. During 2003 we sold approximately 8.3 MMBOE of proved reserves and during 2004 sold approximately 16.5 MMBOE of proved reserves, primarily related to the offshore sale. Reserve quantities and associated production are only one side of the DD&A equation, with capital expenditures, asset retirement obligations less related salvage value, and projected future development costs making up the remainder of the calculation. In total, our DD&A rate on a per BOE basis increased 8% between 2003 and 2004, primarily due to the higher percentage of expenditures on offshore properties during 2003 and the first six months of 2004, which have higher overall finding and development costs, and an increase in certain of our future development cost estimates to reflect the rising costs in the industry. Although the 2004 average DD&A rate was similar to the DD&A rate of $8.00 per BOE during the fourth quarter of 2003, during the year there were significant fluctuations. Our DD&A rate on a per BOE basis decreased in the third quarter of 2004 to $7.62 per BOE from $8.46 per BOE in the second quarter, primarily as a result of the sale of our offshore properties, the proceeds of which were credited to the full cost pool. However, the rate increased in the fourth quarter of 2004 to $7.98 per BOE, primarily to reflect cost inflation in the industry, as we increased our cost estimates (i.e. future development costs) for certain existing proved undeveloped reserves. We adjust our DD&A rate each quarter based on any changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. Our DD&A rate for our CO2 and other fixed assets increased in 2004 as a result of the additional cost incurred drilling CO2 wells during the year and higher associated future development costs, partially offset by an increase in CO2 reserves from 1.6 Tcf as of December 31, 2003 to 2.7 Tcf as of December 31, 2004 (100% working interest basis before amounts attributable to Genesis volumetric production payments - see "CO2 Operations - CO2 Resources"). During 2003, the fourth quarter DD&A rate increased to $8.00 per BOE, increasing the 2003 annual average to $7.48 per BOE. The higher DD&A was partially due to the higher percentage of capital expenditures spent on our offshore properties, 34% during 2003 as compared to approximately 10% during 2002, where we have a higher overall finding cost. The rate was also affected by less than hoped for drilling results in the Gulf of Mexico and Southern Louisiana, particularly in the fourth quarter, where some of our larger exploration potential failed to materialize. In contrast to our offshore properties, our tertiary operations have yielded a finding and development cost, including the net change in forecasted future development and abandonment costs, of just under $6.00 per BOE inception to December 31, 2004, in line with our long-term expectations, helping to partially offset the higher finding and development cost of our offshore and other natural gas properties. Prior to 2003, we provided for the estimated future costs of well abandonment and site reclamation, net of any anticipated salvage, on a unit-of-production basis. This provision was included in DD&A expense and increased each year, along with a general increase in the number of our properties, especially the acquisition of our offshore properties. Effective January 1, 2003, we adopted 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, discounted to its present value using our credit adjusted risk-free interest rate, and that a corresponding amount be capitalized by increasing the carrying amount of the related 39 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations long-lived asset. The liability is accreted 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. As part of this adoption, we ceased accruing for site reclamation costs, as had been our practice in the past, and recorded a $41.0 million liability representing the estimated present value of our retirement obligations, with a $34.4 million increase to oil and natural gas properties. On an undiscounted basis, we estimated our retirement obligations as of December 31, 2003 to be $82.7 million, with an estimated salvage value of $43.3 million, also on an undiscounted basis. As of December 31, 2004, we estimated our retirement obligations to be $52.1 million ($21.5 million present value), with an estimate salvage value of $43.6 million, the decrease related to the sale of our offshore properties. DD&A is calculated on the increase to oil and natural gas and CO2 properties, net of estimated salvage value. We also include the accretion of discount on the asset retirement obligation in our DD&A expense. Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. We did not have any full cost pool ceiling test write downs in 2002, 2003 or 2004 and do not expect to have any such write downs in the foreseeable future at current commodity price levels. Income Taxes
Year Ended December 31, - ---------------------------------------------------------------------------------------------------- Amounts in Thousands, Except Per BOE Amounts 2004 2003 2002 - ---------------------------------------------------------------------------------------------------- Current income tax expense (benefit) $ 22,929 $ (91) $ (406) Defered income tax provision 16,463 26,303 23,926 - ---------------------------------------------------------------------------------------------------- Total income tax provision $ 39,392 $ 26,212 $ 23,520 ==================================================================================================== Average income tax provision per BOE $ 3.27 $ 2.07 $ 1.81 Net effective tax rate 32.3% 32.7% 33.4% Federal tax net operating loss carryforwards $ - $ 94,955 $ 84,891 Total net deferred tax asset (liability) (71,936) (43,539) (21,777) - ----------------------------------------------------------------------------------------------------
Our income tax provision for 2004 was increased to an estimated statutory tax rate of 39% to reflect the changes in our state income tax rates resulting from the sale of our offshore properties. Our tax provision for 2002 and 2003 was based on an estimated statutory rate of 38%. Our net effective tax rate for all periods was lower than the statutory rates, primarily due to the recognition of enhanced oil recovery credits which lowered our overall tax rate. The current income tax expense represents our anticipated alternative minimum cash taxes that we could not offset with our regular tax net operating loss carryforwards or our enhanced oil recovery credits. During the third quarter of 2004, we recognized approximately $21.0 million of current income taxes as a result of the sale of our offshore properties, which was a gain for income tax purposes. The taxes on the offshore sale were primarily alternative minimum taxes as we were able to offset the related regular tax with our net operating loss carryforwards. As of December 31, 2004, we had utilized all of our federal tax net operating loss carryforwards, but had an estimated $27.8 million of enhanced oil recovery credits to carryforward. Since the ability to earn additional enhanced oil recovery credits is reduced or even eliminated based on the level of oil prices, our effective tax rate and cash taxes could both increase in the future if oil prices remain at current levels or increase further. Our overall current income tax credit for 2002 was 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. 40 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations 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 2004 2003 2002 - -------------------------------------------------------------------------------------------------------------- Oil and natural gas revenues $ 36.88 $ 30.43 $ 21.17 Gain (loss) on settlements of derivative contracts (7.01) (4.91) 0.07 Lease operating expenses (7.22) (7.06) (5.48) Production taxes and marketing expenses (1.55) (1.17) (0.92) - -------------------------------------------------------------------------------------------------------------- Production netback 21.10 17.29 14.84 CO2 operating margin relating to industrial sales 0.41 0.51 0.48 General and administrative expenses (1.78) (1.20) (0.96) Net cash interest expense (1.34) (1.61) (1.73) Current income taxes and other (1.78) (0.01) 0.04 Changes in assets and liabilities relating to operations (2.63) 0.62 (0.38) - -------------------------------------------------------------------------------------------------------------- Cash flow from operations 13.98 15.60 12.29 DD&A (8.09) (7.48) (7.26) Deferred income taxes (1.37) (2.08) (1.84) Non-cash hedging adjustments (0.11) 0.28 0.24 Changes in assets and liabilities, loss on early retirement of debt, change in accounting principle and other non-cash items 2.43 (1.86) 0.17 - -------------------------------------------------------------------------------------------------------------- Net income $ 6.84 $ 4.46 $ 3.60 - --------------------------------------------------------------------------------------------------------------
MARKET RISK MANAGEMENT We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. The following table presents the carrying and fair values of our debt, along with average interest rates. We had no bank debt outstanding as of December 31, 2004. 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 2005 2006 2007 2008 2009 Value Value - -------------------------------------------------------------------------------------------------------------------------- Fixed rate debt: Subordinated debt, net of discount - - - - - $223,397 $243,000 (The interest rate on the subordinated debt is a fixed rate of 7.5%.)
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. Historically, we have generally attempted 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, although our hedging percentage may vary relative to our debt levels. For 2005 and beyond, we have hedged significantly less, primarily because of our strong financial position resulted from our lower levels of debt relative to our cash flow from operations. When we make a significant acquisition, we generally attempt to hedge a large percentage, up to 100%, of the forecasted proved production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. Much of our historical hedging activity has been done with collars, although for the COHO acquisition, we also used swaps in order to lock in the prices used in our economic forecasts. For 2005, all of our oil hedges are puts or price floors, allowing us to retain any price upside, while still providing protection in the event of lower prices at a fixed and determinable price (i.e. the cost of the put). We anticipate using more price floors in the future. 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 41 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. For a full description of our hedging position at year-end 2004, see Note 9 to the Consolidated Financial Statements. Upon reaching a verbal agreement with the purchaser (Newfield Exploration Company) of our offshore properties, subject primarily to their further due diligence, we entered into natural gas swaps on a total of 23.6 Bcf for the period of July 2004 through December 2005, covering the anticipated natural gas production from our offshore properties for that period, with the tacit understanding with the prospective purchaser that these hedges would be transferred to them upon closing. These swaps did not qualify for hedge accounting and during the third quarter of 2004, we assigned them to Newfield. During the period that we owned them, we recognized approximately $2.5 million of gain as the hedges appreciated in value before we assigned them to Newfield. At about the same time, with the expectation that the offshore transaction would be consummated, we retired, by purchasing offsetting contracts, 20 MMcf/d of our natural gas hedges for July to December of 2004, at a cost of approximately $3.9 million. This transaction, net of the related gain on the hedges assigned to Newfield, was the primary reason for the $1.3 million net charge to earnings during 2004 relating to our derivative contracts that were not part of the monthly cash settlements on our derivatives contracts. At December 31, 2004, our derivative contracts were recorded at their fair value, which was a net liability of approximately $4.9 million, a decrease of approximately $39.7 million from the $44.6 million fair value liability recorded as of December 31, 2003. This change is the result of the expiration of most of our derivative contracts during 2004 due to the passage of time. Effective January 1, 2005, we have elected to de-designate our existing derivative contracts as hedges and to account for them as speculative contracts going forward. This means that any changes in the fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the balance to earnings. Information regarding our current hedging positions and historical hedging results is included in Note 9 to the Consolidated Financial Statements. Based on NYMEX crude oil futures prices at December 31, 2004, prices were considerably higher than the floor price of $27.50, so we would not expect to receive any funds even if oil prices were to drop 10%. Since the oil hedges are puts or price floors, we do not have to make any payments on the hedges regardless of how high oil prices would go. Based on NYMEX natural gas futures prices at December 31, 2004, we would expect to make future cash payments of $4.2 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 $0.8 million, and if futures prices were to increase by 10% we would expect to pay $7.6 million. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of financial statements in accordance with generally accepted accounting principles requires that we select certain accounting policies and make certain estimates and judgments regarding the application of those policies. Our significant accounting policies are included in Note 1 to the Consolidated Financial Statements. These policies, along with the underlying assumptions and judgments by our management in their application, have a significant impact on our consolidated financial statements. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our financial statements. Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Reserves Businesses involved in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and gas industry. We apply the full-cost method of accounting for our oil and natural gas properties. Another acceptable method of accounting for oil and gas production activities is the successful efforts method of accounting. In general, the primary differences between the two methods are related to the capitalization of costs and the evaluation for asset impairment. Under the full-cost method, all geological and geophysical costs, exploratory dry holes and delay rentals are capitalized to the full cost pool, whereas under the successful efforts method such costs are expensed as incurred. In the assessment of impairment of oil and gas properties, the successful efforts method follows the guidance of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," under which assets are measured for impairment against the undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the full cost pool (net book value of oil and gas properties) is measured against future cash flows discounted at ten percent using commodity prices in effect at the end of the reporting period. The financial results for a 42 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations given period could be substantially different depending on the method of accounting an oil and gas entity applies. In our application of full cost accounting for our oil and gas producing activities, we make significant estimates at the end of each period related to accruals for oil and gas revenues, production, capitalized costs and operating expenses. We calculate these estimates with our best available data, which includes among other things, production reports, price posting, information compiled from daily drilling reports and other internal tracking devices and analysis of historical results and trends. While management is not aware of any required revisions to its estimates, there will likely be future adjustments resulting from such things as changes in ownership interests, payouts, joint venture audits, re-allocations by the purchaser/pipeline, or other corrections and adjustments common in the oil and natural gas industry, many of which will require retroactive application. These types of adjustments cannot be currently estimated or determined and will be recorded in the period during which the adjustment occurs. Under full cost accounting, the estimated quantities of proved oil and natural gas reserves used to compute depletion and the related present value of estimated future net cash flows therefrom used to perform the full-cost ceiling test have a significant impact on the underlying financial statements. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepare the report, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statement disclosures. Over the last four years, Denbury's annual revisions to its reserve estimates have averaged approximately 3% of the previous year's estimates and have been both positive and negative. Changes in commodity prices also affect our reserve quantities. For instance, between 2001 and 2002, commodity prices rebounded from the prior year's fall, resulting in an increase to our reserve quantities of approximately 3.5 MMBOE. During 2003 and 2004, the change related to commodity prices was virtually zero, less than in prior years, as prices were relatively high at year-end 2002, 2003 and 2004. These changes in quantities affect our DD&A rate and the combined effect of changes in quantities and commodity prices impacts our full-cost ceiling test calculation. For example, we estimate that a 5% increase in our estimate of proved reserves quantities would have lowered our fourth quarter DD&A rate from $7.98 per Bbl to approximately $7.64 per Bbl and a 5% decrease in our proved reserve quantities would have increased our DD&A rate to approximately $8.35 per Bbl. Also, reserve quantities and their ultimate values are the primary factors in determining the borrowing base under our bank credit facility and are determined solely by our banks. There can also be significant questions as to whether reserves are sufficiently supported by technical evidence to be considered proven. In some cases our proven reserves are less than what we believe to exist because additional evidence, including production testing, is required in order to classify the reserves as proven. In other cases, properties such as certain of our potential tertiary recovery projects may not have proven reserves assigned to them primarily because we have not yet completed a specific plan for development or firmly scheduled such development. We have a corporate policy whereby we generally do not book proved undeveloped reserves unless the project has been committed to internally, which normally means it is scheduled within the next one to three years (or at least the commencement of the project is scheduled in the case of longer-term multi-year projects such as waterfloods and tertiary recovery projects). Therefore, particularly with regard to potential reserves from tertiary recovery (our CO2 operations), there is uncertainty as to whether the reserves should be included as proven or not. We also have a corporate policy whereby proved undeveloped reserves must be economic at long-term historical prices, which during the last two years are significantly less than the year-end prices used in our reserve report. This also can have the effect of eliminating certain projects being included in our estimates of proved reserves, which projects would otherwise be included if undeveloped reserves were determined to be economic solely based on current prices in a high price environment, as was the case at year-end 2003 and year-end 2004. (See "Depletion, Depreciation and Amortization" under "Results of Operations" above for a further discussion.) All of these factors and the decisions made regarding these issues can have a significant effect on our proven reserves and thus on our DD&A rate, full-cost ceiling test calculation, borrowing base and financial statements. 43 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations Asset Retirement Obligations We have significant obligations related to the plugging and abandonment of our oil and gas wells, and the removal of equipment and facilities from leased acreage and returning such land to its original condition. SFAS No. 143 requires that we estimate the future cost of this obligation, discount it to its present value, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our DD&A expense in future periods. See Note 4 to our Consolidated Financial Statements for further discussion regarding our asset retirement obligations. Income Taxes We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared, therefore we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and prior to year-end 2004, net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our enhanced oil recovery credits). If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2004, we believe that all of our deferred tax assets recorded on our Consolidated Balance Sheet will ultimately be recovered. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would increase in the period it is determined that recovery is not probable. A 1% change in our effective tax rate would have increased our calculated income tax expense by approximately $1,200,000, $800,000, and $700,000 for the years ended December 31, 2004, 2003 and 2002. See Note 7 to the Consolidated Financial Statements for further information concerning our income taxes. 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 was required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized currently in earnings. If the derivative qualifies for cash flow hedge accounting, the change in fair value of the derivative is recognized in 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, $282,000 for 2003 and $2.7 million for 2004. With the significant changes in commodity prices over the last two years, the fair value of our hedges has fluctuated significantly. While most of this change in value is recorded in other comprehensive income as most of our historical hedges have qualified for hedge accounting, 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. 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 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. Most our current derivative hedging instruments qualify for hedge accounting although we plan to abandon hedge accounting as of January 1, 2005. This means that any changes in the future fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging 44 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations the effective portion to other comprehensive income and the balance to earnings. For our three most recently completed fiscal years, if we had not chosen to designate hedge accounting treatment to our oil and natural gas hedge contracts, or if none of our derivative contracts had qualified for hedge accounting treatment, we estimate that our net income would have increased or (decreased) for 2004, 2003 and 2002 by the following amounts: $25.0 million, $(7.8) million and $(38.5) million. The preparation of financial statements requires us to make other estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and believe that the ultimate actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties and such risks and uncertainties could cause the actual results to differ materially from our estimates. RECENT ACCOUNTING PRONOUNCEMENTS On December 16, 2004, the Financial Accounting Standards Board ("FASB") issued SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows." Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) will require all share-based payments to employees, including grants of employee stock options, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. Pro forma disclosure is no longer an alternative. SFAS No. 123(R) must be adopted no later that July 1, 2005 and permits public companies to adopt its requirements using one of two methods: o A "modified prospective" method in which compensation cost is recognized based on the requirements of SFAS No. 123(R) for all share-based payments granted prior to the effective date of SFAS No. 123(R) that remain unvested on the adoption date. o A "modified retrospective" method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures. As permitted by SFAS No. 123, we currently account for share-based payments to employees using the intrinsic value method prescribed by APB 25 and related interpretations. As such, we generally do not recognize compensation expense associated with employee stock options. Accordingly, the adoption of SFAS No. 123(R)'s fair value method could have a significant impact on Denbury's future results of operations, although it will have no impact on our overall financial position. Had the Company adopted SFAS No 123(R) in prior periods, the impact would have approximated the impact of SFAS No. 123 as described in the pro forma net income and earnings per share disclosures above. The adoption of SFAS No. 123 (R) will have no effect on the Company's unvested outstanding restricted stock awards. We currently plan to adopt the provisions of SFAS No. 123(R) on July 1, 2005 using the modified prospective method. Although we have not completed evaluating the impact the adoption of SFAS No. 123(R) will have on our future results of operations, we currently estimate the impact on an annual basis will be similar to our pro forma disclosures for SFAS No. 123 in Note 1 to the Consolidated Financial Statements. SFAS No. 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may serve to reduce the Denbury's future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future. While we cannot estimate what those amounts will be in the future (because they depend, among other things, when employees exercise stock options), the amount of operating cash flows recognized in prior periods for such excess tax deductions were $4.8 million, $1.3 million and $0.7 million during the years ended December 31, 2004, 2003, and 2002, respectively. In July 2004, the Emerging Issues Task Force of the FASB issued EITF 04-05, "Investor's Accounting for an Investment in a Limited Partnership When the Investor is the Sole General Partner and the Limited Partners Have Certain Rights." In question is what rights held by the limited partners preclude consolidation of the limited partnership by the sole general partner. The Task Force noted that in practice differing views have evolved concerning this issue and it has asked the FASB staff to develop this issue for discussion at a future date. Denbury is the general partner of Genesis Energy, L.P. ("Genesis") and currently does not consolidate Genesis in its financial results based primarily on certain rights of the limited partner. This EITF has been issued for comment, with the comment period ending in February 2005. Based on our initial review of the proposed EITF, we currently do not believe that it will impact our consolidation treatment of Genesis; however, this determination is subject to further review and evaluation of the final rules. See Note 3, "Related Party Transactions - Genesis" for further information regarding Denbury's accounting for its investment in Genesis. 45 Denbury Resources Inc. Management's Discussion and Analysis of Financial Condition and Results of Operations FORWARD-LOOKING INFORMATION The statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not limited to, statements found in this Management's Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, cost savings, production rates and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters, mark-to-market values, competition and long-term forecasts of production, finding cost, rates of return, estimated costs, future capital expenditures and overall economics and other variables surrounding our tertiary operations and future plans. Such forward-looking statements generally are accompanied by words such as "plan," "estimate," "expect," "predict," "anticipate," "projected," "should," "assume," "believe", "target" or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management's current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company's financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company's oil and natural gas, inaccurate cost estimates, fluctuations in the prices of goods and services, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital or its availability, general economic conditions, competition and government regulations, unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or which are otherwise 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. 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 41 through 42. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - --------------------------------------------------- Page ---- Management's Report on Internal Control over Financial Reporting....... 47 Reports of Independent Registered Public Accounting Firms.............. 48-49 Consolidated Balance Sheets............................................ 50 Consolidated Statements of Operations.................................. 51 Consolidated Statements of Cash Flows.................................. 52 Consolidated Statements of Stockholders' Equity........................ 53 Consolidated Statements of Comprehensive Income........................ 54 Notes to Consolidated Financial Statements............................. 55-85 Supplemental Oil and Natural Gas Disclosures (Unaudited)............... 81 Quarterly Financial Information (Unaudited)............................ 85 46 MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Our management, including the Chief Executive Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our system of internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2004. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in INTERNAL CONTROL-INTEGRATED FRAMEWORK. Based on our management's assessment, we have concluded that our internal control over financial reporting was effective as of December 31, 2004 based on those criteria. Our management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report which appears herein. 47 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Denbury Resources Inc.: We have completed an integrated audit of Denbury Resources Inc.'s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audit, are presented below. Consolidated financial statements - --------------------------------- In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Denbury Resources Inc. and its subsidiaries (the "Company") at December 31, 2004, and the results of their operations and their cash flows for the year ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. Internal control over financial reporting - ----------------------------------------- Also, in our opinion, management's assessment, included in the accompanying "Management's Report on Internal Control over Financial Reporting," that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions. A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ PRICEWATERHOUSECOOPERS LLP - ------------------------------ Dallas, Texas March 14, 2005 48 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders of Denbury Resources Inc. We have audited the accompanying consolidated balance sheet of Denbury Resources Inc. and Subsidiaries (the "Company") as of December 31, 2003, and the related consolidated statements of operations, cash flows, stockholders' equity and comprehensive income for each of the two years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). 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 financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the financial statements under the caption "Asset Retirement Obligations", the Company changed its method of accounting for asset retirement obligations in 2003 as required by Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations". /s/ Deloitte & Touche LLP - ------------------------- Dallas, Texas March 8, 2004 49 Denbury Resources Inc. Consolidated Balance Sheets
(In Thousands, Except Shares) December 31, - ------------------------------------------------------------------------------------------------------- Assets 2004 2003 --------------- --------------- Current Assets Cash and cash equivalents...................................... $ 33,039 $ 24,188 Short-term investments......................................... 57,171 - Accrued production receivable.................................. 44,790 33,944 Related party receivable - Genesis............................. 745 6,927 Trade and other receivables, net of allowance of $236 and $238. 10,963 18,080 Deferred tax asset............................................. 25,189 25,016 Derivative assets.............................................. 949 - --------------- --------------- Total current assets......................................... 172,846 108,155 --------------- --------------- Property and Equipment Oil and natural gas properties (using full cost accounting) Proved....................................................... 1,326,401 1,409,579 Unevaluated.................................................. 20,253 46,065 CO2 properties and equipment................................... 132,685 85,467 Other ........................................................ 25,929 16,450 Less accumulated depletion and depreciation.................... (707,906) (705,050) --------------- --------------- Net property and equipment................................... 797,362 852,511 --------------- --------------- Investment in Genesis.......................................... 6,791 7,450 Other assets................................................... 15,707 14,505 --------------- --------------- Total Assets................................................. $ 992,706 $ 982,621 =============== =============== Liabilities and Stockholders' Equity Current Liabilities Accounts payable and accrued liabilities....................... $ 51,860 $ 62,349 Oil and gas production payable................................. 24,856 22,215 Derivative liabilities......................................... 5,815 42,010 Short-term capital lease obligations - Genesis................. 375 - --------------- --------------- Total current liabilities.................................... 82,906 126,574 --------------- --------------- Long-term Liabilities Capital lease obligations - Genesis............................ 4,184 - Long-term debt................................................. 223,397 298,203 Asset retirement obligations................................... 18,944 41,711 Derivative liabilities......................................... - 2,603 Deferred revenue - Genesis..................................... 23,378 21,468 Deferred tax liability......................................... 97,125 68,555 Other.......................................................... 1,100 2,305 --------------- --------------- Total long-term liabilities.................................. 368,128 434,845 --------------- --------------- Commitments and Contingencies (Note 10) 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; 56,607,877, and 54,190,042 shares issued at December 31, 2004 and 2003, respectively.................................. 57 54 Paid-in capital in excess of par............................... 441,023 401,709 Deferred compensation.......................................... (21,678) - Retained earnings ............................................. 129,104 46,656 Accumulated other comprehensive loss........................... (4,788) (27,113) Treasury stock, at cost, 93,072 and 8,162 shares at December 31, 2004 and 2003, respectively....................................... (2,046) (104) --------------- --------------- Total stockholders' equity................................... 541,672 421,202 --------------- --------------- Total Liabilities and Stockholders' Equity................... $ 992,706 $ 982,621 =============== ===============
See Notes to Consolidated Financial Statements. 50 Denbury Resources Inc. Consolidated Statements of Operations
(In Thousands, Except Per Share Data) Year Ended December 31, - -------------------------------------------------------------------------------------------------------------- 2004 2003 2002 ------------- ------------ ------------- Revenues Oil, natural gas and related product sales Unrelated parties............................................ $ 381,253 $ 336,521 $ 251,972 Related party - Genesis...................................... 63,524 48,942 22,922 CO2 sales and transportation fees Unrelated parties............................................ 1,183 7,512 7,580 Related party - Genesis...................................... 5,093 676 - Gain (loss) on effective hedge contracts....................... (70,469) (62,210) 932 Interest income and other...................................... 2,388 1,573 1,746 ------------- ------------ ------------- Total revenues............................................... 382,972 333,014 285,152 ------------- ------------ ------------- Expenses Lease operating expenses....................................... 87,107 89,439 71,188 Production taxes and marketing expenses........................ 17,569 14,819 11,902 Transportation expense - Genesis............................... 1,168 - - CO2 operating expenses......................................... 1,338 1,710 1,400 General and administrative..................................... 21,461 15,189 12,426 Interest....................................................... 19,468 23,201 26,833 Loss on early retirement of debt............................... - 17,629 - Depletion, depreciation and accretion.......................... 97,527 94,708 94,236 (Gain) loss on ineffective hedge contracts..................... 15,358 (3,578) (3,093) ------------- ------------ ------------- Total expenses............................................... 260,996 253,117 214,892 ------------- ------------ ------------- Equity in net income (loss) of Genesis........................... (136) 256 55 ------------- ------------ ------------- Income before income taxes....................................... 121,840 80,153 70,315 Income tax provision (benefit) Current income taxes........................................... 22,929 (91) (406) Deferred income taxes.......................................... 16,463 26,303 23,926 ------------- ------------ ------------- Income before cumulative effect of change in accounting principle 82,448 53,941 46,795 Cumulative effect of change in accounting principle, net of income taxes of $1,600................................................ - 2,612 - ------------- ------------ ------------- Net income....................................................... $ 82,448 $ 56,553 $ 46,795 ============= ============ ============= Net income per share - basic Income before cumulative effect of change in accounting principle $ 1.50 $ 1.00 $ 0.88 Cumulative effect of change in accounting principle............ - 0.05 - ------------- ------------ ------------- Net income per common share - basic............................ $ 1.50 $ 1.05 $ 0.88 ============= ============ ============= Net income per share - diluted Income before cumulative effect of change in accounting principle $ 1.44 $ 0.97 $ 0.86 Cumulative effect of change in accounting principle............ - 0.05 - ------------- ------------ ------------- Net income per common share - diluted.......................... $ 1.44 $ 1.02 $ 0.86 ============= ============ ============= Weighted average common shares outstanding Basic.......................................................... 54,871 53,881 53,243 Diluted........................................................ 57,301 55,464 54,365
See Notes to Consolidated Financial Statements. 51 Denbury Resources Inc. Consolidated Statements of Cash Flows
(In Thousands) Year Ended December 31, - -------------------------------------------------------------------------------------------------------------------------- 2004 2003 2002 -------------- ------------- ------------ Cash Flow from Operating Activities: Net income...................................................... $ 82,448 $ 56,553 $ 46,795 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and accretion........................ 97,527 94,708 94,236 Deferred income taxes........................................ 16,463 26,303 23,926 Deferred revenue - Genesis................................... (2,399) (322) - Deferred compensation - restricted stock..................... 1,601 - - Loss on early retirement of debt............................. - 17,629 - Non-cash hedging adjustments................................. 1,270 (3,578) (3,093) Amortization of debt issue costs and other................... 3,283 1,121 2,701 Cumulative effect of change in accounting principle.......... - (2,612) - Changes in assets and liabilities relating to operations: Accrued production receivable................................ (19,776) (3,079) (14,381) Trade and other receivables.................................. 7,475 (1,234) 15,078 Derivative assets and liabilities............................ (7,519) - 8,427 Other assets................................................. (166) 7 133 Accounts payable and accrued liabilities..................... (10,522) 8,862 (17,217) Oil and gas production payable............................... 2,641 4,906 3,869 Other liabilities............................................ (3,674) (1,649) (874) -------------- ------------- ------------ Net Cash Provided by Operating Activities........................ 168,652 197,615 159,600 -------------- ------------- ------------ Cash Flow Used for Investing Activities: Oil and natural gas expenditures............................... (167,001) (146,596) (99,273) Acquisitions of oil and gas properties......................... (11,069) (11,848) (56,364) Investment in Genesis.......................................... - (5,026) (2,170) Acquisition of CO2 assets and capital expenditures............. (50,265) (22,673) (16,445) Net purchases of other assets.................................. (5,210) (2,192) (3,688) Deposit on oil and gas property acquisitions................... (4,507) - - Increase in restricted cash.................................... (542) (848) (909) Purchases of short-term investments............................ (76,517) - - Sales of short-term investments................................ 19,350 - - Net proceeds from CO2 production payment - Genesis............. 4,636 23,895 - Proceeds from sales of oil and gas properties.................. 10,042 29,410 7,688 Sale of Denbury Offshore, Inc.................................. 187,533 - - -------------- ------------- ------------ Net Cash Used for Investing Activities........................... (93,550) (135,878) (171,161) -------------- ------------- ------------ Cash Flow from Financing Activities: Bank repayments................................................ (88,000) (160,000) (40,000) Bank borrowings................................................ 13,000 85,000 49,130 Payments on capital lease obligations - Genesis................ (32) - - Repayment of subordinated debt obligations, including redemption premium - (209,000) - Issuance of subordinated debt, net of discount................. - 223,054 - Issuance of common stock....................................... 13,168 5,537 3,594 Purchase of treasury stock..................................... (3,977) (1,268) - Costs of debt financing........................................ (410) (4,812) (719) -------------- ------------- ------------ Net Cash Provided by (Used for) Financing Activities............. (66,251) (61,489) 12,005 -------------- ------------- ------------ Net Increase in Cash and Cash Equivalents........................ 8,851 248 444 Cash and cash equivalents at beginning of year................... 24,188 23,940 23,496 -------------- ------------- ------------ Cash and cash equivalents at end of year......................... $ 33,039 $ 24,188 $ 23,940 ============== ============= ============
See Notes to Consolidated Financial Statements. 52 Denbury Resources Inc. Consolidated Statements of Changes in Stockholders' Equity
Paid-In Accumulated Treasury Common Stock Capital Restricted Retained Other Stock ($.001 Par Value) in Stock Earnings Comprehensive (at cost) Total ------------------- Excess Deferred (Accumulated Income -------------- Stockholders' (Dollar amounts in Thousands) Shares Amount of Par Compensation Deficit) (Loss) Shares Amount Equity - --------------------------------------------------------------------------------------------------------------------------------- Balance - December 31, 2001 52,956,825 $ 53 $391,557 $ - $(56,670) $ 14,228 - $ - $349,168 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 Derivative contracts, net - - - - - (33,516) - - (33,516) Net income - - - - 46,795 - - - 46,795 ---------------------------------------------------------------------------------------------------- Balance - December 31, 2002 53,539,329 54 395,906 - (9,875) (19,288) - - 366,797 --------------------------------------------------------------------------------------------------- Repurchase of common stock - - - - - - 100,000 (1,276) (1,276) Issued pursuant to employee stock purchase plan 94,968 - 1,174 - (22) - (91,838) 1,172 2,324 Issued pursuant to employee stock option plan 550,090 - 3,213 - - - - - 3,213 Issued pursuant to directors' compensation plan 5,655 - 69 - - - - - 69 Tax benefit from stock options - - 1,347 - - - - - 1,347 Derivative contracts, net - - - - - (7,825) - - (7,825) Net income - - - - 56,553 - - - 56,553 --------------------------------------------------------------------------------------------------- Balance - December 31, 2003 54,190,042 54 401,709 - 46,656 (27,113) 8,162 (104) 421,202 ---------------------------------------------------------------------------------------------------- Repurchase of common stock - - - - - - 200,000 (3,977) (3,977) Issued pursuant to employee stock purchase plan - - 396 - - - (115,090) 2,035 2,431 Issued pursuant to employee stock option plan 1,264,284 2 10,737 - - - - - 10,739 Issued pursuant to directors' compensation plan 3,551 - 82 - - - - - 82 Restricted stock grants 1,150,000 1 23,278 (23,279) - - - - - Amortization of deferred compensation - - - 1,601 - - - - 1,601 Tax benefit from stock options - - 4,821 - - - - - 4,821 Derivative contracts, net - - - - - 22,349 - - 22,349 Unrealized loss on available- for-sale securities - - - - - (24) - - (24) Net income - - - - 82,448 - - - 82,448 ---------------------------------------------------------------------------------------------------- Balance - December 31, 2004 56,607,877 $ 57 $441,023 $ (21,678) $ 129,104 $(4,788) 93,072 $(2,046) $541,672 ====================================================================================================
See Notes to Consolidated Financial Statements. 53 Denbury Resources Inc. Consolidated Statements of Comprehensive Income
(In Thousands) Year Ended December 31, - --------------------------------------------------------------------------------------------------------------------------- 2004 2003 2002 ------------- ------------- ------------- Net Income......................................................... $ 82,448 $ 56,553 $ 46,795 Other comprehensive income (loss), net of tax: Change in fair value of derivative contracts, net of tax of ($19,328), ($26,969) and ($18,784), respectively............... (31,535) (44,002) (30,648) Reclassification adjustments related to settlements of derivative contracts, net of tax of $33,025, $22,173 and ($1,758), respectively 53,884 36,177 (2,868) Unrealized loss on securities available for sale, net of tax of ($15) (24) - - ------------- ------------- ------------- Comprehensive Income............................................... $ 104,773 $ 48,728 $ 13,279 ============= ============= =============
See Notes to Consolidated Financial Statements. 54 Denbury Resources Inc. 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. We also own the rights to a natural source of carbon dioxide ("CO2") reserves that we use for injection in our tertiary oil recovery operations. We also sell some of the CO2 we produce to third parties for various 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 publicly traded master limited partnership. During 2003, we acquired additional Genesis limited partnership units, increasing our ownership interest in Genesis from 2% to 9.25%. We account for our ownership interest in Genesis under the equity method of accounting. 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 3 for more information regarding our related party transactions with Genesis and summary financial information. All material intercompany balances and transactions have been eliminated. We have evaluated our consolidation of variable interest entities in accordance with FASB Interpretation No. 46, "Consolidation of Variable Interest Entities," and have concluded that we do not have any variable interest entities that would require consolidation. Effective December 29, 2003, Denbury Resources Inc. changed its corporate structure to a holding company format. The purposes of creating the holding company structure were to better reflect the operating practices and methods of Denbury, to improve its economics, and to provide greater administrative and operational flexibility. As part of this restructure, Denbury Resources Inc. (predecessor entity) merged into a newly formed limited liability company and survived as Denbury Onshore, LLC, a Delaware limited liability company and an indirect subsidiary of the newly formed holding company, Denbury Holdings, Inc. Denbury Holdings, Inc. subsequently assumed the name Denbury Resources Inc. (new entity). The reorganization was structured as a tax free reorganization to Denbury's stockholders and all outstanding capital stock of the original public company was automatically converted into the identical number of and type of shares of the new public holding company. Stockholders' ownership interests in the business did not change as a result of the new structure and shares of the Company remained publicly traded under the same symbol (DNR) on the New York Stock Exchange. The new parent holding company is co-obligor (or guarantor, as appropriate) regarding the payment of principal and interest on Denbury's outstanding debt securities. 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 55 Denbury Resources Inc. Notes to Consolidated Financial Statements 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) ASSET RETIREMENT OBLIGATIONS. On January 1, 2003, we adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. 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, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant. Prior to the adoption of this new standard, we recognized a provision for our asset retirement obligations each period as part of our depletion and depreciation calculation, based on the unit-of-production method. See Note 4 for more information regarding our change in accounting related to the adoption of SFAS No. 143. 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 before future abandonment costs (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 13 for information on our proved oil and natural gas reserves and the basis on which they are recorded. Property and equipment - Other Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, are depreciated principally on a straight-line basis over estimated useful lives. Estimated useful lives are generally as follows: furniture and fixtures and vehicles 5 to 10 years; and computer equipment and software 3 to 5 years. Leased property meeting certain capital lease criteria is capitalized and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term. 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 56 Denbury Resources Inc. Notes to Consolidated Financial Statements extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2004 and 2003, 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. In accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, derivative financial instruments are 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 instruments that qualify for hedge accounting 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 re-designated, deferred gains or losses on the hedging instrument are recognized in earnings immediately. Receipts and payments resulting from settlements of derivative hedging instruments qualifying for hedge accounting are recorded in "Gain (loss) on effective hedge 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 "Gain (loss) on ineffective hedge contracts" under expenses in the Consolidated Statements of Operations. Denbury's hedging activities are further discussed in Note 9. Effective January 1, 2005, we have decided to de-designate from hedge accounting treatment our existing derivative hedging instruments. As such, we will account for our derivative instruments in future periods as speculative contracts and future changes in the fair value of these instruments will be recognized in the income statement in the period of change. While this change may result in more volatility in our income in future periods, we believe that the benefits associated with applying hedge accounting do not outweigh the cost, time and effort required to apply hedge accounting. 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, short-term investments, trade and accrued production receivables and the derivative hedging instruments discussed above. Our cash equivalents and short-term investments 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 57 Denbury Resources Inc. Notes to Consolidated Financial Statements 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. There are no margin requirements with the counterparties of our derivative contracts. 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 Genesis and to other 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 expenses" and the expenses related to our own uses are recorded in "Lease operating expenses" 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. We evaluate our CO2 assets for impairment by comparing our expected future revenues from these assets to their net carrying value. 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. Short-term Investments Our short-term investments consist primarily of investment grade debt securities that are classified as "available-for-sale" in accordance with the provisions of SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Available-for-sale securities are stated at fair value, based on quoted market prices, with the unrealized gain or loss, net of tax, reported in other comprehensive income. Premiums and discounts are amortized or accreted into earnings over the life of the related security. Dividend and interest income is recognized when earned. We have no investments that are considered to be trading securities. The following is a summary of current available-for-sale marketable securities at December 31, 2004:
(In Thousands) December 31, 2004 - --------------------------------------------------------------------------------------------------------- Gross Gross Amortized Unrealized Unrealized Estimated Cost Gains Losses Fair Value ----------------------------------------------------- Certificate of deposits....................... $ 2,000 $ - $ - $ 2,000 Government and agency obligations............. 17,470 - (14) 17,456 Other debt securities......................... 37,739 4 (28) 37,715 ------------- ------------ ------------- ------------ Total current available-for-sale securities $ 57,209 $ 4 $ (42) $ 57,171 ============= ============ ============= ============
Restricted Cash and Investments At December 31, 2004 and 2003, we had approximately $6.4 million and $9.5 million, respectively, of restricted cash and investments held in escrow accounts for future site reclamation costs. These balances are recorded at amortized cost and are included in "Other Assets" in the Consolidated Balance Sheets. The estimated fair market value of these investments at December 31, 2004 and 2003 was the same as amortized cost. 58 Denbury Resources Inc. Notes to Consolidated Financial Statements 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, restricted stock and any other outstanding convertible securities. For each of the three years in the period ended December 31, 2004, 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:
(In Thousands) Year Ended December 31, - --------------------------------------------------------------------------------------------------- 2004 2003 2002 ------------ ------------- ------------ Weighted average common shares - basic............. 54,871 53,881 53,243 Potentially dilutive securities: Stock options.................................. 2,413 1,583 1,122 Restricted stock............................... 17 - - ------------ ------------- ------------ Weighted average common shares - diluted........... 57,301 55,464 54,365 ============ ============= ============
The weighted average common shares - basic amount in 2004 excludes 1,150,000 shares of non-vested restricted stock granted in 2004 that is subject to future time vesting requirements. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share. For purposes of calculating weighted average common shares - diluted, the non-vested restricted stock is included in the computation using the treasury stock method, with the proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. The restricted shares were issued in August through December 2004 and have been included in the calculation for the periods they were outstanding. These shares may result in greater dilution in future periods, depending on the market price of our common stock during those periods. We excluded stock options representing 40,000 shares in 2004, 1.0 million shares in 2003 and 1.7 million shares in 2002 from our diluted shares outstanding because their inclusion would be antidilutive, as their exercise prices exceeded the average market price of our common stock during the respective periods. Stock-Based Compensation We issue stock options to all of our employees under our stock option plans, which are described more fully in Note 8. We account for our stock options utilizing the recognition and measurement principles of Accounting Principles Board Opinion 25 (APB 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," as amended by SFAS No. 148, in accounting for our stock options. 59 Denbury Resources Inc. Notes to Consolidated Financial Statements
(In Thousands, Except Per Share Data) Year Ended December 31, - -------------------------------------------------------------------------------------------------------------------- 2004 2003 2002 ------------- ------------ ------------- Net income: Net income, as reported............................................ $ 82,448 $ 56,553 $ 46,795 Add: Stock-based compensation included in reported net income, net of related tax effects.............................................. 977 - - Less: Stock-based compensation expense applying fair value based method, net of related tax effects......................... 3,772 3,101 2,853 ------------- ------------ ------------- Pro forma net income............................................... $ 79,653 $ 53,452 $ 43,942 ============= ============ ============= Net income per common share As reported: Basic............................................................ $ 1.50 $ 1.05 $ 0.88 Diluted.......................................................... 1.44 1.02 0.86 Pro forma: Basic............................................................ $ 1.45 $ 0.99 $ 0.83 Diluted.......................................................... 1.40 0.98 0.83
The weighted average fair value of options granted using the Black-Scholes option pricing model and the weighted average assumptions used in determining those fair values are as follows:
2004 2003 2002 ------------- ------------ ------------ Weighted average fair value of options granted... $ 6.44 $ 6.02 $ 4.17 Risk free interest rate.......................... 3.34% 2.94% 4.05% Expected life.................................... 5 years 5 years 5 years Expected volatility.............................. 46.8% 59.6% 61.4% 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 (i) the fair value of financial derivative instruments, (ii) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and ceiling test, (iii) accruals related to oil and gas production and revenues, capital expenditures 60 Denbury Resources Inc. Notes to Consolidated Financial Statements and lease operating expenses, (iv) the estimated costs and timing of future asset retirement obligations, and (v) estimates made in the calculation of income taxes. While management is not aware of any significant revisions to any of its estimates, there will likely be future revisions to its estimates resulting from matters such as changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs. 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. Recent Accounting Pronouncements On December 16, 2004, the Financial Accounting Standards Board ("FASB") issued SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows." Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) will require all share-based payments to employees, including grants of employee stock options, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. Pro forma disclosure is no longer an alternative. SFAS No. 123(R) must be adopted no later that July 1, 2005 and permits public companies to adopt its requirements using one of two methods: o A "modified prospective" method in which compensation cost is recognized based on the requirements of SFAS No. 123(R) for all share-based payments granted prior to the effective date of SFAS No. 123(R) that remain unvested on the adoption date. o A "modified retrospective" method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures. As permitted by SFAS No. 123, we currently account for share-based payments to employees using the intrinsic value method prescribed by APB 25 and related interpretations. As such, we generally do not recognize compensation expense associated with employee stock options. Accordingly, the adoption of SFAS No. 123(R)'s fair value method could have a significant impact on Denbury's future results of operations, although it will have no impact on our overall financial position. Had the Company adopted SFAS No 123(R) in prior periods, the impact would have approximated the impact of SFAS No. 123 as described in the pro forma net income and earnings per share disclosures above. The adoption of SFAS No. 123(R) will have no effect on the Company's unvested outstanding restricted stock awards. We currently plan to adopt the provisions of SFAS No. 123(R). Although we have not completed evaluating the impact the adoption of SFAS No. 123(R) will have on our future results of operations, we currently estimate the impact on an annual basis will be similar to our pro forma disclosures for SFAS No. 123 above. SFAS No. 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may serve to reduce the Denbury's future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future. While we cannot estimate what those amounts will be in the future (because they depend, among other things, when employees exercise stock options), the amount of operating cash flows recognized in prior periods for such excess tax deductions were $4.8 million, $1.3 million and $0.7 million during the years ended December 31, 2004, 2003, and 2002, respectively. In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (SAB 106), which clarifies the calculation of the full cost ceiling and depreciation, depletion, and amortization ("DD&A") of oil and gas properties in conjunction with accounting for asset retirement obligations under SFAS No. 143. The guidance in SAB 106 had no impact on our consolidated financial statements. 61 Denbury Resources Inc. Notes to Consolidated Financial Statements NOTE 2. ACQUISITIONS AND DIVESTITURES Sale of Denbury Offshore, Inc. On July 20, 2004, we closed the sale of Denbury Offshore, Inc., a subsidiary that held our offshore assets, for $200 million (before adjustments) to Newfield Exploration Company. The sale price was based on the asset value of the offshore assets as of April 1, 2004, which means that the net operating cash flow (defined as revenue less operating expenses and capital expenditures) from these properties which we received between April 1st and closing, as well as expenses of the sale and other contractual adjustments, reduced the purchase price to approximately $187 million. We excluded from the sale a discovery well drilled at High Island A-6 during 2004, and certain deep rights at West Delta 27 that we sold for $1.8 million in December 2004, but retained a carried interest in a deep exploratory well. Our financial results for 2004 include production, revenues, operating expenses, and capital expenditures of the offshore properties through July 19, 2004. Revenues of Denbury Offshore, Inc. included in our 2004 results were $62.6 million. We recorded the proceeds from the sale as a reduction to our full cost pool. We paid approximately $21 million of current income taxes relating to the sale and paid approximately $2.4 million of employee severance costs in 2004. We used $85 million of the sales proceeds to retire our bank debt. Our offshore properties made up approximately 12.5% of our year-end 2003 proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented approximately 25% of our 2004 second quarter production (9,114 BOE/d). COHO Gulf Coast Properties In August 2002, we acquired the Gulf Coast properties of COHO Energy, Inc., auctioned in the U.S. Bankruptcy Court in Dallas, Texas. Our net purchase price was $48.2 million and included nine fields, eight of which are located in Mississippi and one in Texas. At December 31, 2002, these properties had reserves of approximately 15.1 million barrels of oil and net production of approximately 4,000 barrels of oil per day. The Mississippi fields included 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. In February 2003, we sold Laurel Field, acquired in the COHO acquisition, for $25.9 million and other consideration which included an interest in Atchafalaya Bay Field (where we already owned an interest) and seismic over that area. At December 31, 2002, Laurel Field had approximately 7.4 MMBbls of proved reserves. In March 2003, we sold the Bentonia and Glazier fields for approximately $1.6 million. The proceeds from the sale of Laurel Field were used to reduce our bank debt. 62 Denbury Resources Inc. Notes to Consolidated Financial Statements NOTE 3. RELATED PARTY TRANSACTIONS - GENESIS On May 14, 2002, a newly formed subsidiary of Denbury acquired Genesis Energy, L.L.C. (which was susequently converted to Genesis Energy, Inc.), the general partner of Genesis, a publicly traded master limited partnership, for total consideration, including expenses and commissions, of approximately $2.2 million. Genesis has two primary lines of business: crude oil gathering and marketing and pipeline transportation, primarily in Mississippi, Texas, Alabama and Florida. In November 2003, through our subsidiary general partner, we purchased an additional 689,000 partnership common units and 14,000 general partner units of Genesis for $7.15 per unit, with an aggregate purchase price of approximately $5.0 million. With these additional units, our ownership interest increased to approximately 9.25% (2.0% general partner ownership and 7.25% limited partner ownership). We are accounting for our 9.25% ownership in Genesis under the equity method of accounting as we have significant influence over the limited partnership; however, our control is limited under the limited partnership agreement and therefore, we do not consolidate Genesis. Our equity in Genesis' net income (loss) for 2004 was ($136,000), for 2003 was $256,000 and for 2002 was $55,000, representing 2% of Genesis' net income (loss) for the periods from May 14, 2002 through October 31, 2003 and 9.25% of Genesis' net income (loss) for the periods from November 1, 2003 through December 31, 2004. Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which consisted of $15.3 million of debt and $22.8 million in letters of credit at December 31, 2004. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. Our investment in Genesis of $7.2 million exceeded our percentage of net equity in the limited partnership at the time of acquisition by approximately $2.2 million, which represents goodwill and is not subject to amortization. The fair value of our investment in Genesis was $11.1 million at December 31, 2004, based on quoted market values. Over the past several years, including the period prior to our investment in Genesis, we sold certain of our oil production to Genesis. Beginning in September 2004, we elected to sell our own crude oil to independent third parties rather than to Genesis. As such, we discontinued our direct sales to Genesis and began to transport our crude oil to our sales point using Genesis' common carrier pipeline. For these transportation services, we pay Genesis a fee for the use of their pipeline and trucking services. For 2004, we expensed $1.2 million for these transportation services. At December 31, 2004, we had a receivable from Genesis of $0.7 million and $6.9 million at December 31, 2003. We recorded oil sales to Genesis of $63.5 million, $48.9 million and $22.9 million for the years ended December 31, 2004, 2003, and 2002, respectively. Denbury received other miscellaneous payments from Genesis, including $120,000 in both 2004 and 2003 in director fees for certain executive officers of Denbury that are board members of Genesis, and $508,000 in 2004 and $57,000 in 2003 of pro rata dividend distributions from Genesis. Transportation Leases During 2004, we requested that Genesis build two pipelines for our benefit. The pipelines were to transport our crude oil from Olive and McComb Fields in Southwest Mississippi to Genesis' main crude oil pipeline to improve our ability to market our crude oil, and to transport CO2 from our main CO2 pipeline to Brookhaven Field for our tertiary operations. As part of these arrangements, we entered into two transportation agreements. The first agreement, entered into in November, was to transport crude oil from Olive Field. This agreement is for 10 years and has a minimum payment of approximately $18,000 per month. This minimum monthly charge will increase for any volumes transported in excess of a stated monthly volume. In December, we entered into the second transportation agreement to transport CO2 to Brookhaven Field in Southwest Mississippi. This agreement is for an eight-year period and has minimum payments of approximately $49,000 per month. This minimum monthly payment will increase for any volumes transported in excess of a stated monthly volume. Genesis will operate and maintain these pipelines at its own expense. We have accounted for these agreements as capital leases. The pipelines held under these capital leases are classified as property and equipment and are amortized using the straight-line method over the lease terms. Lease amortization is included in depreciation expense. The related obligations are recorded as debt. At December 31, 2004, we had $4.6 million recorded as debt, of which $375,000 was current. 63 Denbury Resources Inc. Notes to Consolidated Financial Statements CO2 Volumetric Production Payment In November 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million ($23.9 million as adjusted for interim cash flows from the September 1, 2003 effective date and for transaction costs) under a volumetric production payment ("VPP"), and assigned to Genesis three of our existing long-term commercial CO2 supply agreements with our industrial customers. These industrial contracts represented approximately 60% of our then current industrial CO2 sales volumes. Pursuant to the VPP, Genesis may take up to 52.5 MMcf/d of CO2 through 2009, 43.0 MMcf/d from 2010 through 2012, and 25.2 MMcf/d to the end of the term. On August 26, 2004, we closed on another transaction with Genesis, selling to them a 33.0 Bcf volumetric production payment ("VPPII") of CO2 for $4.8 million ($4.6 million as adjusted for interim cash flows from the July 1 effective date and for transaction costs) along with a related long-term supply agreement with an industrial customer. Pursuant to the VPPII, Genesis may take up to 9 MMcf/d of CO2 to the end of the contract term. We have recorded the net proceeds of these volumetric production payment sales as deferred revenue and will recognize such revenue as CO2 is delivered during the term of the two volumetric production payments. At December 31, 2004 and 2003, $25.8 million and $23.6 million, respectively, was recorded as deferred revenue of which $2.4 million and $2.1 million was included in current liabilities at December 31, 2004 and 2003, respectively. During 2004 and 2003, we recognized deferred revenue of $2.4 million and $0.3 million, respectively, for deliveries under the VPP and VPPII. We provide Genesis with certain processing and transportation services in connection with these agreements for a fee of approximately $0.16 per Mcf of CO2 delivered to their industrial customers, which resulted in $2.7 million and $0.4 million in revenue to Denbury for the years ended December 31, 2004 and 2003, respectively. Summarized financial information of Genesis Energy, L.P.
(In Thousands) Year Ended December 31, - --------------------------------------------------------------------------------- 2004 2003 ------------------- ----------------- Revenues................................. $ 927,143 $ 657,897 Cost of sales............................ 908,804 644,157 Other expenses........................... 19,288 14,159 Income (loss) from discontinued operations (463) 13,741 ------------------- ----------------- Net income (loss)...................... $ (1,412) $ 13,322 =================== ================= December 31, December 31, 2004 2003 ------------------- ----------------- Current assets........................... $ 77,396 $ 88,211 Non-current assets....................... 65,758 58,904 ------------------- ----------------- Total assets........................... $ 143,154 $ 147,115 =================== ================= Current liabilities...................... $ 81,938 $ 87,244 Non-current liabilities.................. 15,460 7,000 Partners' capital........................ 45,756 52,871 ------------------- ----------------- Total liabilities and partners' capital $ 143,154 $ 147,115 =================== =================
NOTE 4. ASSET RETIREMENT OBLIGATIONS On January 1, 2003, we adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil and natural gas wells, removal of equipment and facilities from leased 64 Denbury Resources Inc. Notes to Consolidated Financial Statements acreage and returning such land to its original condition. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Prior to the adoption of this new standard, we recognized a provision for our asset retirement obligations each period as part of our depletion and depreciation calculation, based on the unit-of-production method. The adoption of SFAS No. 143 on January 1, 2003, required us to record (i) a $41.0 million liability for our future asset retirement obligations (an increase of $34.1 million in our liability for asset retirement obligations that we had recorded at December 31, 2002), (ii) a $34.4 million increase in oil and natural gas properties, (iii) a $3.9 million decrease in accumulated depreciation and depletion, and (iv) a $2.6 million gain as a cumulative effect adjustment of a change in accounting principle, net of taxes. The following pro forma data summarizes Denbury's net income and net income per common share as if we had applied the provisions of SFAS No. 143 in prior periods, and as if we had removed the first quarter 2003 cumulative effect adjustment for the adoption of SFAS No. 143:
(In Thousands, except per share data) Year Ended December 31, - --------------------------------------------------------------------------------------------------- 2003 2002 ------------ --------------- Net income, as reported.......................................... $ 56,553 $ 46,795 Pro forma adjustments to reflect retroactive adoption of SFAS 143.................................................... (2,612) 473 ------------ --------------- Pro forma net income ............................................ $ 53,941 $ 47,268 ============ =============== Net income per common share: As reported: Basic.......................................................... $ 1.05 $ 0.88 Diluted........................................................ 1.02 0.86 Pro forma: Basic.......................................................... $ 1.00 $ 0.89 Diluted........................................................ 0.97 0.87
The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2004 and 2003.
(In Thousands) Year Ended December 31, - ------------------------------------------------------------------------------------------------------------- 2004 2003 ----------------- --------------- Beginning asset retirement obligation............................... $ 43,812 $ 6,845 Cumulative effect adjustment for SFAS No. 143, January 1, 2003.... - 34,110 Liabilities incurred during period................................ 3,206 3,405 Liabilities settled during period................................. (2,549) (1,007) Liabilities sold during period.................................... (25,337) (2,393) Accretion expense................................................. 2,408 2,852 ----------------- ---------------- Ending asset retirement obligation.................................. $ 21,540 $ 43,812 ================= ================
Liabilities sold during the period primarily represent the asset retirement obligations previously associated with our offshore assets held by Denbury Offshore, Inc., which we sold in July 2004. At December 31, 2004 and 2003, $2.6 million and $2.1 million of our asset retirement obligation was classified in "Accounts payable and accrued liabilities" under current liabilities in our Consolidated Balance Sheets. We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $6.4 million at December 31, 2004, and $9.5 million at December 31, 2003, and are included in "Other Assets" in our Consolidated Balance Sheets. 65 Denbury Resources Inc. Notes to Consolidated Financial Statements NOTE 5. PROPERTY AND EQUIPMENT
(In Thousands) December 31, - ------------------------------------------------------------------------------ 2004 2003 -------------- -------------- Oil and natural gas properties: Proved properties........................ $ 1,326,401 $ 1,409,579 Unevaluated properties................... 20,253 46,065 -------------- -------------- Total.................................. 1,346,654 1,455,644 Accumulated depletion and depreciation..... (686,799) (690,395) -------------- -------------- Net oil and natural gas properties....... 659,855 765,249 -------------- -------------- CO2 properties............................. 132,685 85,467 Accumulated depletion and depreciation..... (10,636) (5,971) -------------- -------------- Net CO2 properties....................... 122,049 79,496 -------------- -------------- Other ..................................... 25,929 16,450 Accumulated depletion and depreciation..... (10,471) (8,684) -------------- -------------- Net other................................ 15,458 7,766 -------------- -------------- Net property, equipment and other........ $ 797,362 $ 852,511 ============== ==============
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 can be assigned to such properties. A summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 2004 and 2003 and the year in which they were incurred follows:
(In Thousands) December 31, 2004 December 31, 2003 - ------------------------------------------------------------------------------------- -------------------------------------------- Costs Incurred During: Costs Incurred During: -------------------------------------------- --------------------------------- 2004 2003 2002 2001 Total 2003 2002 2001 Total ------------------------------------------------------ -------------------------------------------- Property acquisition costs.. $ 3,400 $ 2,519 $ 1,207 $ 1,798 $ 8,924 $ 3,640 $ 6,301 $ 21,169 $ 31,110 Exploration costs........... 3,787 2,771 3,550 1,221 11,329 6,528 5,291 3,136 14,955 ------------------------------------------------------ -------------------------------------------- Total....................... $ 7,187 $ 5,290 $ 4,757 $ 3,019 $ 20,253 $ 10,168 $ 11,592 $ 24,305 $ 46,065 ====================================================== ============================================
Costs are transferred into the amortization base on an ongoing basis as the projects are evaluated and proved reserves established or impairment determined. We review the excluded properties for impairment at least annually. We currently estimate that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within five years. 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. 66 Denbury Resources Inc. Notes to Consolidated Financial Statements NOTE 6. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
(In Thousands) December 31, - ------------------------------------------------------------------------------- 2004 2003 ------------- ------------ 7.5% Senior Subordinated Notes due 2013............ $ 225,000 $ 225,000 Discount on Senior Subordinated Notes.............. (1,603) (1,797) Capital lease obligations - Genesis................ 4,559 - Senior bank loan................................... - 75,000 ------------- ------------ Total............................................ 227,956 298,203 Less current obligations........................... 375 - ------------- ------------ Long-term debt and capital lease obligations.... $ 227,581 $ 298,203 ============= ============
Senior Bank Loan On September 1, 2004, we entered into a new bank credit agreement which modified the prior agreement by (i) creating a structure wherein the commitment amount and borrowing base amount are no longer the same, (ii) improving our credit pricing by reducing the interest rate chargeable at certain levels of borrowing, (iii) extending the term by three years to April 30, 2009, (iv) reducing the collateral requirements, (v) authorizing up to $20 million of possible future CO2 volumetric production payment transactions with Genesis Energy, and (vi) other minor modifications and corrections. Under the new agreement, our borrowing base is currently set at $200 million, with an initial commitment amount of $100 million. The borrowing base represents the amount we can borrow from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount we asked the banks to commit to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request made by us in excess of the commitment amount, up to the borrowing base limit, although they are not obligated to fund any amount in excess of $100 million, the commitment amount. The advantage to us is that we will pay commitment fees on the commitment amount, not the borrowing base, thus lowering our overall cost of available credit. The bank 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, 2004. Our bank credit facility provides for a semi-annual re-determination of the borrowing base on April 1 and October 1. Borrowings under the credit facility are generally in tranches that can have maturities up to one year. Interest on any borrowings are based on the Prime Rate or LIBOR rate plus an applicable margin as determined by the borrowings outstanding. The facility matures in April 2009. As of December 31, 2004, we had no outstanding borrowings under the facility and $460,000 in letters of credit secured by the facility. The next scheduled re-determination of the borrowing base will be as of April 1, 2005, based on December 31, 2004 assets and proved reserves. Subordinated Debt Issuance of 7.5% Senior Subordinated Notes due 2013 On March 25, 2003, we issued $225 million of 7.5% Senior Subordinated Notes due 2013. The notes were priced at 99.135% of par and we used most of our $218.4 million of net proceeds from the offering, after underwriting and issuance costs, to retire our existing $200 million of 9% Senior Subordinated Notes due 2008, including the Series B notes (see "Redemption of 9% Senior Subordinated Notes due 2008 (Including Series B Notes)" below). 67 Denbury Resources Inc. Notes to Consolidated Financial Statements The notes mature on April 1, 2013 and interest on the notes is payable each April 1 and October 1. We may redeem the notes at our option beginning April 1, 2008 at the following redemption prices: 103.75% after April 1, 2008, 102.5% after April 1, 2009, 101.25% after April 1, 2010, and 100% after April 1, 2011 and thereafter. In addition, prior to April 1, 2006, we may redeem up to 35% of the notes at a redemption price of 107.5% with net cash proceeds from a stock offering. The indenture under which the notes were issued is essentially the same as the indenture covering our previously outstanding 9% notes. The indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The notes are not subject to any sinking fund requirements. All of our significant subsidiaries fully and unconditionally guarantee this debt. In connection with our internal reorganization to a holding-company-organizational structure (see Note 1), we entered into a First Supplemental Indenture dated December 29, 2003, which did not require the consent of the holders of the 7.5% Senior Subordinated Notes due 2013. The supplemental indenture made Denbury Resources Inc. and Denbury Onshore, LLC, co-obligors of this debt. All of our significant subsidiaries continue to fully and unconditionally guarantee this debt. There were no other significant changes as part of the amendment. Redemption of 9% Senior Subordinated Notes due 2008 (Including Series B Notes) On April 16, 2003, we redeemed our $200 million of 9% Senior Subordinated Notes due 2008 at an aggregate cost of $209.0 million, including a $9.0 million call premium. As a result of this early redemption, we recorded a before-tax charge to earnings in the second quarter of 2003 of $17.6 million ($11.5 million after income tax), which included the $9.0 million call premium and the write-off of the remaining discount and debt issuance costs associated with these notes. Indebtedness Repayment Schedule As of December 31, 2004, our indebtedness, excluding the discount on our senior subordinated debt, is repayable over the next five years and thereafter as follows:
(In Thousands) - ----------------------------------------------- 2005............................. $ 375 2006............................. 412 2007............................. 451 2008............................. 496 2009............................. 545 Thereafter....................... 227,280 ------------ Total indebtedness............. $ 229,559 ============
68 Denbury Resources Inc. Notes to Consolidated Financial Statements NOTE 7. INCOME TAXES Our income tax provision (benefit) is as follows:
(In Thousands) Year Ended December 31, - ------------------------------------------------------------------------------------------ 2004 2003 2002 ------------ ------------ ------------ Current income tax expense (benefit): Federal....................................... $ 22,166 $ (91) $ (419) State......................................... 763 - 13 ------------ ------------ ------------ Total current income tax expense (benefit).... 22,929 (91) (406) ------------ ------------ ------------ Deferred income tax expense: Federal....................................... 12,352 23,864 21,822 State......................................... 4,111 2,439 2,104 ------------ ------------ ------------ Total deferred income tax expense........... 16,463 26,303 23,926 ------------ ------------ ------------ Total income tax expense.................. $ 39,392 $ 26,212 $ 23,520 ============ ============ ============
In conjunction with the sale of Denbury Offshore, Inc. in 2004, we utilized all of our federal tax net operating loss carryforwards and paid alternative minimum taxes of approximately $21 million. 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, 2004, we have approximately $132.3 million in state net operating loss carryforwards that begin to expire in 2013. 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 are approximately $27.8 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, 2004 and 2003 balance sheet dates. We believe that we will be able to utilize all of our deferred tax assets at December 31, 2004, and therefore have provided no valuation allowance against our deferred tax assets. At December 31, 2004 and 2003, our deferred tax assets and liabilities were as follows:
(In Thousands) December 31, - ---------------------------------------------------------------------------- 2004 2003 -------------------------- Deferred tax assets: Loss carryforwards - federal................ $ - $ 33,234 Loss carryforwards - state................... 5,290 2,764 Tax credit carryover......................... 14,186 978 Enhanced oil recovery credit carryforwards... 27,828 16,578 Derivative hedging contracts................. 2,920 16,617 Other........................................ 318 90 ------------ ------------ Total deferred tax assets.................. 50,542 70,261 ------------ ------------ Deferred tax liabilities: Property and equipment....................... (120,038) (112,200) Asset retirement obligations................. (2,440) (1,600) ------------ ------------ Total deferred tax liabilities............ (122,478) (113,800) ------------ ------------ Total net deferred tax liability........ $ (71,936) $ (43,539) ============ ============
69 Denbury Resources Inc. Notes to Consolidated Financial Statements Our income tax provision varies from the amount that would result from applying the federal statutory income tax rate to income before income taxes as follows:
(In Thousands) Year Ended December 31, - -------------------------------------------------------------------------------------- 2004 2003 2002 ------------ ------------ ------------ Income tax provision calculated using the federal statutory income tax rate......... $ 42,644 $ 28,054 $ 24,587 State income taxes.......................... 4,874 2,398 2,121 Enhanced oil recovery credits............... (7,986) (4,687) (3,394) Other....................................... (140) 447 206 ------------ ------------ ------------ Total income tax expense.................. $ 39,392 $ 26,212 $ 23,520 ============ ============ ============
NOTE 8. 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 Repurchase Plan Since August 2003, Denbury has had an active stock repurchase plan ("Plan") to purchase shares of our common stock on the NYSE in order for such repurchased shares to be reissued to our employees who participate in Denbury's Employee Stock Purchase Plan (see Employee Stock Purchase Plan below). The Plan provides for purchases through an independent broker of 50,000 shares of Denbury's common stock per fiscal quarter over a period of approximately twelve months, or a total of 200,000 shares per year. Purchases are to be made at prices and times determined at the discretion of the independent broker, provided however that no purchases may be made during the last ten business days of a fiscal quarter. During 2003, we purchased 100,000 shares at an average cost of $12.77 per share and reissued 91,838 of those shares under Denbury's Employee Stock Purchase Plan. In 2004, we repurchased into treasury 200,000 shares at an average cost of $19.89 per share and reissued 115,090 treasury shares under the Employee Stock Purchase Plan. Our current repurchase program extends through June 2005. Stock Option Plans Denbury has two stock option plans in effect at December 31, 2004. The first plan has been in existence since 1995 (the "1995 Plan") and will expire in August 2005. The second plan, the 2004 Omnibus Stock and Incentive Plan (the "2004 Plan"), has a ten year term and was approved by the shareholders in May 2004. At December 31, 2004, we had a total of 8,195,587 shares of common stock authorized for issuance pursuant to the 1995 Plan, of which 710,291 shares were available for issuance, and 1,125,000 shares authorized for issuance pursuant to the 2004 Plan, of which all 1,125,000 were available for issuance. In January 2005, we issued options under the 1995 Plan that utilized substantially all of the remaining shares under the 1995 Plan and that same month began issuing options under the 2004 Plan. We do not anticipate issuing any further options pursuant to the 1995 Plan and all future grants will be made pursuant to the 2004 Plan. Under the terms of these plans, incentive and non-qualified options may be issued to officers, employees, directors 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 in the 1995 Plan as the average closing price of our common stock for the ten trading days prior to issuance, or in the case of the 2004 Plan, the closing price on the date of grant. These plans are administered by the Compensation Committee of Denbury's Board of Directors. 70 Denbury Resources Inc. Notes to Consolidated Financial Statements The following is a summary of our stock option activity:
Year Ended December 31, -------------------------------------------------------------------------------------------- 2004 2003 2002 ------------------------------ ------------------------------ ------------------------------ Weighted Weighted Weighted Number Average Number Average Number Average of Options Price of Options Price of Options Price --------------- -------------- --------------- -------------- --------------- -------------- Outstanding at beginning of year... 5,326,216 $ 9.20 4,996,365 $ 8.46 4,615,223 $ 8.40 Granted............................ 1,009,810 14.35 957,608 11.33 921,341 7.50 Exercised.......................... (1,264,284) 8.49 (550,090) 5.77 (370,120) 4.51 Forfeited.......................... (631,585) 9.77 (77,667) 12.25 (170,079) 10.30 --------------- --------------- --------------- Outstanding at end of year......... 4,440,157 10.49 5,326,216 9.20 4,996,365 8.46 =============== =============== =============== Exercisable at end of year......... 1,544,412 $ 9.61 2,263,264 $ 10.11 2,267,230 $ 10.26 =============== ============== =============== ============== =============== ==============
The following is a summary of stock options outstanding at December 31, 2004:
Options Outstanding Options Exercisable ------------------------------------------------------ -------------------------------- Weighted Number Average Weighted Number Weighted of Options Remaining Average of Options Average Outstanding Contractual Exercise Exercisable Exercise at 12/31/04 Life Price at 12/31/04 Price ------------------- ------------------- -------------- ----------------- -------------- Range of Exercise Prices - ----------------------------------- $3.77 - 5.50....................... 689,338 4.4 years $ 4.14 689,338 $ 4.14 $5.51 - 8.00....................... 728,514 6.6 years 7.10 81,842 7.13 $8.01 - 11.50...................... 1,459,336 7.1 years 10.37 134,839 9.69 $11.51 - 14.50..................... 1,159,516 7.1 years 13.56 332,448 13.37 $14.51 - 22.50..................... 361,443 4.0 years 18.33 305,945 18.48 $22.51 - 29.50..................... 42,010 9.8 years 25.05 - - ------------------- ----------------- 4,440,157 6.4 years 10.49 1,544,412 9.61 =================== =================
Restricted Stock During August through December 2004, the Board of Directors, based on a recommendation by the Board's Compensation Committee, awarded the officers of Denbury a total of 1,100,000 shares of restricted stock and the independent directors of Denbury a total of 50,000 shares of restricted stock, all granted under Denbury's 2004 Omnibus Stock and Incentive Plan that was approved by Denbury's shareholders in May 2004. The holders of these shares have all of the rights and privileges of owning the shares (including voting rights) except that the holders are not entitled to delivery of the certificates until certain requirements are met. With respect to the 1,100,000 shares of restricted stock granted to officers of Denbury, the vesting restrictions on those shares are as follows: i) 65% of the awards vest 20% per year over five years and, ii) 35% of the awards vest upon retirement, as defined in the 2004 Plan. With respect to the 65% of the awards that vest over five years, on each annual vesting date, 66-2/3% of the vested shares may be delivered to the holder with the remaining 33-1/3% retained and held in escrow until the holder's separation from the Company. With respect to the 50,000 restricted shares issued to Denbury's independent board members, the shares vest 20% per year over five years. For these shares, on each annual vesting date, 40% of such vested shares may be delivered to the holder with the remaining 60% retained and held in escrow until 71 Denbury Resources Inc. Notes to Consolidated Financial Statements the holder's separation from the Company. All restricted shares vest upon death, disability or a change in control. Upon issuance of the 1,150,000 shares of restricted stock pursuant to the 2004 Omnibus Stock and Incentive Plan, we recorded deferred compensation expense of $23.3 million, the market value of the shares on the grant dates, as a reduction to shareholders' equity. This expense will be amortized over the applicable five year or retirement date vesting periods. The compensation expense recorded with respect to the restricted shares for the year ending December 31, 2004, was $1.6 million. Employee 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, 2004, there are 291,376 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 or treasury stock purchased by the Company in the open market for that purpose, in either case, based on the market value of Denbury's common stock at the end of each quarter. We recognize compensation expense for the 75% company match portion, which totaled $1,011,000, $997,000 and $822,000 for the years ended December 31, 2004, 2003 and 2002, respectively. This plan is administered by the Compensation Committee of Denbury's Board of Directors. This plan currently terminates in August 2005, although we plan to request that shareholders extend this plan for another five years at the 2005 Annual Meeting of Shareholders. 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 2004, 2003 and 2002, Denbury's matching contributions were approximately $1.0 million, $1.1 million, and $884,000, respectively, to the 401(k) Plan. NOTE 9. 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. Historically, we have generally attempted 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 a majority of our budgeted exploration and development expenditures without incurring significant debt, although our hedging percentage may vary relative to our debt levels. When we make a significant acquisition, we generally 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 predominantly with collars, although for the 2002 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. 72 Denbury Resources Inc. Notes to Consolidated Financial Statements The following is a summary of the net gain (loss) on our commodity contracts that qualify for hedge accounting which are included in "(Gain) loss on effective hedge contracts" in our Consolidated Statements of Operations:
(In Thousands) Year Ended December 31, - ---------------------------------------------------------------------------------------------------- 2004 2003 2002 ------------ ------------ ------------ Settlement of hedge contracts - Oil...................... $ (50,072) $ (20,337) $ (598) Settlement of hedge contracts - Gas...................... (20,397) (41,873) 1,530 ------------ ------------ ------------ Gain (loss) on effective hedge contracts............... $ (70,469) $ (62,210) $ 932 ============ ============ ============
The following is a summary of "(Gain) loss on ineffective hedge contracts," included in our Consolidated Statements of Operations:
(In Thousands) Year Ended December 31 - ---------------------------------------------------------------------------------------------------------------- 2004 2003 2002 ------------- ------------ ------------- Settlement of contract not qualifying for hedge accounting.......... $ 14,088 $ - $ - Hedge ineffectiveness on contracts qualifying for hedge accounting........................................................ 2,687 282 600 Reclassification of accumulated other comprehensive income balance and adjustments to fair value associated with termination of contracts designated to offshore production.................... (955) - - Adjustments to fair value and amortization of ineffective hedge no longer qualifying for hedge accounting ........................... 2,086 - - Adjustment to fair value associated with contracts transferred in sale of offshore properties....................................... (2,548) - Amortization of contract premiums................................... - 1,192 9,664 Amortization of terminated Enron-related hedges over the original contract periods.................................................. - (5,052) (13,357) ------------- ------------ ------------- (Gain) loss on ineffective contracts.............................. $ 15,358 $ (3,578) $ (3,093) ============= ============ =============
Loss on Enron Hedges In conjunction with the acquisition of Matrix Oil and Gas, Inc. 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 after December 2001, we would not have collected anything on the price floors relating to 2003, even if Enron had not filed bankruptcy, as the natural gas NYMEX prices during 2003 were above $3.75 (the floor price for 2003). We calculate 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. 73 Denbury Resources Inc. Notes to Consolidated Financial Statements When Enron filed for bankruptcy during the fourth quarter of 2001, these 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 was that any future changes in the current market value of these assets had to be reflected in the income statement and any remaining accumulated other comprehensive income at the time of the accounting change had to 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 recognized pre-tax income during 2003 of approximately $5.1 million. The three-year total pre-tax net loss on the Enron hedges was approximately $5.9 million, which approximates the difference between the amount collected and paid for the Enron portion of the associated price floors. Hedging Contracts at December 31, 2004
Crude Oil Contracts: NYMEX Contract Prices Per Bbl ----------------------------------------------------- Estimated Collar Prices Fair Value at -------------------------- December 31, 2004 Type of Contract and Period Bbls/d Floor Price Floor Ceiling (In Thousands) - -------------------------------- ------------- ------------ ------------ ------------ --------------------- Floor Contracts Jan. 2005 - Dec. 2005........... 7,500 $ 27.50 - - $ 949 Natural Gas Contracts: NYMEX Contract Prices Per MMBtu ----------------------------------------------------- Estimated Collar Prices Fair Value at -------------------------- December 31, 2004 Type of Contract and Period MMBtu/d Floor Price Floor Ceiling (In Thousands) - -------------------------------- ------------- ------------ ------------ ------------ --------------------- Collar Contracts Jan. 2005 - Dec. 2005........... 15,000 - $ 3.00 $ 5.50 $ (5,815)
At December 31, 2004, our derivative contracts were recorded at their fair value, which was a net liability of $4.9 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 $4.8 million at December 31, 2004, represents the deficit in the fair market value of our derivative contracts as compared to the cost of our hedges, net of income taxes. The $4.8 million in accumulated other comprehensive loss as of December 31, 2004, will expire within the next 12 months. We have decided to de-designate from hedge accounting treatment our existing derivative hedging instruments, effective January 1, 2005. As such, we will account for our derivative instruments in future periods as speculative contracts and future changes in the fair value of these instruments will be recognized in the income statement in the period of change. While this may result in more volatility in our income statement in future periods, we believe that the benefits associated with applying hedge accounting do not outweigh the cost, time and effort required to apply hedge accounting. NOTE 10. COMMITMENTS AND CONTINGENCIES We have operating leases for the rental of office space, equipment, and vehicles that totaled $21.6 million, $16.6 million, and $1.7 million as of December 31, 2004, 2003,and 2002, respectively. In addition, in 2004 we entered into two lease financing arrangements totaling $6.9 million for equipment at our McComb Field and Jackson Dome CO2 Field. These lease terms are for seven years with monthly payments of approximately $91,000 per month. In August 2003, we entered into a $6.0 million lease financing arrangement for certain equipment at our CO2 processing facility at Mallalieu Field. This lease term is for seven years with monthly payments of approximately $81,000 per month. 74 Denbury Resources Inc. Notes to Consolidated Financial Statements In 2004, we entered into two agreements with Genesis to transport crude oil and CO2. These agreements are accounted for as capital leases and are discussed in detail in Note 3. At December 31, 2004, long-term commitments for these items require the following future minimum rental payments:
Capital Operating (In Thousands) Leases Leases - --------------------------------------------------------------- ------------ 2005........................................ $ 806 $ 3,977 2006........................................ 806 3,967 2007........................................ 806 3,954 2008........................................ 806 3,807 2009........................................ 806 3,064 Thereafter.................................. 2,777 2,813 ------------ ------------ Total minimum lease payments.............. 6,807 $ 21,582 ============ Less: Amount representing interest......... (2,248) ------------ Present value of minimum lease payments... $ 4,559 ============
Long-term contracts require us to deliver CO2 to our industrial CO2 customers at various contracted prices, plus we have a CO2 delivery obligation to Genesis related to two CO2 volumetric production payments (see "Genesis Transactions" above). Based upon the maximum amounts deliverable as stated in the contracts and the volumetric production payment, we estimate that we may be obligated to deliver up to 398 Bcf of CO2 to these customers over the next 17 years; however, since the group as a whole has historically purchased less CO2 than the maximum allowed in their contracts, based on the current level of deliveries, we project that our commitment would likely be reduced to approximately 332 Bcf. The maximum volume required in any given year is approximately 101 MMcf/d, although based on our current level of deliveries, this would likely be reduced to approximately 78 MMcf/d. Given the size of our proven CO2 reserves at December 31, 2004 (approximately 2.7 Tcf before deducting approximately 178.7 Bcf for the VPPs), our current production capabilities and our projected levels of CO2 usage for our own tertiary flooding program, we believe that we can meet these delivery obligations. Denbury is subject to various possible contingencies that 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. Litigation We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses, including those noted below. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position or overall trends in results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that we may have a range of legal exposure that would require accrual. The estimate of the potential impact from the following legal proceedings on our financial position or overall results of operations could change in the future. Along with two other companies, we have been named in a lawsuit styled J. Paulin Duhe, Inc. vs. Texaco, Inc., et al, Cause No. 101,227, filed in late 2003 in the 16th Judicial District Court, Division "E", Terrebonne Parish, Louisiana, seeking restoration to its original condition of property on which oil has been produced over the past 70 years. The contract and tort claims by the plaintiffs 75 Denbury Resources Inc. Notes to Consolidated Financial Statements allege surface and groundwater damage of 26 acres that are part of our Iberia Field in Iberia Parish, Louisiana. Recently, plaintiff's experts have initially alleged that clean-up of alleged contamination of the property would cost $79.0 million, although settlement offers by plaintiffs have already been made for much smaller sums. The property was originally leased to Texaco, Inc. for mineral development in 1934 and Denbury acquired its interest in the property in August 2000 from Manti Operating Company. Discovery is currently underway, and the April 2005 trial setting has been continued to an unspecified date in the future. We believe that we are indemnified by the prior owner, which we expect to cover our exposure to most damages, if any, found to have occurred prior to the time that we purchased the property. We believe that the allegations of this lawsuit are subject to a number of defenses, are without merit and we and the other defendants plan to vigorously defend this lawsuit, and if necessary, we will seek indemnification from the prior owner. On December 29, 2003, an action styled Harry Bourg Corporation vs. Exxon Mobil Corporation, et al, Cause No. 140749, was filed in the 32nd Judicial District Court, Terrebonne Parish, Louisiana against Denbury and eleven other oil companies and their predecessors alleging damage as the result of mineral exploration activities conducted by these oil and gas operators/companies over the last 60 years. Plaintiff has asked for restoration of the 10,000 acre property and/or damages in claims made under tort law and various oil and gas contracts. The Bourg Corporation recently produced its first preliminary expert reports that allege damages of approximately $100.0 million against Denbury. Discovery is continuing in this case, with trial currently set for January 2006. We believe the allegations of this lawsuit are without merit and plan to vigorously defend this lawsuit along with the other defendants. No provision has been accrued in our financial statements. NOTE 11. 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, 2004, two purchasers each accounted for 10% or more of our oil and natural gas revenues: Hunt Refining (21%) and Genesis (14%). For the year ended December 31, 2003, we had two significant purchasers that each accounted for 10% or more of our oil and natural gas revenues: Hunt Refining (15%) and Genesis (12%). For the year ended December 31, 2002, two purchasers each accounted for 10% or more of our natural gas revenues: Hunt Refining (14%) and Genesis (11%). Accounts Payable and Accrued Liabilities
(In Thousands) Year Ended December 31, - -------------------------------------------------------------------------------------- 2004 2003 ----------------- ----------------- Accounts payable................................ $ 26,262 $ 33,321 Accrued compensation............................ 5,613 2,806 Accrued exploration and development costs....... 5,439 7,546 Accrued interest ............................... 4,219 4,272 Asset retirement obligations - current.......... 2,596 2,101 Deferred revenues - Genesis..................... 2,431 2,105 Advances payable................................ 76 4,430 Other........................................... 5,224 5,768 ----------------- ----------------- Total ........................................ $ 51,860 $ 62,349 ================= =================
76 Denbury Resources Inc. Notes to Consolidated Financial Statements Supplemental Cash Flow Information
(In Thousands) Year Ended December 31, - -------------------------------------------------------------------------- 2004 2003 2002 ------------ ------------ ------------- Interest paid................... $ 18,099 $ 23,525 $ 24,636 Income taxes paid (refunded).... 20,726 184 (1,304)
In 2004, we recorded a non-cash increase to property and debt in the amount of $4.6 million in connection with two capital leases. In August through December 2004, the company issued 1,150,000 shares of restricted stock with a market value of $23.3 million on the date of grant. See Note 8 Stockholders' Equity-Restricted Stock. Fair Value of Financial Instruments
(In Thousands) December 31, - ---------------------------------------------------------------------------------------------------------------------- 2004 2003 ------------------------------ ------------------------------ Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value -------------- --------------- ------------- --------------- Senior bank debt.................................... $ - $ - $ 75,000 $ 75,000 7.5% Senior Subordinated Notes due 2013............. 223,397 243,000 223,203 232,875
As of December 31, 2003, 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. The fair values of our short-term investments are discussed in Note 1. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities. NOTE 12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION On December 29, 2003, we amended the indenture for our 7.5% Senior Subordinated Notes due 2013 to reflect our new holding company organizational structure (see Note 1 and Note 6). As part of this restructuring our indenture was amended so that both Denbury Resources Inc. and Denbury Onshore, LLC became co-obligors of our subordinated debt. Prior to this restructure, Denbury Resources Inc. was the sole obligor. Our subordinated debt is fully and unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries. Genesis Energy, Inc., the subsidiary that holds the Company's investment in Genesis Energy, L.P., is not a guarantor of our subordinated debt. The results of our equity interest in Genesis is reflected through the equity method by one of our significant subsidiaries, Denbury Gathering & Marketing. The following is condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and significant subsidiaries: 77 Denbury Resources Inc. Notes to Consolidated Financial Statements Condensed Consolidating Balance Sheets
(In Thousands) December 31, 2004 - ----------------------------------------------------------------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and (Issuer and Guarantor Resources Inc. Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated ---------------- --------------- ------------- ---------------- ---------------- Assets Current assets.............................. $ 1 $ 171,997 $ 204,709 $ (203,861) $ 172,846 Property and equipment...................... - 796,578 784 - 797,362 Investment in subsidiaries (equity method).. 541,671 - 333,907 (868,787) 6,791 Other assets................................ - 15,707 2,271 (2,271) 15,707 ---------------- --------------- ------------- ---------------- ---------------- Total assets.............................. $ 541,672 $ 984,282 $ 541,671 $ (1,074,919) $ 992,706 ================ =============== ============= ================ ================ Liabilities and Stockholders' Equity Current liabilities......................... $ - $ 286,767 $ - $ (203,861) $ 82,906 Long-term liabilities....................... - 370,399 - (2,271) 368,128 Stockholders' equity........................ 541,672 327,116 541,671 (868,787) 541,672 ---------------- --------------- ------------- ---------------- ---------------- Total liabilties and stockholders' equity $ 541,672 $ 984,282 $ 541,671 $ (1,074,919) $ 992,706 ================ =============== ============= ================ ================ (In Thousands) December 31, 2003 - ----------------------------------------------------------------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and (Issuer and Guarantor Resources Inc. Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated ---------------- --------------- ------------- ---------------- ---------------- Assets Current assets.............................. $ 1 $ 85,109 $ 23,045 $ - $ 108,155 Property and equipment ..................... - 560,038 292,473 - 852,511 Investment in subsidiaries (equity method).. 421,201 - 210,803 (624,554) 7,450 Other assets................................ - 11,186 3,319 - 14,505 ---------------- --------------- ------------- ---------------- ---------------- Total assets.............................. $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621 ================ =============== ============= ================ ================ Liabilities and Stockholders' Equity Current liabilities......................... $ - $ 119,364 $ 7,210 $ - $ 126,574 Long-term liabilities....................... - 333,616 101,229 - 434,845 Stockholders' equity........................ 421,202 203,353 421,201 (624,554) 421,202 ---------------- ------------------------------ ---------------- ---------------- Total liabilities and stockholders' equity $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621 ================ =============== ============= ================ ================
78 Denbury Resources Inc. Notes to Consolidated Financial Statements Condensed Consolidating Statements of Operations
(In Thousands) Year Ended December 31, 2004 - ---------------------------------------------------------------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and (Issuer and Guarantor Resources Inc. Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated --------------- --------------- -------------- ---------------- ---------------- Revenues..................................... $ - $ 320,328 $ 62,644 $ - $ 382,972 Expenses..................................... 171 222,988 37,837 - 260,996 --------------- --------------- -------------- ---------------- ---------------- Income before the following: (171) 97,340 24,807 - 121,976 Equity in net earnings of subsidiaries..... 82,554 - 67,122 (149,812) (136) --------------- --------------- -------------- ---------------- ---------------- Income before income taxes .................. 82,383 97,340 91,929 (149,812) 121,840 --------------- --------------- -------------- ---------------- ---------------- Income tax provision......................... (65) 30,082 9,375 - 39,392 --------------- --------------- -------------- ---------------- ---------------- Net income (loss).......................... $ 82,448 $ 67,258 $ 82,554 $ (149,812) $ 82,448 =============== =============== ============== ================ ================ (In Thousands) Year Ended December 31, 2003 - ---------------------------------------------------------------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and (Issuer and Guarantor Resources Inc. Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated --------------- --------------- -------------- ---------------- ---------------- Revenues..................................... $ - $ 238,072 $ 94,942 $ - $ 333,014 Expenses..................................... - 196,392 56,725 - 253,117 --------------- --------------- -------------- ---------------- ---------------- Income before the following: - 41,680 38,217 - 79,897 Equity in net earnings of subsidiaries..... 56,553 - 40,667 (96,964) 256 --------------- --------------- -------------- ---------------- ---------------- Income before income taxes and cumulative effect of change in accounting principle... 56,553 41,680 78,884 (96,964) 80,153 Income tax provision......................... - 5,250 20,962 - 26,212 --------------- --------------- -------------- ---------------- ---------------- Net income before cumulative effect of change in accounting principle.................... 56,553 36,430 57,922 (96,964) 53,941 --------------- --------------- -------------- ---------------- ---------------- Cumulative effect of a change in accounting principle, net of income tax............... - 3,981 (1,369) - 2,612 --------------- --------------- -------------- ---------------- ---------------- Net income (loss).......................... $ 56,553 $ 40,411 $ 56,553 $ (96,964) $ 56,553 =============== =============== ============== ================ ================ (In Thousands) Year Ended December 31, 2002 - ----------------------------------------------------------------------------------------------------------------- Denbury Resources Inc. Denbury (Parent and Guarantor Resources Inc. 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 =============== =============== ============== ================
79 Denbury Resources Inc. Notes to Consolidated Financial Statements Condensed Consolidating Statements of Cash Flow
(In Thousands) Year Ended December 31, 2004 - --------------------------------------------------------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and (Issuer and Guarantor Resources Inc. Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated ---------------- --------------- -------------- ---------------- ---------------- Cash flow from operations.............. $ (9,192) $ 331,123 $ (153,279) $ - $ 168,652 Cash flow from investing activities.... - (246,973) 153,423 - (93,550) Cash flow from financing activities.... 9,192 (75,443) - - (66,251) ---------------- --------------- -------------- ---------------- ---------------- Net increase (decrease) in cash flow... - 8,707 144 - 8,851 Cash, beginning of period.............. 1 24,174 13 - 24,188 ---------------- --------------- -------------- ---------------- ---------------- Cash, end of period.................... $ 1 $ 32,881 $ 157 $ - $ 33,039 ================ =============== ============== ================ ================ (In Thousands) Year Ended December 31, 2003 - --------------------------------------------------------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and (Issuer and Guarantor Resources Inc. Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated ---------------- --------------- -------------- ---------------- ---------------- Cash flow from operations.............. $ $ 146,639 $ 50,976 $ - $ 197,615 Cash flow from investing activities.... - (81,256) (54,622) - (135,878) Cash flow from financing activities.... 1 (61,490) - - (61,489) ---------------- --------------- -------------- ---------------- ---------------- Net increase (decrease) in cash flow... 1 3,893 (3,646) - 248 Cash, beginning of period.............. - 20,281 3,659 - 23,940 ---------------- --------------- -------------- ---------------- ---------------- Cash, end of period.................... $ 1 $ 24,174 $ 13 $ - $ 24,188 ================ =============== ============== ================ ================ (In Thousands) Year Ended December 31, 2002 - ---------------------------------------------------------------------------------------------------------- Denbury Resources Inc. Denbury (Parent and Guarantor Resources Inc. 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 ================ =============== ============== ================
80 Denbury Resources Inc. Notes to Consolidated Financial Statements NOTE 13. 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. Costs incurred in oil and natural gas activities were as follows:
(In Thousands) Year Ended December 31, - -------------------------------------------------------------------------- 2004 2003 2002 ------------ ------------ ------------- Property acquisitions: Proved ....................... $ 22,271 $ 22,307 $ 56,364 Unevaluated................... 3,459 3,955 4,342 Exploration..................... 23,987 34,050 29,985 Development..................... 128,351 98,132 64,946 Asset retirement obligations.... 3,174 3,405 - ------------ ------------ ------------- Total costs incurred (1)...... $ 181,242 $ 161,849 $ 155,637 ============ ============ ============= (1) Capitalized general and administrative costs that directly relate to exploration and development activities were $5.1 million, $5.5 million, $5.3 million for the years ended December 31, 2004, 2003 and 2002, 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:
(In Thousands, Except per BOE data) Year Ended December 31, - ---------------------------------------------------------------------------------------------------------------- 2004 2003 2002 ------------- ------------ ------------- Oil, natural gas and related product sales......................... $ 444,777 $ 385,463 $ 274,894 Gain (loss) on effective hedge contracts........................... (70,469) (62,210) 932 ------------- ------------ ------------- Total revenues................................................... 374,308 323,253 275,826 ------------- ------------ ------------- Lease operating costs.............................................. 87,107 89,439 71,188 Production taxes and marketing expenses............................ 18,737 14,819 11,902 Depletion, depreciation and accretion.............................. 90,913 90,694 90,679 (Gain) loss on ineffective hedge contracts......................... 15,358 (3,578) (3,093) ------------- ------------ ------------- Net operating income............................................. 162,193 131,879 105,150 Income tax provision............................................... 52,437 45,427 36,563 ------------- ------------ ------------- Results of operations from oil and natural gas producing activities $ 109,756 $ 86,452 $ 68,587 ============= ============ ============= Depletion, depreciation and accretion per BOE...................... $ 7.54 $ 7.16 $ 6.98 ============= ============ =============
81 Denbury Resources Inc. Notes to Consolidated Financial Statements 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 until we have committed to perform the required development operations, the majority of which we generally expect to commence within the next year. We also have a corporate policy whereby proved undeveloped reserves must be economic at prices significantly lower than the year-end prices used in our reserve report, at prices closer to historical averages. 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. Estimated Quantities of Reserves
Year Ended December 31, -------------------------------------------------------------------------------- 2004 2003 2002 -------------------------- -------------------------- -------------------------- Oil Gas Oil Gas Oil Gas (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) Balance at beginning of year............ 91,266 221,887 97,203 200,947 76,490 198,277 Revisions of previous estimates......... (3,271) 2,898 2,958 (25,451) (408) (22,975) Revisions due to price changes.......... 492 25 50 (152) 3,020 2,660 Extensions and discoveries.............. 1,575 61,158 1,059 68,408 2,326 51,819 Improved recovery (1)................... 18,863 - 4,009 - - - Production.............................. (7,044) (30,094) (6,896) (34,623) (6,874) (36,662) Acquisition of minerals in place........ 429 5,304 838 14,541 23,383 9,360 Sales of minerals in place.............. (1,023) (92,694) (7,955) (1,783) (734) (1,532) ------------ ------------ ------------- ------------ ------------- ------------ Balance at end of year.................. 101,287 168,484 91,266 221,887 97,203 200,947 ============ ============ ============= ============ ============= ============ Proved Developed Reserves: Balance at beginning of year............ 53,804 144,750 62,398 142,812 54,722 169,897 Balance at end of year.................. 55,998 94,573 53,804 144,750 62,398 142,812 (1) Improved recovery additions result from the application of secondary recovery methods such as water-flooding 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 82 Denbury Resources Inc. Notes to Consolidated Financial Statements 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 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, ---------------------------------------- 2004 2003 2002 ------------- ------------ ------------- Oil (NYMEX)..................... $ 43.45 $ 32.52 $ 31.20 Natural Gas (NYMEX Henry Hub)... 6.15 6.19 4.79
Future cash inflows were reduced by estimated future production, development and abandonment 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.
(In Thousands) December 31, - ---------------------------------------------------------------------------------------------------------------- 2004 2003 2002 --------------- -------------- --------------- Future cash inflows........................................ $ 4,742,276 $ 4,059,424 $ 3,787,077 Future production costs.................................... (1,509,280) (1,120,741) (1,044,193) Future development costs................................... (340,879) (300,981) (268,269) --------------- -------------- --------------- Future net cash flows before taxes....................... 2,892,117 2,637,702 2,474,615 Future income taxes........................................ (906,221) (748,273) (689,617) --------------- -------------- --------------- Future net cash flows.................................... 1,985,896 1,889,429 1,784,998 10% annual discount for estimated timing of cash flows..... (856,700) (765,302) (756,022) --------------- -------------- --------------- Standardized measure of discounted future net cash flows $ 1,129,196 $ 1,124,127 $ 1,028,976 =============== ============== ===============
83 Denbury Resources Inc. Notes to Consolidated Financial Statements 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:
(In Thousands) Year Ended December 31, - ------------------------------------------------------------------------------------------------------------------ 2004 2003 2002 -------------- -------------- -------------- Beginning of year................................................. $ 1,124,127 $ 1,028,976 $ 505,795 Sales of oil and natural gas produced, net of production costs.... (339,250) (281,205) (191,803) Net changes in sales prices....................................... 352,830 141,932 694,646 Extensions and discoveries, less applicable future development and production costs............................................ 151,014 235,228 151,926 Improved recovery (1)............................................. 190,033 40,663 - Previously estimated development costs incurred................... 55,091 52,874 34,931 Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production............. (197,959) (157,989) (50,855) Accretion of discount............................................. 156,637 142,622 57,433 Acquisition of minerals in place.................................. 9,003 44,856 160,899 Sales of minerals in place........................................ (300,481) (78,830) (5,285) Net change in income taxes........................................ (71,849) (45,000) (328,711) -------------- -------------- -------------- End of year....................................................... $ 1,129,196 $ 1,124,127 $ 1,028,976 ============== ============== ============== (1) Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding.
CO2 Reserves Based on engineering reports prepared by DeGolyer and MacNaughton, our CO2 reserves, on a 100% working interest basis, were estimated at approximately 2.7 Tcf at December 31, 2004 (includes 178.7 Bcf of reserves dedicated to two volumetric production payments with Genesis), 1.6 Tcf at December 31, 2003 (includes 162.6 Bcf of reserves dedicated to a volumetric production payment), and 1.6 Tcf at December 31, 2002. We make reference to the gross amount of proved reserves as that is the amount that is available both for Denbury's tertiary recovery programs and for industrial users who are customers of Denbury and others, as we are responsible for distributing the entire CO2 production stream for both of these purposes. 84 Denbury Resources Inc. Notes to Consolidated Financial Statements NOTE 14. UNAUDITED QUARTERLY INFORMATION
- ----------------------------------------------------------------------------------------------------------------- In Thousands, Except Per Share Amounts March 31 June 30 September 30 December 31 - ----------------------------------------------------------------------------------------------------------------- 2004 - ---- Revenues (1)................................... $ 97,748 $ 106,213 $ 88,029 $ 90,982 Expenses (1)................................... 64,710 77,277 61,886 57,123 Net income (2)................................. 22,304 19,389 18,274 22,481 Net income per share: Basic ....................................... 0.41 0.35 0.33 0.41 Diluted...................................... 0.40 0.34 0.32 0.39 Cash flow from operations...................... 52,995 53,210 44,766 17,681 Cash flow provided by (used for) investing activities (2) (3)........................... (68,111) (51,351) 69,046 (43,134) Cash flow provided by (used for) financing activities (2)............................... 8,136 8,873 (84,035) 775 2003 - ---- Revenues....................................... $ 86,432 $ 84,188 $ 79,415 $ 82,979 Expenses (4)................................... 58,910 76,660 56,691 60,856 Income before accounting change (5)............ 18,453 5,129 15,149 15,210 Net income (5)................................. 21,065 5,129 15,149 15,210 Income per share before accounting change: Basic ....................................... 0.34 0.10 0.28 0.28 Diluted...................................... 0.33 0.09 0.27 0.27 Net income per share: Basic ....................................... 0.39 0.10 0.28 0.28 Diluted...................................... 0.38 0.09 0.27 0.27 Cash flow from operations...................... 35,509 60,542 49,789 51,775 Cash flow used for investing activities........ (18,139) (54,742) (35,495) (27,502) Cash flow provided by (used for) financing activities................................... 119,860 (147,622) (5,534) (28,193) (1) The loss on settlement of ineffective hedges has been reclassified from Revenues to Expenses in this presentation. For the second quarter of 2004, $3.5 million loss was reclassified from Revenues to Expenses. For the third quarter of 2004, $4.8 million loss was reclassified from Revenues to Expenses. (2) In July 2004, we sold Denbury Offshore, Inc. a subsidiary that held our offshore assets. We used $85 million of the proceeds to retire debt (see Note 2). (3) Auction rate securities in the amount of $35.4 million at September 30, 2004, have been reclassified from cash and equivalent to short-term investments to conform to the December 31, 2004 presentation. Accordingly, cash flow provided by investing activities for the quarter ended September 30, 2004 has been adjusted to reflect this presentation. (4) In the second quarter of 2003, we incurred a $17.6 million ($11.5 million net of income tax) loss on early retirement of debt (see Note 6). (5) In the first quarter of 2003, we recognized a gain of $2.6 million for the cumulative effect adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" (see Note 4).
85 Denbury Resources Inc. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND - ------------------------------------------------------------------------------- FINANCIAL DISCLOSURE - -------------------- On May 12, 2004, the Audit Committee of Denbury approved the appointment of PricewaterhouseCoopers LLP as the Company's independent auditors for the fiscal year ending December 31, 2004, replacing Deloitte & Touche LLP, which had been the Company's independent auditors since 1990. This decision was affirmed by Denbury's Board of Directors. Information regarding this change in independent auditors was included in our report on Form 8-K dated May 17, 2004, and subsequently amended on May 24, 2004. There have been no other changes in accountants nor any disagreements with accountants. ITEM 9A. 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 as of the end of the period covered by this annual report on Form 10-K and have determined that such disclosure controls and procedures are effective in all material respects in providing to them on a timely basis material information required to be disclosed in this annual report. Our assessment of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 herein. There have been no changes in internal controls over financial reporting during the period covered by this annual report on Form 10-K that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. In January 2005, we began processing our transactions on a newly implemented accounting software system. We changed systems in order (i) to integrate and automate more of our functions, which will also allow us to have more information in one integrated database, (ii) to provide operating efficiencies, (iii) to enable us to close our books in a more timely manner without sacrificing quality, (iv) to review and improve our processes and (v) improve the internal control surrounding our computer systems. All of Denbury's 2004 accounting was performed on its prior system and as a result, this change had no impact on Denbury's internal control over financial reporting during 2004. As a result of moving to a new system in January 2005, we anticipate that certain control procedures will need to be changed during 2005 in order to conform to our new system. We plan to evaluate those changes during the first quarter of 2005. While we believe that our new accounting system will ultimately strengthen our internal control system, there are inherent weaknesses in implementing any new system and until we have fully tested all changes to our controls, we may not be able to provide assurance that our disclosure controls are effective in all material respects. ITEM 9B. OTHER INFORMATION - -------------------------- None. 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 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 11, 2005, ("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. 86 Denbury Resources Inc. 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 2004. Code of Ethics We have adopted a Code of Ethics for Senior Financial Officers and Principal Executive Officer. This Code of Ethics, including any amendments or waivers, is posted on our website at www.denbury.com. 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 AND - ------------------------------------------------------------------------------- RELATED STOCKHOLDER MATTERS - --------------------------- Information as to Denbury's common stock that may be issued under our equity compensation plans, which plans have been approved by shareholders, and the number of shares of Denbury's common stock beneficially owned as of March 1, 2005, 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. PRINCIPAL ACCOUNTANT FEES AND SERVICES - ----------------------------------------------- Information required to be presented on principal accountant fees and services will be presented under the caption "Relationship with Independent Accountants" in the Proxy Statement for the Annual Meeting and is incorporated herein by reference. PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES - --------------------------------------------------- Financial Statements and Schedules. Financial statements and schedules filed as a part of this report are presented on page 46. All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to consolidated financial statements. Exhibits. The following exhibits are filed as part of this report.
Exhibit No. Exhibit ----------- ------- 2(a) Agreement and Plan of Merger to Form Holding Company, dated as of December 22, 2003, but effective December 29, 2003 at 9:00 a.m. EST, by and among the Registrant, the Predecessor and Denbury Onshore, LLC (incorporated by reference as Exhibit 2.1 of our Form 8-K filed December 29, 2003).
87 Denbury Resources Inc.
Exhibit No. Exhibit ----------- ------- 2(b) Stock Purchase Agreement made as of July 19, 2004, between Denbury Resources Inc. and Newfield 2(b) Exploration Company (incorporated by reference as exhibit 2.14 of our Form 8-K filed August 4, 2004). 3(a) Restated Certificate of Incorporation of Denbury Resources Inc. filed with the Delaware Secretary of State on December 29, 2003 (incorporated by reference as Exhibit 3.1 of our Form 8-K filed December 29, 2003). 3(b) Bylaws of Denbury Resources Inc., a Delaware corporation, adopted December 29, 2003 (incorporated by reference as Exhibit 3.2 of our Form 8-K filed December 29, 2003). 4(a) Indenture for $225 million of 7.5% Senior Subordinated Notes due 2013 among Denbury Resources Inc., certain of its subsidiaries and JP Morgan Chase Bank as trustee, dated March 25, 2003 (incorporated by reference from Exhibit 4(a) to our Registration Statement No. 333-105233-04 on Form S-4, filed May 14, 2003). 4(b) First Supplemental Indenture for $225 million of 7.5% Senior Subordinated Notes due 2013 dated as of December 29, 2003, among Denbury Resources Inc., certain of its subsidiaries, and the JP Morgan Chase Bank, as trustee (incorporated by reference as Exhibit 4.1 of our Form 8-K filed December 29, 2003). 10(a) Fifth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, Denbury Resources Inc., as Parent Guarantor, Bank One, N.A. as Administrative Agent, and certain other financial institutions, dated September 1, 2004 (incorporated by reference as Exhibit 1.1 of our Form 8-K filed September 3, 2004). 10(b)** Denbury Resources Inc. Amended and Restated Stock Option Plan (incorporated by reference as Exhibit 99 of our Registration Statement No. 333-106253 on Form S-8, filed June 18, 2003). 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, filed February 2, 1996, with amendments incorporated by reference as exhibits of our Registration Statements on Forms S-8, No. 333-70485, filed January 12, 1999, No. 333-39218, filed June 13, 2000 and No. 333-90398, filed 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 our 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 our Registration Statement on Form S-8, No. 333-39172, filed June 13, 2000 and amended March 2, 2001). 10(f)** Denbury Resources Severance Protection Plan, dated December 6, 2001 (incorporated by reference as Exhibit 10(f) of our Form 10-K for the year ended December 31, 2000). 10(g)* ** Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan as amended. 10(h)* ** Description of non-employee director's compensation arrangements. 10(i)* ** Description of cash bonus compensation arrangements for employees and officers. 10(j)* ** Description of stock option grant practices for employees and officers. 10(k)* ** Form of restricted stock award that vests 20% per annum, for grants to officers pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. 10(l)* ** Form of restricted stock award that vests on retirement, for grants to officers pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. 10(m)* ** Form of restricted stock award that vests 20% per annum, for grants to directors pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. 10(n)* ** Form of incentive stock option agreement that vests 25% per annum, for grants to new employees and officers on their hire date pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. 10(o)* ** Form of incentive stock option agreement that cliff vests 100% four years from the date of grant, for grants to employees and officers pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. 10(p)* ** Form of non-qualified stock option agreement that vests 25% per annum, for grants to new employees and officers on their hire date pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. 10(q)* ** Form of non-qualified stock option agreement that vests 100% four years from the date of grant, for grants to employees, officers and directors pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. 10(r)* ** Form of stock appreciation rights agreement that vests 25% per annum, for grants to new employees and officers on their hire date pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. 10(s)* ** Form of stock appreciation rights agreement that vests 100% four years from the date of grant, for grants to employees, officers and directors pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
88 Denbury Resources Inc.
Exhibit No. Exhibit ----------- ------- 16 Letter from Deloitte & Touche LLP to the Securities and Exchange Commission, dated May 24, 2004, regarding change in certifying accountant, pursuant to Item 304(a)(3) of Regulation S-K 21* (filed as exhibit 16.1 of our Form 8-K/A filed May 24, 2004) and incorporated by reference herein. 21* List of Subsidiaries of Denbury Resources Inc. 23(a)* Consent of PricewaterhouseCoopers LLP. 23(b)* Consent of Deloitte & Touche LLP. 23(c)* Consent of DeGolyer and MacNaughton. 31(a)* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31(b)* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32* Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99* The summary of DeGolyer and MacNaughton's Report as of December 31, 2004, on oil and gas reserves (SEC Case) dated March 9, 2005.
* Filed herewith. ** Compensation arrangements. 89 Denbury Resources Inc. 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 11, 2005 /s/ Phil Rykhoek ----------------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer March 11, 2005 /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 11, 2005 /s/ Gareth Roberts ----------------------- Gareth Roberts Director, President and Chief Executive Officer (Principal Executive Officer) March 11, 2005 /s/ Phil Rykhoek ----------------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer (Principal Financial Officer) March 11, 2005 /s/ Mark C. Allen ----------------------- Mark C. Allen Vice President and Chief Accounting Officer (Principal Accounting Officer) March 11, 2004 /s/ Ron Greene ----------------------- Ron Greene Director March 11, 2005 /s/ David I. Heather ----------------------- David I. Heather Director March 11, 2005 /s/ Randy Stein ----------------------- Randy Stein Director 90 March 11, 2005 /s/ Wieland Wettstein ----------------------- Wieland Wettstein Director March 11, 2005 /s/ Greg McMichael ----------------------- Greg McMichael Director March 11, 2005 /s/ Donald Wolf ----------------------- Donald Wolf Director 91 EX-23 2 fy2004-exhibit23c.txt EXHIBIT 23(C), CONSENT OF DEGOLYER & MACNAUGHTON Exhibit 23(c) DeGolyer and MacNaughton 4925 Greenville Avenue, Suite 400 One Energy Square Dallas, Texas 75206 March 14, 2005 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, to references to DeGolyer and MacNaughton, and to the inclusion of information taken from our "Appraisal Report as of December 31, 2004 on Proved Reserves of Certain Properties owned by Denbury Resources Inc. SEC Case," "Appraisal Report as of December 31, 2003 on Proved Reserves of Certain Properties owned by Denbury Resources Inc. SEC Case," and "Appraisal Report as of December 31, 2002 on Proved Reserves of Certain Properties owned by Denbury Resources Inc. SEC Case" (our Reports) under the sections "Financial Highlights," "Selected Operating Data - Oil and Gas Reserves," "Operations Section of Annual Report - Our CO2 Assets," and "Notes to Consolidated Financial Statements - Estimated Quantities of Reserves and Standardized Measure of Future Net Cash Flows" in the Denbury Resources Inc. Annual Report on Form 10-K for the year ended December 31, 2004. We further consent to the incorporation of our "Appraisal Report as of December 31, 2004 on Proved Reserves of Certain Properties owned by Denbury Resources Inc. SEC Case" in such Form 10-K as Exhibit 99 therein. Very truly yours, /s/ DeGolyer and MacNaughton ---------------------------- DeGolyer and MacNaughton EX-10 3 fy2004-exhibit10j.txt EXHIBIT 10(J), EMPLOYEE STOCK OPTIONS Exhibit 10(j) Description of Stock Option Grant Practices for Employees and Officers Our compensation program currently includes the issuance of stock options to all of our eligible employees and officers on their date of hire, with additional options granted each year as part of the annual review by the Compensation Committee of compensation (see also Exhibit 10(i)). An employees' initial grant generally vest 25% per year over a period of four years, while the annual grants generally cliff vest 100% four years from the grant date. The goal of our stock option grant program to all employees is to provide a generally consistent level of option grants that vest each year. As part of their annual compensation evaluation, the Compensation Committee considers the computed value of stock options using the Black-Scholes pricing model, and also takes into consideration: o the total options outstanding relative to the total common stock outstanding; o the number of option grants made by comparable companies in the aggregate and for similar positions; o the perceived incentive value of the options currently held by the employees; and o the overall compensation package by the Company for that year. Based on these factors, the Committee determines the appropriate number of stock options to set aside for issuance to new employees and the number to be granted to existing employees who are part of the Company's annual recurring grant program. Since the price of the Company's stock has generally increased over the last few years, the Black-Scholes pricing model suggests that the number of stock options granted to each employee should decrease correspondingly, assuming that other variables that are part of the Black-Scholes computation remain constant. The Committee, following a practice generally used since 1999, has reduced the number of annual option grants to each employee by approximately one-half of what the Black-Scholes formula would suggest is necessary to maintain a consistent level of stock option compensation for each employee, as they believe the other factors, noted above, should also be taken into consideration. Once overall Company-wide levels of cash compensation and stock option grants are determined, stock options are generally allocated among employees on the basis of their current year bonuses which are set at the same time. Our executive officers receive a level of stock options calculated using the same percentage of bonuses as the other employees in the management and professional group, using the same classifications of employees referenced in Exhibit 10(i) third level even though their bonuses are paid at the fourth level. These classifications of employees for cash bonuses and stock options are generally based upon the level of base compensation. All options are granted at the prevailing market price for our common stock and only have value if the market price of the common stock increases after the date of grant. All of the options granted under the option plan expire ten years from the date of grant and, to the extent allowed under the United States federal income tax laws, are granted as incentive stock options. Currently we plan to discontinue the use of stock options effective July 1, 2005. Future grants to new employees and recurring grants to existing employees will be made with stock appreciation rights payable only in stock rather than stock options. The allocation methodology and practice is expected to remain the same. This change will not impact the employees' level of compensation or potential economic benefit, but will benefit all shareholders as it will significantly reduce the amount of dilution caused by the issuance of stock options. EX-10 4 fy2004-exhibit10h.txt EXHIBIT 10(H), DIRECTOR'S CASH COMPENSATION Exhibit 10(h) Director's Cash Compensation Arrangements We increased our cash compensation for the non-employee directors effective July 1, 2004. Since July 2004, directors have been paid an annual retainer fee of $35,000, plus $2,000 per board meeting attended and $1,000 per telephone conference attended. The Chairman of the Compensation Committee and the Chairman of the Board are also paid an additional fee of $5,000 per year. The Co-Chairman of the Audit Committee are both paid an additional fee of $20,000 per year and the other Audit Committee members are paid an additional annual retainer of $5,000 for serving on the Audit Committee. The members of the Audit Committee may also receive an additional $5,000 per year fee for performing special services. The only such award to date has been to Mr. Heather who performs review work on our annual reserve report and began receiving this additional fee in the fourth quarter of 2002. The Director Plan allows each non-employee director to make an annual election in the preceding year to receive his or her compensation either in cash or in shares of our common stock and to elect to defer receipt of such compensation, if they wish (see Exhibit 10(e)). EX-99 5 fy2004-exhibit99.txt EXHIBIT 99, PROVED RESERVES APPRAISAL REPORT Exhibit 99 DEGOLYER AND MACNAUGHTON 4925 Greenville Avenue, Suite 400 One Energy Square Dallas, Texas 75206 APPRAISAL REPORT as of DECEMBER 31, 2004 on PROVED RESERVES of CERTAIN PROPERTIES owned by DENBURY RESOURCES INC. SEC CASE DeGolyer and MacNaughton TABLE of CONTENTS Page ---- FOREWARD.....................................................................1 Scope of Investigation.....................................................1 Authority..................................................................2 Source of Information......................................................2 CLASSIFICATION of RESERVES...................................................3 ESTIMATE of RESERVES.........................................................5 VALUATION of RESERVES........................................................6 SUMMARY and CONCLUSIONS......................................................9 DEGOLYER AND MACNAUGHTON 4925 Greenville Avenue, Suite 400 One Energy Square Dallas, Texas 75206 APPRAISAL REPORT as of DECEMBER 31, 2004 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, 2004, 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). Estimates of carbon dioxide gas reserves are also included. The reserves estimated in this report are located in Arkansas, Louisiana, Mississippi, Texas, and offshore from Louisiana and Texas. The properties appraised are listed in detail in a related report entitled "Appraisal Report as of December 31, 2004 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, 2004. 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 $43.45 per barrel and $6.149 per million British thermal units (MMBtu). No escalation has been applied to prices and costs. Degolyer and MacNaughton 2 A 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 expenses, 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 represented. A field examination of the properties was not considered necessary for the purposes of this report. DeGolyer and MacNaughton 3 CLASSIFICATION of RESERVES - -------------------------- Petroleum reserves included in this report are classified 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 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. DeGolyer and MacNaughton 4 (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 recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. DeGolyer and MacNaughton 5 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 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 DeGolyer and MacNaughton 6 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, 2003, gross production estimated to December 31, 2004, 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 2004. The following table presents estimates of the proved reserves, as of December 31, 2004, of the properties appraised, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):
Oil and Natural Gas Total Condensate Liquids Liquids Gas (Mbbl) (Mbbl) (Mbbl) (MMcf) ---------------- --------------- ---------- --------- Gross Proved Reserves Developed Producing 102,966 270 103,236 233,923 Developed Nonproducing 22,247 279 22,526 64,020 Undeveloped 57,027 166 57,193 115,319 ---------------- --------------- ---------- --------- Total Gross Reserves 182,240 715 182,955 413,262 Net Proved Reserves Developed Producing 39,411 139 39,550 68,568 Developed Nonproducing 16,302 147 16,449 26,005 Undeveloped 45,203 85 45,289 73,911 ---------------- --------------- ---------- --------- Total Net Reserves 100,916 371 101,288 168,484
In addition to the natural gas reserves shown in the foregoing tabulation, Denbury's net proved carbon dioxide gas reserves in Mississippi, as of December 31, 2004, are estimated to be 2,128,692 MMcf. This amount includes 1,529,477 MMcf of developed reserves and 599,215 MMcf of undeveloped reserves. The carbon dioxide gas reserves have been prepared under the same guidelines as those for oil and natural gas. No revenue estimates have been made for the carbon dioxide reserves. 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 United States Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB). DeGolyer and MacNaughton 7 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 $43.45 per barrel and held constant thereafter. The weighted average price over the lives of the properties was $36.77 per barrel. Natural Gas Liquids Prices Natural gas liquids prices were calculated using the 2003 average ratio to the NYMEX oil price of $43.45 per barrel. These prices were held constant over the lives of the properties. The average price over the lives of the properties is $26.88 per barrel. Natural Gas Prices Natural gas prices were calculated for each lease using differentials furnished by Denbury to a NYMEX price of $6.149 per MMBtu and held constant thereafter. The weighted average price over the lives of the properties was $6.06 per thousand cubic feet. Operating Expenses and Capital Costs Current operating expenses and capital costs, based on information provided by Denbury, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation. The future revenue to be derived from the production and sale of the proved reserves, as of December 31, 2004, of the properties appraised is estimated as follows: DeGolyer and MacNaughton 8
Proved ------------------------------------------------------ Developed Developed Total Producing Nonproducing Undeveloped Proved ------------------------------------------------------ Future Gross Revenue, M$ 1,754,596 777,921 2,209,758 4,742,275 Production and Ad Valorem Taxes, M$ 77,195 35,410 86,847 199,452 Operating Expenses, M$ 588,992 150,680 570,155 1,309,827 Capital Costs, M$ 8,859 20,257 297,970 327,086 Abandonment Costs, M$ 13,474 (194) 512 13,792 Future Net Revenue, M$ 1,066,076 571,768 1,254,273 2,892,118 Present Worth at 10 Percent, M$ 710,278 327,744 605,266 1,643,289 1. Numbers in table may not add due to rounding. 2. 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. 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. DeGolyer and MacNaughton 9 SUMMARY and CONCLUSIONS - ----------------------- Denbury owns working and royalty interests in certain properties located in Arkansas, Louisiana, Mississippi, Texas, and offshore from Louisiana and Texas. The estimated net proved reserves of the properties appraised, as of December 31, 2004, are summarized as follows, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):
Oil and Natural Gas Total Condensate Liquids Liquids Gas (Mbbl) (Mbbl) (Mbbl) (MMcf) ---------------- --------------- ---------- --------- Net Proved Reserves Developed Producing 39,411 139 39,550 68,568 Developed Nonproducing 16,302 147 16,449 26,005 Undeveloped 45,203 85 45,289 73,911 ---------------- --------------- ---------- --------- Total 100,916 371 101,288 168,484
The estimated revenue and expenditures attributable to Denbury's interests in the proved reserves, as of December 31, 2004, 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, M$ 1,754,596 777,921 2,209,758 4,742,275 Production and Ad Valorem Taxes, M$ 77,195 35,410 86,847 199,452 Operating Expenses, M$ 588,992 150,680 570,155 1,309,827 Capital Costs, M$ 8,859 20,257 297,970 327,086 Abandonment Costs, M$ 13,474 (194) 512 13,792 Future Net Revenue, M$ 1,066,076 571,768 1,254,273 2,892,118 Present Worth at 10 Percent, M$ 710,278 327,744 605,266 1,643,289 1. Numbers in table may not add due to rounding. 2. Future income taxes have not been taken into account in the preparation of these estimates.
DeGolyer and MacNaughton 10 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, SIGNED: March 9, 2005 /s/ DeGolyer and MacNaughton ---------------------------- DeGolyer and MacNaughton /s/ Paul J. Szatkowski, P.E. ---------------------------- Paul J. Szatkowski, P.E. Senior Vice President DeGolyer and MacNaughton EX-23 6 fy2004-exhibit23a.txt EXHIBIT 23(A), CONSENT OF PRICEWATERHOUSECOOPERS EXHIBIT 23(a) CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (Nos. 333-1006, 333-27995, 333-55999, 333-70485, 333-39172, 333-39218, 333-63198, 333-90398, 333-106253, and 333-116249) and Form S-3 (No. 333-107676) of Denbury Resources Inc. of our report dated March 14, 2005 relating to the financial statements, management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLP - ------------------------------ PricewaterhouseCoopers LLP Dallas, Texas March 14, 2005 EX-21 7 fy2004-exhibit21.txt EXHIBIT 21, SUBSIDIARIES OF THE REGISTRANT EXHIBIT 21 LIST OF SUBSIDIARIES JURISDICTION OF NAME OF SUBSIDIARY INCORPORATION STATUS 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 9.25% general partner interest of Genesis Energy LP and .01% general partner interest of Genesis Crude Oil LP Denbury Operating Company Delaware Wholly owned subsidiary of Denbury Resources Inc. - operating holding company of limited liability companies Denbury Onshore, L.L.C. Delaware Wholly owned subsidiary of Denbury Operating Company - onshore oil and gas properties Denbury Marine, L.L.C. Louisiana Wholly owned subsidiary of Denbury Operating Company - marine company Tuscaloosa Royalty Fund L.L.C. Delaware Wholly Owned Subsidiary of Denbury Operating Company
EX-23 8 fy2004-exhibit23b.txt EXHIBIT 23(B), CONSENT OF DELOITTE & TOUCHE LLP EXHIBIT 23(b) CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Post-Effective Amendment No. 1 to Registration Statement Nos. 333-1006, 333-27995, 333-55999, 333-70485 , 333-39218, 333-63198, 333-106253, and 333-116249 on Form S-8, Post-Effective Amendment No. 2 to Registration Statements Nos. 333-39172 and 333-90398 on Form S-8 and Post-Effective Amendment No. 2 to Registration Statement No. 333-107676 on Form S-3 of our report dated March 8, 2004 relating to the financial statements of Denbury Resources Inc., which report expresses an unqualified opinion and includes an explanatory paragraph relating to a change in method of accounting for asset retirement obligations in 2003 as required by Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations", appearing in this Annual Report on Form 10-K of Denbury Resources Inc. for the year ended December 31, 2004. /s/ Deloitte & Touche LLP - ------------------------- Dallas, Texas March 14, 2005 EX-31 9 fy2004-exhibit31a.txt EXHIBIT 31(A) - CERTIFICATION OF GARETH ROBERTS Exhibit 31 (a) CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Gareth Roberts, certify that: 1. I have reviewed this report on Form 10-K of Denbury Resources Inc. (the "registrant"); 2. Based on my knowledge, this 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 report; 3. Based on my knowledge, the financial statements, and other financial information included in this 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 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-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Dated: March 15, 2005 /s/ Gareth Roberts ------------------ Gareth Roberts President and Chief Executive Officer EX-31 10 fy2004-exhibit31b.txt EXHIBIT 31(B) - CERTIFICATION (302) OF CFO Exhibit 31(b) CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Phil Rykhoek, certify that: 1. I have reviewed this report on Form 10-K of Denbury Resources Inc. (the "registrant"); 2. Based on my knowledge, this 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 report; 3. Based on my knowledge, the financial statements, and other financial information included in this 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 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-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Dated: March 15, 2005 /s/ Phil Rykhoek ---------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer EX-32 11 fy2004-exhibit32.txt EXHIBIT 32, CERTIFICATION (906) OF CEO AND CFO Exhibit 32 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, 2004 (the "Report") of Denbury Resources Inc. ("Denbury") as filed with the Securities and Exchange Commission on March 15, 2005, 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 15, 2005 /s/ Gareth Roberts ------------------ Gareth Roberts President and Chief Executive Officer Dated: March 15, 2005 /s/ Phil Rykhoek ---------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer EX-10 12 fy2004-exhibit10g.txt EXHIBIT 10(G), OMNIBUS STOCK & INCENTIVE PLAN Exhibit 10(g) 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. TABLE OF CONTENTS 1. Purpose.................................................................1 2. Definitions.............................................................1 (a) "Administrator"................................................1 (b) "Agreed Price".................................................1 (c) "Applicable Laws"..............................................1 (d) "Award"........................................................1 (e) "Board"........................................................1 (f) "Broker Assisted Exercise".....................................1 (g) "Cause"........................................................2 (h) "Change in Control"............................................2 (i) "Change in Control Price"......................................3 (j) "Code".........................................................3 (k) "Committee"....................................................3 (l) "Common Stock".................................................3 (m) "Company"......................................................3 (n) "Date of Grant"................................................3 (o) "Director".....................................................3 (p) "Disability"...................................................3 (q) "Effective Date"...............................................3 (r) "Eligible Person(s)"...........................................3 (s) "Employee(s)"..................................................4 (t) "Fair Market Value"............................................4 (u) "Holder".......................................................4 (v) "Incentive Stock Option".......................................4 (w) "Investment Committee".........................................4 (x) "Limited SAR"..................................................4 (y) "Non-Qualified Stock Option"...................................4 (z) "Option".......................................................4 (aa) "Option Price".................................................4 (bb) "Parent".......................................................4 (cc) "Performance Award"............................................4 (dd) "Performance Measures".........................................5 (ee) "Performance Period"...........................................5 (ff) "Plan".........................................................5 (gg) "Plan Year"....................................................5 (hh) "Reserved Shares"..............................................5 (ii) "Restriction(s)" "Restricted"..................................5 (jj) "Restricted Period"............................................5 (kk) "Restricted Shares"............................................5 (ll) "Restricted Share Award".......................................5 (mm) "Restricted Share Distributions"...............................5 (nn) "SAR"..........................................................5 (oo) "Share(s)".....................................................6 i (pp) "Spread".......................................................6 (qq) "Separation"...................................................6 (rr) "Subsidiary"...................................................6 (ss) "1933 Act".....................................................6 (tt) "1934 Act".....................................................6 (uu) "Vested".......................................................6 (vv) "10% Person"...................................................6 3. Award of Reserved Shares................................................6 4. Conditions for Grant of Awards..........................................7 5. Grant of Options........................................................8 6. Option Price............................................................8 7. Exercise of Options.....................................................9 8. Vesting of Options......................................................9 9. Termination of Option Period...........................................10 10. Acceleration...........................................................11 11. Adjustment of Reserved Shares..........................................11 12. Transferability of Awards..............................................13 13. Issuance of Reserved Shares............................................13 14. Administration of the Plan.............................................13 15. Tax Withholding........................................................15 16. Restricted Share Awards................................................15 17. Performance Awards.....................................................16 18. Stock Appreciation Rights and Limited Stock Appreciation Rights........17 19. Section 83(b) Election.................................................20 20. Interpretation.........................................................20 21. Amendment and Discontinuation of the Plan..............................20 22. Effective Date and Termination Date....................................21 ii 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. 1. Purpose. The purpose of this Plan is to advance the interests of Denbury Resources Inc., a Delaware Corporation, and increase shareholder value by providing additional incentives to attract, retain and motivate those qualified and competent employees and Directors, upon whose efforts and judgment its success is largely dependent. 2. Definitions. As used herein, the following terms shall have the meaning indicated: (a) "Administrator" shall mean the person(s) designated by the Committee to carry out nondiscretionary administrative duties with respect to the Plan and Awards. (b) "Agreed Price" shall relate to the grant of an Award in the form of a SAR or Limited SAR, and shall mean the value assigned to the Award's Reserved Shares which will form the basis for calculating the Spread on the date of exercise of the SAR or Limited SAR, which assigned value shall be the Fair Market Value of such Reserved Shares on the Date of Grant. (c) "Applicable Laws" means the requirements relating to the administration of stock option plans under U.S. state corporate laws, U.S. federal and state securities laws, and the Code; and the similar laws of any foreign country or jurisdiction where Options are, or will be, granted. (d) "Award" shall mean either an Option, a SAR, a Restricted Share Award, or a Performance Award, except that where it shall be appropriate to identify the specific type of Award, reference shall be made to the specific type of Award; and provided, further, that references to Award shall be deemed to be references to the written agreement evidencing such Award, and provided, finally, without limitation, that unless expressly provided to the contrary in the terms of the Award, in the event of a conflict between the terms of the Plan and the terms of an Award, the terms of the Plan are controlling. (e) "Board" shall mean the Board of Directors of the Parent. (f) "Broker Assisted Exercise" shall mean a special sale and remittance procedure pursuant to which the Holder of an Option shall concurrently provide irrevocable written instructions to (a) an Administrator designated brokerage firm ("Broker") to effect the immediate sale of the Reserved Shares and remit to the Administrator, out of the sale proceeds available on the settlement date, sufficient funds to cover the aggregate Option Price plus all applicable Federal, state and local income and employment taxes required to be withheld by the Company, and (b) the Administrator to deliver the certificates for the Shares directly to such brokerage firm in order to complete the sale. 1 (g) "Cause" shall mean either (i) a final, nonappealable conviction of a Holder for commission of a felony involving moral turpitude, or (ii) Holder's willful gross misconduct that causes material economic harm to the Company or that brings substantial discredit to the Company's reputation. (h) "Change in Control"shall mean any one of the following: (1) "Continuing Directors" no longer constitute a majority of the Board; the term "Continuing Director" means any individual who has served in such capacity for one year or more; (2) after the Effective Date, any person or group of persons acting together as an entity (other than the Texas Pacific Group and its Affiliates) become (i) the beneficial owners (as defined in Rule 13d-3 under the Securities Exchange Act of 1934, as amended) directly or indirectly, of shares of common stock representing thirty percent (30%) or more of the voting power of the Company's then outstanding securities entitled generally to vote for the election of the Company's Directors, and (ii) the largest beneficial owner directly or indirectly of the Company's then outstanding securities entitled generally to vote for the election of the Company's Directors; (3) the merger or consolidation to which the Company is a party if (i) the stockholders of the Company immediately prior to the effective date of such merger or consolidation have beneficial ownership (as defined in Rule 13d-3 under the Exchange Act) of less than forty percent (40%) of the combined voting power to vote for the election of directors of the surviving corporation or other entity following the effective date of such merger or consolidation; or (ii) fifty percent (50%) or more of the individuals constituting the members the Investment Committee are terminated due to the Change in Control; or (4) the sale of all or substantially all, of the assets of the Company or the liquidation or dissolution of the Company. (5) Notwithstanding the foregoing provisions of this Section 2(h), if a Holder's Separation is for a reason other than for Cause, and occurs not more than 90 days prior to the date on which a Change in Control occurs, for purposes of Awards, such termination shall be deemed to have occurred immediately following a Change in Control. (6) Notwithstanding anything herein to the contrary, under no circumstances will a change in the constitution of the board of directors of any Subsidiary, a change in the beneficial ownership of any Subsidiary, 2 the merger or consolidation of a Subsidiary with any other entity, the sale of all or substantially all of the assets of any Subsidiary or the liquidation or dissolution of any Subsidiary constitute a "Change in Control" under this Plan. (i) "Change in Control Price" shall mean the higher of (i) the highest price per Share paid in any transaction reported on the NYSE or such other exchange or market as is the principal trading market for the Common Stock, or (ii) the highest price per share paid in any bona fide transaction related to a Change in Control, at any time during the 60 day period immediately preceding such occurrence; with such occurrence date to be determined by the Committee. (j) "Code" shall mean the Internal Revenue Code of 1986, as now or hereafter amended. (k) "Committee" shall mean the Compensation Committee of the Board, provided, further, that in granting Performance Awards, Committee shall refer to only those members of the Compensation Committee who are "Outside Directors" within the meaning of Section 162(m) of the Code. (l) "Common Stock" shall mean the common stock, $.001 par value, of the Parent. (m) "Company" shall mean, individually and collectively, the Parent and the Subsidiaries, except that when it shall be appropriate to refer only to Denbury Resources Inc., the reference will be to "Parent". (n) "Date of Grant" shall mean the date on which the Committee takes formal action to grant an Award, provided that it is followed, as soon as reasonably practicable, by written notice to the Eligible Person receiving the Award. (o) "Director" shall mean a member of the Board. (p) "Disability" shall mean a Holder's present incapacity resulting from an injury or illness (either mental or physical) which, in the reasonable opinion of the Administrator based on such medical evidence as it deems necessary, will result in death or can be expected to continue for a period of at least twelve (12) months and will prevent the Holder from performing the normal services required of the Holder by the Company; provided, however, that such disability did not result, in whole or in part: (i) from chronic alcoholism; (ii) from addiction to narcotics; (ii) from a felonious undertaking; or (iv) from an intentional self-inflicted wound. (q) "Effective Date" shall mean May 12, 2004. (r) "Eligible Person(s)" shall mean those persons or entities, as applicable, who are Employees, or non-employee Directors. 3 (s) "Employee(s)" shall mean each person whose customary work schedule is a minimum of thirty (30) hours per week, and who is designated as an employee on the books of the Company. (t) "Fair Market Value" per Share on the date of reference shall be the Closing Price on such date, provided, further, that if the actual transaction involving the Shares occurs at a time when the New York Stock Exchange is closed for regular trading, then it shall be the most recent Closing Price; provided, further, that "Closing Price" means the closing price of the Shares on the New York Stock Exchange as reported in any newspaper of general circulation. (u) "Holder" shall mean, at each time of reference, each person with respect to whom an Award is in effect; provided, further, that following the death of a Holder, it shall refer to the person who succeeds to the rights of such Holder. (v) "Incentive Stock Option" shall mean an Option that is an incentive stock option as defined in Section 422 of the Code. (w) "Investment Committee" shall mean the committee of that name established by the Board, who shall be solely responsible for selecting its members, and whose members on the Effective Date are Messrs. Gareth Roberts, Ronald T. Evans, Mark Worthey and Phil Rykhoek. (x) "Limited SAR" shall mean a limited stock appreciation right as defined in Section 18 hereof. (y) "Non-Qualified Stock Option" shall mean an Option that is not an Incentive Stock Option. (z) "Option" (when capitalized) shall mean the grant of the right to purchase Reserved Shares through the payment of the Option Price and taking the form of either an Incentive Stock Option or a Non-Qualified Stock Option; except that, where it shall be appropriate to identify a specific type of Option, reference shall be made to the specific type of Option; provided, further, without limitation, that a single Option may include both Incentive Stock Option and Non-Qualified Stock Option provisions. (aa) "Option Price" shall mean the price per Reserved Share which is required to be paid by the Holder in order to exercise his or her right to acquire the Reserved Share under the terms of the Option. (bb) "Parent" shall mean Denbury Resources Inc. 4 (cc) "Performance Award" shall mean the award which is granted contingent upon the attainment of the performance objectives during the Performance Period, all as described more fully in Section 17. (dd) "Performance Measures" shall mean one or more of the following: (i) earnings per share, (ii) return on average common equity, (iii) pre-tax income, (iv) pre-tax operating income, (v) net revenue, (vi) net income, (vii) profits before taxes, (viii) book value per share, (ix) changes in amounts of oil and gas reserves, (x) changes in production rates, (xi) net asset value, (xii) net asset value per share, (xiii) sales, (xiv) finding costs, or (xv) operating cost reductions, but shall not include remaining in the employ of the Company for a specified period of time. (ee) "Performance Period" shall mean the period described in Section 17 with respect to which the performance objectives relate. (ff) "Plan" shall mean this 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (gg) "Plan Year" shall mean the calendar year. (hh) "Reserved Shares" shall mean, at each time of reference, the total number of Shares described in Section 3 with respect to which the Committee may grant an Award, all of which Reserved Shares shall be held in the Parent's treasury or shall be made available from the Parent's authorized and unissued Shares. (ii) "Restriction(s)" "Restricted" and similar shall mean the restrictions applicable to Reserved Shares subject to an Award which constitute "a substantial risk of forfeiture" of such Reserved Shares within the meaning of Section 83(a)(1) of the Code. (jj) "Restricted Period" shall mean the period during which Restricted Shares are subject to Restrictions. (kk) "Restricted Shares" shall mean the Reserved Shares granted to an Eligible Person which are subject to Restrictions; provided, further, that the Committee may, in its sole discretion, determine that the Restrictions which otherwise would have been imposed have been fully satisfied on the Date of Grant by reason of prior service and/or other considerations, and thus provide that such Restricted Shares shall be fully Vested on the Date of Grant. 5 (ll) "Restricted Share Award" shall mean the award of Restricted Shares. (mm) "Restricted Share Distributions" shall mean any amounts, whether Shares, cash or other property (other than regular cash dividends) paid or distributed by the Parent with respect to Restricted Shares during a Restricted Period. (nn) "Retirement Vesting Date" shall mean the first birthday of a Holder on which that Holder has attained the later of (i) his 60th birthday, and (ii) the birthday on which that Holder attains an age equal to (x) 65 minus (y) the number which results from multiplying (A) fifty percent (50%) times (B) that Holder's full years of service as an Employee on such birthday, with such product of (A) and (B) rounded down to the nearest whole number before being deducted from 65. For example only, and without limiting the generality of the foregoing, a Holder who has completed 70 months of service (i.e., 5 full years of service) as an Employee on his 62nd birthday will not have attained his Retirement Vesting Date, whereas a Holder who has completed 72 months of service (i.e., 6 full years of service) as an Employee on his 62nd birthday will have attained his Retirement Vesting Date. (oo) "SAR" shall mean a stock appreciation right as defined in Section 18 hereof. (pp) "Share(s)" shall mean a share or shares of Common Stock. (qq) "Spread" shall mean the difference between the Option Price, or the Agreed Price, as the case may be, of the Share(s) on the date of the Award, and the Fair Market Value of such Share(s) on the date of reference. (rr) "Separation" shall mean the date on which a Holder ceases to have an employment relationship with the Company for any reason, including death or Disability; and provided, further, without limitation, such employment relationship will cease, in the case of a non-Employee Director, upon his or her ceasing to be a Director; provided, however, that a Separation will not be considered to have occurred while an Employee is on sick leave, military leave, or any other leave of absence approved by the Company, if the period of such leave does not exceed 90 days, or, if longer, so long as the Employee's right to redeployment with the Company is guaranteed either by statute or by contract. (ss) "Subsidiary" shall mean, where the Award is an Incentive Stock Option, a "subsidiary corporation", whether now or hereafter existing, as defined in Section 424(f) of the Code, and on the case of any other Award, shall mean any entity which would be a subsidiary corporation as defined in Section 424(f) of the Code if it were a corporation. Notwithstanding the foregoing, Genesis Energy, Inc. shall not be considered a Subsidiary for purposes of this Plan. (tt) "1933 Act" shall mean the Securities Act of 1933, as amended. (uu) "1934 Act" shall mean the Securities Exchange Act of 1934, as amended. 6 (vv) "Vested" and similar terms shall mean the number of Option Shares which have become nonforfeitable and the number of Restricted Shares on which the Restrictions have lapsed; provided, further, and without limitation, that the lapse of Restrictions based on the attainment of performance objectives is also a Vesting event. (ww) "10% Person" shall mean a person who owns directly (or indirectly through attribution under Section 425(d) of the Code) at the Date of Grant of an Incentive Stock Option, stock possessing more than 10% of the total combined voting power of all classes of voting stock (as defined in Section 424 of the Code) of the Parent on the Date of Grant. 3. Award of Reserved Shares. (a) As of the Effective Date, 2,500,000 Shares shall automatically, and without further action, become Reserved Shares. Notwithstanding the foregoing, not more than 1,375,000 Reserved Shares may be issued under the Plan as a result of the Vesting of Restricted Stock or Performance Awards. To the extent any Award shall terminate, expire or be canceled, the Reserved Shares subject to such Award (or with respect to which the Award is measured), shall remain Reserved Shares. Where an Award is settled on a basis other than the issuance of Reserved Shares, the Reserved Shares which measured the amount of such Award settlement shall be canceled and no longer considered Reserved Shares. (b) Notwithstanding any provision in this Plan to the contrary, no person whose compensation may be subject to the limitations on deductibility under Section 162(m) of the Code shall be eligible for a grant during a single calendar year of an Award with respect to, or measured by, more than 500,000 Reserved Shares. The limitation under this Section 3(b) shall be construed so as to comply with the requirements of Section 162(m) of the Code. 4. Conditions for Grant of Awards. (a) Without limiting the generality of the provisions hereof which deal specifically with each form of Award, Awards shall only be granted to such one or more Eligible Persons as shall be selected by the Committee. (b) In granting Awards, the Committee shall take into consideration the contribution the Eligible Person has made or may be reasonably expected to make to the success of the Company and such other factors as the Committee shall determine. The Committee shall also have the authority to consult with and receive recommendations from officers and other personnel of the Company with regard to these matters. The Committee may from time to time in granting Awards under the Plan prescribe such terms and conditions concerning such Awards as it deems appropriate, including, without limitation, relating an Award to achievement of specific goals established by the Committee or to the continued employment of the Eligible Person for a specified period of time, provided that such terms and conditions are not inconsistent with the provisions of this Plan. 7 (c) Incentive Stock Options may be granted only to Employees, and all other Awards may be granted to any Eligible Person. (d) The Plan shall not confer upon any Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall it interfere in any way with his or her right or the Company's right to terminate his or her employment at any time. (e) The Awards granted to Eligible Persons shall be in addition to regular salaries, pension, life insurance or other benefits (if any) related to their service to the Company, and nothing herein shall be deemed to limit the ability of the Company to enter into any other compensation arrangements with any Eligible Person. (f) The Administrator shall determine in each case whether periods of military or government service shall constitute a continuation of employment or service for the purposes of this Plan or any Award. (g) Notwithstanding any provision hereof to the contrary, each Award which in whole or in part involves the issuance of Reserved Shares may provide for the issuance of such Reserved Shares for consideration consisting of cash or cash equivalents, or such other consideration as the Committee may determine, including (without limitation) as compensation for past services rendered. (h) The Committee may delegate in writing to the Administrator the authority to grant Awards to new Employees of the Company, provided that such authority contains limits on the maximum amount or number of Awards (on both an individual basis and, if the Committee so designates, on an aggregate basis) that the Administrator may grant under such authority. Such authority shall also designate the terms and conditions for these grants. 5. Grant of Options. (a) The Committee may grant Options to Eligible Persons from time to time, alone, in addition to, or in tandem with, other Awards granted under the Plan. An Option granted hereunder shall be either an Incentive Stock Option or a Non-Qualified Stock Option, and shall clearly state whether it is (in whole or in part) an Incentive Stock Option or a Non-Qualified Stock Option; provided, further, that failure of an Option designated as an Incentive Stock Option to qualify as an Incentive Stock Option will not affect its validity, and the portion which does not qualify as an Incentive Stock Option shall be a Non-Qualified Stock Option. (b) If both Incentive Stock Options and Non-Qualified Stock Options are granted to a Holder, the right to exercise, to the full extent thereof, Options of either type shall not be contingent in whole or in part upon the exercise of, or failure to exercise, Options of the other type. 8 (c) The aggregate Fair Market Value (determined as of the Date of Grant) of the Reserved Shares with respect to which any Incentive Stock Option is exercisable for the first time by a Holder during any calendar year under the Plan and all such plans of the Company (as defined in Section 425 of the Code) shall not exceed $100,000; provided, further, without limitation, that any portion of an Option designated as an Incentive Stock Option which exceeds such $100,000 limit will, notwithstanding such designation, be a validly granted Non-Qualified Stock Option. (d) The Committee may at any time offer to buy out for a payment in cash, an Option previously granted, based on such terms and conditions as the Committee shall establish and as communicated to the Holder by the Administrator at the time that such offer is made. 6. Option Price. (a) The Option Price shall be any price determined by the Committee which is not less than one hundred percent (100%) of the Fair Market Value per Share on the Date of Grant; provided, however, that in the case of an Incentive Stock Option granted to a 10% Person the Option Price shall not be less than 110% of the Fair Market Value per Share on the Date of Grant. The Administrator shall determine the Fair Market Value per Share. (b) Unless further limited by the Committee in any Option, the Option Price may be paid in cash, by certified or cashier's check, by wire transfer, by money order, through a Broker Assisted Exercise, with Shares (but with Shares only if expressly permitted by the terms of the Option and only with Shares owned by the Holder for at least 6 months prior to the exercise date), or by a combination of the above; provided, however, that the Administrator may accept a personal check in full or partial payment. If the Option Price is permitted to be, and is, paid in whole or in part with Shares, the value of the Shares surrendered shall be the Shares' Fair Market Value on the date delivered to the Administrator. 7. Exercise of Options. An Option shall be deemed exercised when (i) the Administrator has received written notice of such exercise in accordance with the terms of the Option, and (ii) full payment of the aggregate Option Price plus required withholding tax amounts, if any, described in Section 15, of the Reserved Shares as to which the Option is exercised has been made. Separate stock certificates shall be issued by the Parent for any Reserved Shares acquired as a result of exercising an Incentive Stock Option and a Non-Qualified Stock Option. 8. Vesting of Options. (a) Without limitation, each Option shall Vest in whole or in part, and shall expire, according to the terms of the Option. Unless otherwise expressly provided in an Option, each Option which is not an Annual Option as described in Section 8(b) below, shall Vest, and Reserved Shares subject to such Option shall become Vested Option Shares, on the dates set forth in the following Vesting Schedule: 9 (1) 25% of the Reserved Shares on the first anniversary of the Date of Grant; (2) 25% of the Reserved Shares on the second anniversary of the Date of Grant; (3) 25% of the Reserved Shares on the third anniversary of the Date of Grant; and (4) 25% of the Reserved Shares on the fourth anniversary of the Date of Grant. (b) Except as otherwise expressly provided in such Option, an Option which is expressly designated as an "Annual" Option shall not Vest, and shall remain 100% forfeitable, until the fourth (4th) anniversary of its Date of Grant, and on such fourth (4th) anniversary of its Date of Grant such Annual Option shall become 100% Vested, and all Reserved Shares subject to such Annual Option shall become Vested Option Shares. (c) The Committee, in its sole discretion, may accelerate the date on which all or any portion of an otherwise unvested Option shall Vest or restrictions on Restricted Shares will lapse. 9. Termination of Option Period. (a) Unless the terms of an Option expressly provide for a different date of termination, the unexercised portion of an Option shall automatically and without notice terminate and become null and void at the time of the earliest to occur of the following: (1) on the 90th day following Holder's Separation for any reason except death, Disability or for Cause; or (2) immediately upon Separation as a result, in whole or in material part, of a discharge for Cause; or (3) on the first anniversary of a Separation by reason of death or Disability; (4) in the case of a 10% Person, on the fifth (5th ) anniversary of the Date of Grant; or (5) on the tenth (10th) anniversary of the Date of Grant. (b) Notwithstanding any provision of the Plan to the contrary, in the event of the proposed dissolution or liquidation of the Parent, or in the event of a proposed sale of all or substantially all of the assets of the Company, or the proposed merger of the Parent with or into another corporation (collectively, 10 the "Transaction"), unless otherwise expressly provided (by express reference to this Section 9(b)) in the terms of an Option, after the public announcement of the Transaction, the Committee may, in its sole discretion, direct the Administrator to deliver a written notice ("Cancellation Notice") to any Holder of an Option, canceling the unexercised Vested portion (including the portion which becomes Vested by reason of acceleration), if any, of such Option, effective on the date specified in the Cancellation Notice ("Cancellation Date"). Notwithstanding the forgoing, the Cancellation Date may not be earlier than the last to occur of (i) the 15th day following delivery of the Cancellation Notice, and (ii) the 60th day prior to the proposed date for the consummation of the Transaction ("Proposed Date"). Without limitation, the Cancellation Notice will provide that, unless the Holder elects in writing to waive, in whole or in part, a Conditional Exercise, that the exercise of the Option will be a Conditional Exercise. A "Conditional Exercise" shall mean that in the event the Transaction does not occur within 180 days of the Proposed Date, the exercising Holder shall be refunded any amounts paid to exercise such Holder's Option, such Option will be reissued, and the purported exercise of such Option shall be null and void ab intitio. 10. Acceleration. (a) Unless otherwise expressly provided in the Award, in the event the Holder's Separation is by reason of the Holder's death, or Disability, all Awards granted to the Holder shall become fully exercisable, Vested, or the Restricted Period shall terminate, as the case may be (hereafter, in this Section 10, such Award shall be "accelerated"). (b) Unless otherwise expressly provided in an Award, in the event of a Change in Control (i) all Awards shall be accelerated, and (ii) in the sole discretion of the Committee, the value of some or all Awards may be cashed out on the basis of the Change in Control Price, at any time during the 60 day period immediately preceding any bona fide transaction related to a Change in Control; provided, further, that if a date prior to such occurrence is selected for a cash out, any subsequent increase in the Change in Control Price will be paid to each Holder on the date of such occurrence, or as soon thereafter as reasonably possible. 11. Adjustment of Reserved Shares. (a) If at any time while the Plan is in effect or Awards with respect to Reserved Shares are outstanding, there shall be any increase or decrease in the number of issued and outstanding Shares through the declaration of a stock dividend or through any recapitalization resulting in a stock split-up, combination or exchange of Shares, then and in such event: (i) appropriate adjustment shall be made in the maximum number of Reserved Shares which may be granted under Section 3, and equitably in the Reserved Shares which are then subject to each Award, so that the same proportion of the Parent's issued and outstanding Common Stock shall continue to be subject to grant under Section 3, and to such Award, and 11 (ii) in addition, and without limitation, in the case of each Award (including, without limitation, Options) which requires the payment of consideration by the Holder in order to acquire Reserved Shares, an appropriate equitable adjustment shall be made in the consideration (including, without limitation the Option Price) required to be paid to acquire the each Reserved Share, so that (i) the aggregate consideration to acquire all of the Reserved Shares subject to the Award remains the same and, (ii) so far as possible, (and without disqualifying an Incentive Stock Option) the relative cost of acquiring each Reserved Share subject to such Award remains the same. All such determinations shall be made by the Board in its sole discretion. (b) The Committee may change, or may direct the Administrator to change, the terms of Options outstanding under this Plan, with respect to the Option Price or the number of Reserved Shares subject to the Options, or both, when, in the Committee's judgment, such adjustments become appropriate by reason of a corporate transaction (as defined in Treasury Regulation ss. 1.425-1(a)(1)(ii)); provided, however, that if by reason of such corporate transaction an Incentive Stock Option is assumed or a new Incentive Stock Option is substituted therefor, the Committee, or at the direction of the Committee, the Administrator, may only change the terms of such Incentive Stock Option such that (i) the excess of the aggregate Fair Market Value of the Shares subject to the substituted Incentive Stock Option immediately after the substitution or assumption, over the aggregate Option Price of such Shares at such time, is not more than the excess of the aggregate Fair Market Value of all Reserved Shares subject to the Incentive Stock Option immediately before such substitution or assumption over the aggregate Option Price of such Reserved Shares at such time, and (ii) the substituted Incentive Stock Option, or the assumption of the original Incentive Stock Option does not give the Holder additional benefits which such Holder did not have under the original Incentive Stock Option. Without limiting the generality of any other provisions hereof, including, without limitation, Section 21, except to the minimum extent, if any, required by Section 424(a) of the Code with respect to Incentive Stock Options, no change made under the authority of this Section 11(b) in the terms of an Option shall alter such Option's material provisions in a way that makes such Option less valuable to its Holder. (c) Except as otherwise expressly provided herein, the issuance by the Parent of shares of its capital stock of any class, or securities convertible into shares of capital stock of any class, either in connection with direct sale for adequate consideration, or upon the exercise of rights or warrants to subscribe therefor, or upon conversion of shares or obligations of the Parent convertible into such shares or other securities, shall not affect, and no adjustment by reason thereof shall be made with respect to, Reserved Shares subject to Awards granted under the Plan. (d) Without limiting the generality of the foregoing, the existence of outstanding Awards with respect to Reserved Shares granted under the Plan shall not affect in any manner the right or power of the Parent to make, authorize or 12 consummate (1) any or all adjustments, recapitalizations, reorganizations or other changes in the Parent's capital structure or its business; (2) any merger or consolidation of the Parent; (3) any issue by the Parent of debt securities, or preferred or preference stock which would rank above the Reserved Shares subject to outstanding Awards; (4) the dissolution or liquidation of the Parent; (5) any sale, transfer or assignment of all or any part of the assets or business of the Company; or (6) any other corporate act or proceeding, whether of a similar character or otherwise. 12. Transferability of Awards. Each Award shall provide that such Award shall not be transferable by the Holder otherwise than by will or the laws of descent and distribution, and that so long as an Holder lives, only such Holder or his or her guardian or legal representative shall have the right to exercise such Incentive Stock Option. 13. Issuance of Reserved Shares. No Holder shall be, or have any of the rights or privileges of, the owner of Reserved Shares subject to an Award unless and until certificates representing such Common Stock shall have been issued and delivered to such Holder. As a condition of any issuance of Common Stock, the Administrator may obtain such agreements or undertakings, if any, as the Administrator may deem necessary or advisable to assure compliance with any such law or regulation or shareholder agreement including, but not limited to, a representation, warranty or agreement to be bound by any legends that are, in the opinion of the Administrator, necessary or appropriate to comply with the provisions of any securities law deemed by the Administrator to be applicable to the issuance of the Reserved Shares and which are endorsed upon the Share certificates. Share certificates issued to the Holder receiving such Reserved Shares who is a party to any shareholders agreement, voting trust, or any similar agreement shall bear the legends contained in such agreements. Notwithstanding any provision hereof to the contrary, no Reserved Shares shall be required to be issued with respect to an Award unless counsel for the Parent shall be reasonably satisfied that such issuance will be in compliance with applicable federal or state securities laws. In no event shall the Company be required to sell or issue Reserved Shares under any Award if the sale or issuance thereof would constitute a violation of applicable federal or state securities law or regulation or a violation of any other law or regulation of any governmental authority or any national securities exchange. As a condition to any sale or issuance of Reserved Shares, the Company may place legends on Reserved Shares, issue stop transfer orders, and require such agreements or undertakings as the Company may deem necessary or advisable to assure compliance with any such law or regulation. Without limitation, the Company shall use its best efforts to register the Reserved Shares with the Securities and Exchange Commission under a Form S-8. 13 14. Administration of the Plan. (a) The Plan shall be administered by the Committee and, except for the powers reserved to the Board in Section 21 hereof, the Committee shall have all of the administrative powers under the Plan. Without limitation, all members of the Committee must be independent Directors under applicable rules of the New York Stock Exchange. (b) The Committee, from time to time, may adopt rules and regulations for carrying out the purposes of the Plan and, without limitation, may delegate all of what, in its sole discretion, it determines to be primarily administrative or ministerial duties to the Administrator. The determinations under, and the interpretations of, any provision of the Plan or an Award by the Committee (or the Administrator in the exercise of his administrative authority) shall, in all cases, be in its sole discretion, and shall be final and conclusive. (c) Any and all determinations and interpretations of the Committee shall be made either (i) by a majority vote of the members of the Committee at a meeting duly called, with at least 2 days prior notice, or (ii) without a meeting, by the written approval of all members of the Committee. (d) No member of the Committee, or the Administrator, shall be liable for any action taken or omitted to be taken by such member or by any other member of the Committee or by the Administrator with respect to the Plan, and to the extent of liabilities not otherwise insured under a policy purchased by the Company, the Company does hereby indemnify and agree to defend and save harmless any member of the Committee, and the Administrator, with respect to any liabilities asserted or incurred in connection with the exercise and performance of their powers and duties hereunder, unless such liabilities are judicially determined to have arisen out of such person's gross negligence, fraud or bad faith. Such indemnification shall include attorney's fees and all other costs and expenses reasonably incurred in defense of any action arising from such act of commission or omission. Nothing herein shall be deemed to limit the Company's ability to insure itself with respect to its obligations hereunder. (e) In particular, and without limitation, except for the authority granted to the Administrator under Section 4(h) to make determinations described in subsections (i), (ii), and (iii) below while carrying out the general delegation by the Committee with respect to the grant of Awards to new Employees, the Committee shall have the sole authority, consistent with the terms of the Plan: (i) to determine whether and to what extent Awards are to be granted hereunder to one or more Eligible Persons; (ii) to determine the number of Reserved Shares to be covered by each such Award granted hereunder; 14 (iii) to determine the terms and conditions of any Award granted hereunder, and to amend or waive any such terms and conditions except to the extent, if any, expressly prohibited by the Plan; (iv) to determine whether and under what circumstances an Option may be settled in Restricted Shares instead of Reserved Shares; (v) to determine whether, to what extent, and under what circumstances Awards under the Plan are to be made, and operate, on a tandem basis vis-a-vis other Awards under the Plan; and (vi) to determine (or to delegate to the Administrator the authority to determine) whether to permit payment of tax withholding requirements in Shares. (f) Without limitation, Committee (and the Administrator in carrying out his responsibilities under Section 4(h)) shall have the authority to adopt, alter, and repeal any or all of its rules, guidelines, and practices with respect to the Plan, and all questions of interpretation, with respect to the Plan or any Award shall be decided by the Committee (or by the Administrator in carrying out his duties under Section 4(h)), whose decision shall be final, conclusive and binding upon the Company and each other affected party. (g) Without limitation, the Committee in its sole discretion may limit the authority granted, or previously granted, hereunder by the Committee to the Administrator by notifying the Administrator in writing of such change. 15. Tax Withholding. On or immediately prior to the date on which a payment is made to a Holder hereunder or, if earlier, the date on which an amount is required to be included in the income of the Holder as a result of an Award, the Holder shall be required to pay to the Company, in cash, or in Shares (but in Shares only if expressly permitted in the Award, or by written authorization of the Administrator, and then only in the minimum amount required to satisfy the minimum withholding requirements with respect to such Award), the amount (if any) which the Company reasonably determines to be necessary in order for the Company to comply with applicable federal or state tax withholding requirements, and the collection of employment taxes; provided, further, without limitation, that the Administrator may require that such payment be made in cash. 16. Restricted Share Awards. (a) The Committee may grant Awards of Restricted Shares to any Eligible Person, for no cash consideration, for such minimum consideration as may be required by applicable law, or for such other consideration as may be specified in the grant. The terms and conditions of Restricted Shares shall be specified in the Award. The Committee, in its sole discretion, shall determine what rights, if any, the person to whom an Award of Restricted Shares is made shall have in the Restricted Shares during the Restriction Period and the Restrictions 15 applicable to the particular Award, including whether the holder of the Restricted Shares shall have the right to vote the Restricted Shares and the extent, if any, of Holder's right to receive Restricted Share Distributions. Unless otherwise provided in the Restricted Share Award, upon the expiration of Restrictions, the Restricted Shares shall cease to be Restricted Shares. (b) The Restrictions on Restricted Shares shall lapse in whole, or in installments, over whatever Restricted Period shall be selected by the Committee. (c) Without limitations, the Committee may accelerate the date on which Restrictions lapse with respect to any Restricted Shares. (d) During the Restricted Period, the certificates representing the Restricted Shares, and any Restricted Share Distributions, shall be registered in the Holder's name and bear a restrictive legend disclosing the Restrictions, the existence of the Plan, and the existence of such Restricted Share Award. Such certificates shall be deposited by the Holder with the Company, together with stock powers or other instruments of assignment, each endorsed in blank, which will permit the transfer to the Company of all or any portion of the Restricted Shares, and any assets constituting Restricted Share Distributions, which shall be forfeited in accordance with the terms of such Restricted Share Award. Restricted Shares shall constitute issued and outstanding Common Stock for all corporate purposes and the Holder shall have all rights, powers and privileges of a holder of unrestricted Shares except those that are expressly excluded under the terms of the Restricted Share Award, and Holder will not be entitled to delivery of the stock certificates until all Restrictions shall have terminated, and the Company will retain custody of all related Restricted Share Distributions (which will be subject to the same Restrictions, terms, and conditions as the related Restricted Shares) until the conclusion of the Restricted Period with respect to the related Restricted Shares; and provided, further, that any Restricted Share Distributions shall not bear interest or be segregated into a separate account but shall remain a general asset of the Company, subject to the claims of the Company's creditors, until the conclusion of the applicable Restricted Period; and provided, finally, that any material breach of any terms of the Restricted Share Award, as reasonably determined by the Administrator, will cause a forfeiture of both Restricted Shares and Restricted Share Distributions. 17. Performance Awards. (a) Performance Awards during a Plan Year may be granted only to the Chief Executive Officer and the four (4) highest paid employees as of the last day of such Plan Year ("Covered Employees"), and shall in all events be specifically designated as Performance Awards. Nothing herein shall be construed as limiting the Committee's authority to grant other types of Awards to Eligible Persons, including Covered Employees, conditioned on the satisfaction of such criteria, including those comprising the Performance Measures, as the Committee, in its sole discretion, may select. (b) Without limitation, the Committee's grant of Performance Awards may, in its sole discretion, be made in Reserved Shares, or in cash, or in a combination of Reserved Shares and cash, but the cash portion of such Award may not exceed $500,000 in a Plan Year. 16 (c) The Committee shall select the Performance Measures which will be required to be satisfied during the Performance Period in order to earn the Performance Award. Such Performance Measures, and the duration of any Performance Period, may differ with respect to each Covered Employee, or with respect to separate Performance Awards issued to the same Covered Employee. The selected Performance Measures, the Performance Period(s), and any other conditions to the Company's obligation to pay a Performance Award shall be set forth in each Performance Award on or before the first to occur of (i) the 90th day of the selected Performance Period, (ii) the first date on which more than 25% of the Performance Period has elapsed, and (iii) the first date, if any, on which satisfaction of the Performance Measure(s) is no longer substantially uncertain. (d) Performance Awards may be payable in a single payment or in installments but may not be paid in whole or in part prior to the date on which the Performance Measures are attained, except that such payment may be accelerated upon the death or Disability of the Covered Employee, or as a result of a Change in Control, it being understood that if such acceleration events occur prior to the attainment of the Performance Measures, the Performance Award will not be exempt from Section 162(m) of the Code. (e) The extent to which any applicable performance objective has been achieved shall be conclusively determined by the Committee, but may be specifically delegated to the Administrator. Without limitation, where a Covered Employee has satisfied the Performance Measures with respect to a Performance Award, if permitted under the terms of such Performance Award, the Committee, in its sole discretion, may reduce the maximum amount payable under such Performance Award. 18. Stock Appreciation Rights and Limited Stock Appreciation Rights (a) The Committee shall have authority to grant (i) a SAR with respect to Reserved Shares, including, without limitation, Reserved Shares covered by any Option ("Related Option"), or (ii) a Limited SAR with respect to all or some of the Reserved Shares covered by any Option, or (iii) a SAR with respect to , or as to some or all of, a Performance Award ("Related Performance Award"). A SAR or Limited SAR granted with respect to a related Option or Related Performance Award must be granted on the Date of Grant of such Related Option or Related Performance Award. (b) For the purposes of this Section 18, the following definitions shall apply: (i) The term "Offer" shall mean any tender offer or exchange offer for thirty percent (30%) or more of the outstanding Common Stock of the Parent, other than one made by the Parent; provided that the corporation, person or other entity making the Offer acquires at least five percent (5%) of such Common Stock pursuant to such Offer. 17 (ii) The term "Offer Price Per Share" shall mean the highest price per Share paid in any Offer which is in effect at any time during the period beginning on the sixtieth (60th) day prior to the date on which a Limited SAR is exercised and ending on the date on which the Limited SAR is exercised. Any securities or properties which are a part or all of the consideration paid or to be paid for Common Stock in the Offer shall be valued in determining the Offer Price Per Share at the higher of (1) the valuation placed on such securities or properties by the person making such Offer, or (2) the valuation placed on such securities or properties by the Administrator. (iii) The term "Limited SAR" shall mean a right granted under this Plan with respect to a Related Option or Related Performance Award, that shall entitle the Holder to an amount in cash equal to the Offer Spread in the event an Offer is made. (iv) The term "Offer Spread" shall mean, with respect to each Limited SAR, an amount equal to the product of (1) the excess of (A) the Offer Price Per Share immediately preceding the date of exercise over (B) (x) if the Limited SAR is granted in tandem with an Option, then the Option Price per Share of the Related Option, or (y) if the Limited SAR is issued with respect to a Performance Award, the Agreed Price under the Related Performance Award, multiplied by (2) the number of Reserved Shares with respect to which such Limited SAR is being exercised; provided, however that with respect to any Limited SAR granted in tandem with an Incentive Stock Option, in no event shall the Offer Spread exceed the amount permitted to be treated as the Offer Spread under applicable Treasury Regulations or other legal authority without disqualifying the Option as an Incentive Stock Option. (v) The term "SAR" shall mean a right granted under this Plan, including, without limitation, a right granted in tandem with an Award, that shall entitle the Holder thereof to an amount equal to the SAR Spread payable as described in Section 18(d). (vi) The term "SAR Spread" shall mean with respect to each SAR an amount equal to the product of (1) the excess of (A) the Fair Market Value per Share on the date of exercise, over (B) (x) if the SAR is granted in tandem with an Option, then the Option Price per Reserved Share of the Related Option, (y) if the SAR is granted in tandem with a Performance Award, the Agreed Price under the Related Performance Award, or (z) if the SAR is granted by itself with respect to a designated number of Reserved Shares, the Agreed Price which, without limitation, is the Fair Market Value of the Reserved Shares on the Date of Grant, in each case multiplied by (2) the number of Reserved Shares with respect to which such SAR is being exercised; provided, however, without limitation, that with respect to any SAR granted in tandem with an Incentive Stock Option, in no event shall the SAR Spread exceed the amount permitted to be treated as the SAR 18 Spread under applicable Treasury Regulations or other legal authority without disqualifying the Option as an Incentive Stock Option. (c) To exercise the SAR or Limited SAR, the Holder shall: (i) Give written notice thereof to the Company, specifying the SAR or Limited SAR being exercised and the number or Reserved Shares with respect to which such SAR or Limited SAR is being exercised, and (ii) If requested by the Company, deliver within a reasonable time the agreement evidencing the SAR or Limited SAR being exercised and, if applicable, the Related Option agreement, or Related Performance Award agreement, to the Secretary of the Company who shall endorse or cause to be endorsed thereon a notation of such exercise and return all agreements to the Holder. (d) As soon as practicable after the exercise of a SAR or Limited SAR, the Company shall transfer to the Holder Reserved Shares having a Fair Market Value on the date the SAR or Limited SAR is exercised equal to either the SAR Spread, or the Offer Spread, as the case may be; provided, however, without limiting the generality of Section 15, that the Company, in its sole discretion, may withhold from such transferred Reserved Shares any amount necessary to satisfy the Company's minimum obligation for federal and state withholding taxes with respect to such exercise. (e) A SAR or Limited SAR may be exercised only if and to the extent that it is permitted under the terms of the Award which, in the case of a Related Option, shall be only when such Related Option is eligible to be exercised; provided, however, a Limited SAR may be exercised only during the period beginning on the first day following the date of expiration of the Offer and ending on the thirtieth (30th) day following such date. (f) Upon the exercise or termination of a Related Option, or the payment or termination of a Related Performance Award, the SAR or Limited SAR with respect to such Related Option or Related Performance Award likewise shall terminate. (g) A SAR or Limited SAR shall be transferable (i) only to the extent, if any, provided in the agreement evidencing the SAR, or (ii) if granted with respect to a Related Option, or Related Performance Award, only to the extent, if any, that such Related Option, or Related Performance Award, is transferable, and under the same conditions. (h) Each SAR or Limited SAR shall be on such terms and conditions not inconsistent with this Plan as the Committee may determine. (i) The Holder shall have no rights as a stockholder with respect to the related Reserved Shares as a result of the grant of a SAR or Limited SAR. 19 (j) With respect to a Holder who, on the date of a proposed exercise of a SAR or Limited SAR, is an officer (as that term is used in Rule 16a-1 promulgated under the 1934 Act or any similar rule which may subsequently be in effect), such proposed exercise may only occur as permitted by Rule 16b-3, including without limitation paragraph (e)(3)(iii) (or any similar rule which may subsequently be in effect promulgated pursuant to Section 16(b) of the 1934 Act). 19. Section 83(b) Election. If as a result of receiving an Award, a Holder receives Restricted Shares, then such Holder may elect under Section 83(b) of the Code to include in his or her gross income, for his or her taxable year in which the Restricted Shares are transferred to such Holder, the excess of the Fair Market Value (determined without regard to any Restriction other than one which by its terms will never lapse), of such Restricted Shares at the Date of Grant, over the amount (if any) paid for the Restricted Shares. If the Holder makes the Section 83(b) election described above, the Holder shall (i) make such election in a manner that is satisfactory to the Administrator, (ii) provide the Administrator with a copy of such election, (iii) agree to promptly notify the Company if any Internal Revenue Service or state tax agent, on audit or otherwise, questions the validity or correctness of such election or of the amount of income reportable on account of such election, and (iv) agree to pay the withholding amounts described in Section 15. 20. Vesting of Awards Upon Retirement. Unless otherwise expressly provided in the Award or in the Plan, the unvested portion of each Award granted to a Holder in the form of Option Shares, SARs, Limited SARs or Restricted Shares and owned by that HOlder on the date of that Holder's Separation will vest 100% on the date of that Holder's Separation if, and only if, such Separation occurs on or after the date that Holder attains their Retirement Vesting Date. 21. Interpretation. (a) If any provision of the Plan is held invalid for any reason, such holding shall not affect the remaining provisions hereof, but instead the Plan shall be construed and enforced as if such provision had never been included in the Plan. (b) THIS PLAN SHALL BE GOVERNED BY THE LAWS OF THE STATE OF DELAWARE. (c) Headings contained in this Agreement are for convenience only and shall in no manner be construed as part of this Plan. (d) Any reference to the masculine, feminine, or neuter gender shall be a reference to such other gender as is appropriate. 20 (e) Nothing contained in this Plan shall prevent the Board from adopting other or additional compensation arrangements, subject to shareholder approval if such approval is required; and such arrangements may be either generally applicable or applicable only in specific cases. 22. Amendment and Discontinuation of the Plan. The Board, or the Committee (subject to the prior written authorization of the Board), may from time to time amend the Plan or any Award; provided, however, that (except to the extent provided in Section 9(b)) no such amendment may, without approval by the shareholders of the Parent, (a) increase the number of Reserved Shares or change the class of Eligible Persons, (b) permit the granting of Awards which expire beyond the maximum 10-year period described in Section 9(a)(5), or (c) make any change for which applicable law or regulatory authority (including the regulatory authority of the NYSE or any other market or exchange on which the Common Stock is traded) would require shareholder approval or for which shareholder approval would be required under Section 162(m) of the Code to secure complete deductibility of all compensation paid as a result of Awards; and provided, further, that no amendment or suspension of the Plan or any Award issued hereunder shall, except as specifically permitted in this Plan or under the terms of such Award, substantially impair any Award previously granted to any Holder without the consent of such Holder. 23. Effective Date and Termination Date. The Plan shall be effective as of its Effective Date, and shall terminate on the tenth anniversary of such Effective Date; provided, further, without limitation, that unless otherwise expressly provided in an Award, the termination of the Plan shall not terminate an Award which is outstanding on such date. DENBURY RESOURCES INC. By______________________________ 21 EX-10 13 fy2004-exhibit10k.txt EXHIBIT 10(K), FORM OF RESTRICTED STOCK AWARD Exhibit 10(k) Form of Vesting Restricted Stock Award to Officers ___________________ Shares Date of Grant: ___________ RESTRICTED STOCK AWARD YEARLY VESTING AWARDS 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. RESTRICTED STOCK AWARD ("Award") made effective August 6, 2004 ("Date of Grant") between Denbury Resources Inc. (the "Company") and __________________ ("Holder"). WHEREAS, the Company desires to grant to the Holder _____________________ Restricted Shares under and for the purposes of the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (the "Plan"); WHEREAS, in accordance with the provisions of Section 16(d) of the Plan, the Restricted Shares (together with a stock power (set forth below)), will be delivered to the Company, to be held in escrow by the Company for the benefit of Holder until such time as such Restricted Shares are Vested by reason of the lapse of the applicable Restrictions, after which time the Company shall make delivery of the Vested Shares (but not Retained Vested Shares, as described in Section 5) to Holder; and WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award. NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows: 1. Restricted Share Award. The Company hereby sells, transfers, assigns and delivers to the Holder an aggregate of _________________ Restricted Shares ("Award Restricted Shares") on the terms and conditions set forth in the Plan and supplemented in this Award, including, without limitation, the restrictions more specifically set forth in Section 2 below, subject only to Holder's execution of this Award agreement. 2. Vesting of Award Restricted Shares. The Restrictions on the Award Restricted Shares shall lapse (Award Restricted Shares with respect to which Restrictions have lapsed being herein referred to as "Vested Shares") with respect to 20% of the Award Restricted Shares on the First Anniversary of the Date of Grant, and Restrictions with respect to an additional 20% of Award Restricted Shares shall lapse on each subsequent Anniversary of the Date of Grant, so that, without A-1 limitation, Restrictions on all of the Award Restricted Shares will have lapsed no later than the Fifth Anniversary of the Date of Grant. Without limiting the generality of the foregoing, in the event that, prior to lapse of Restrictions with respect to all Award Restricted Shares, either (i) Holder incurs a Separation by reason of Holder's death, or Disability, or (ii) there is a Change in Control, or (iii) without limiting the generality of Section 2(h)(5) of the Plan, Holder incurs a Separation for any reason other than Cause after the Commencement of a Change in Control, then the Restrictions on all remaining Award Restricted Shares shall lapse and all such Award Restricted Shares shall become Vested Shares, as of the date of such death, disability, Change in Control, or Change in Control following a Separation after the Commencement of a Change in Control. For all purposes of this Award, the term "Commencement of a Change in Control" shall mean any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, taken by a "person" (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a "group" (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after such material action, lead to a Change in Control as defined in Section 2(h)(2), (3) or (4) of the Plan involving such person, group, or their affiliates. 3. Restrictions - Forfeiture of Award Restricted Shares. The Award Restricted Shares are subject to the Restriction that all rights of Holder to any Award Restricted Shares which have not become Vested Shares, or do not become Vested Shares as a result of Holder's Separation after the Commencement of a Change in Control, automatically and without notice, shall terminate and be permanently forfeited on the date of Holder's Separation. 4. Withholding. On the date Award Restricted Shares become Vested Shares, the minimum withholding required to be made by the Company shall be paid by Holder to the Administrator in cash, or by delivery of Shares, which Shares may be in whole or in part Vested Shares, based on the Fair Market Value of such Shares on the date of delivery. The Holder, in his sole discretion, may direct that the Company withhold at any rate which is in excess of the minimum withholding rate described in the preceding sentence, but not in excess of the highest incremental tax rate for Holder, and such additional directed withholding will be made in the same manner as described in the preceding sentence except that no portion of such additional directed withholding may be paid in Shares which have not Vested, or which have not been purchased and held by Holder for, at least six (6) months prior to the date of delivery. 5. Issuance of Shares. Without limitation, Holder shall have all of the rights and privileges of an owner of the Award Restricted Shares (including voting rights) except that Holder shall not be entitled to delivery of the certificates evidencing any of the Shares unless and until they become Vested Shares, nor shall Holder be entitled to receive Restricted Share Distributions (i.e. dividends) unless and until Holder is entitled either (i) to receive the certificates for the related Vested Shares, or (ii) such Award Restricted Shares become Retained Vested Shares, as defined below. Notwithstanding the foregoing, on the date Award Restricted Shares become Vested Shares, the Administrator shall deliver to the Holder two-thirds (66 2/3%) of such Vested Shares (reduced A-2 by the number of Vested Shares delivered to the Administrator to pay required withholding under Section 4 above), and shall retain the other one-third (33 1/3%) of the Vested Shares ("Retained Vested Shares") in escrow until the date of Holder's Separation, and immediately after such Separation shall deliver all such Retained Vested Shares to Holder. During the period in which the Company holds the Retained Vested Shares, Holder is entitled to receive what would be Restricted Share Distributions if Holder was in possession of such Retained Vested Shares, except Holder shall not be entitled to receive a Restricted Share Distribution made in the form of Shares, but rather such Shares will be retained by the Company as additional Retained Vested Shares. 6. No Transfers Permitted. The rights under this Award are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Vested Shares. 7. No Right To Continued Employment. Neither the Plan nor this Award shall confer upon the Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall they interfere in any way with Holder's right to terminate employment, or the Company's right to terminate Holder's employment, at any time. 8. Governing Law. WITHOUT LIMITATION, THIS AWARD SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. 9. Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto. 10. Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law. IN WITNESS WHEREOF, the Company has caused these presents to be executed on its behalf and its corporate seal to be affixed hereto by its duly authorized representative and the Holder has hereunto set his or her hand and seal, all on the day and year first above written. Dated as of this 6th day of August, 2004. DENBURY RESOURCES INC. By: _______________________________ Gareth Roberts President and CEO By: _______________________________ Phil Rykhoek Sr. VP, CFO and Secretary A-3 Assignment Separate From Certificate FOR VALUE RECEIVED, the undersigned hereby sells, assigns and transfers unto Denbury Resources Inc. the _______________ Shares subject to this Award, standing in the undersigned's name on the books of said Denbury Resources Inc., represented by Certificate No. _____herewith and do hereby irrevocably constitute and appoint the corporate secretary of Denbury Resources Inc. as attorney to transfer the said stock on the books of Denbury Resources Inc. with full power of substitution in the premises. Dated ____________________ ------------------------------ ______________________ - Holder ACKNOWLEDGMENT The undersigned hereby acknowledges (i) my receipt of this Award, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Award with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Award and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Award and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Administrator upon any questions arising under the Plan, or this Award, or both. Dated as of this ________ day of ______________, 200__. ------------------------------ ___________________ - Holder A-4 EX-10 14 fy2004-exhibit10l.txt EXHIBIT 10(L), FORM OF RESTRICTED STOCK AWARD Exhibit 10(l) Form of Restricted Stock Award that Vests on Retirement Granted to Officers __________________ Shares Date of Grant___________ RESTRICTED STOCK AWARD RETIREMENT AWARDS 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. RESTRICTED STOCK AWARD ("Award") made effective August 6, 2004 ("Date of Grant") between Denbury Resources Inc. (the "Company") and ____________________ ("Holder"). WHEREAS, the Company desires to grant to the Holder ____________________ Restricted Shares under and for the purposes of the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (the "Plan"); WHEREAS, in accordance with the provisions of Section 16(d) of the Plan, the Restricted Shares (together with a stock power (set forth below)), will be delivered to the Company, to be held in escrow by the Company for the benefit of Holder until such time as such Restricted Shares are Vested by reason of the lapse of the applicable Restrictions, after which time the Company shall make delivery of the Vested Shares to Holder; and WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award. NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows: 1. Restricted Share Award. The Company hereby sells, transfers, assigns and delivers to the Holder an aggregate of ______________________ Restricted Shares ("Award Restricted Shares") on the terms and conditions set forth in the Plan and supplemented in this Award, including, without limitation, the restrictions more specifically set forth in Section 2 below, subject only to Holder's execution of this Award agreement. 2. Vesting of Award Restricted Shares. The Restrictions on the Award Restricted Shares shall lapse (Award Restricted Shares with respect to which Restrictions have lapsed being herein referred to as "Vested Shares") with respect to 100% of the Award Restricted Shares upon the later of (i) the Holder's attainment of his "Retirement Vesting Date" and (ii) the date of the Holder's Separation. The Holder's "Retirement Vesting Date" shall be the first birthday of the Holder on which Holder has attained the later of (i) his 60th birthday, and (ii) the A-1 birthday on which Holder attains an age equal to (x) 65 minus (y) the number which results from multiplying (A) fifty percent (50%) times (B) the Holder's full years of service as an Employee on such birthday, with such product of (A) and (B) rounded down to the nearest whole number before being deducted from 65. For example only, and without limiting the generality of the foregoing, a Holder who has completed 70 months of service (i.e., 5 full years of service) as an Employee on his 62nd birthday will not have attained his Retirement Vesting Date, whereas a Holder who has completed 72 months of service (i.e., 6 full years of service) as an Employee on his 62nd birthday will have attained his Retirement Vesting Date. Without limiting the generality of the foregoing, in the event that, prior to lapse of Restrictions with respect to all Award Restricted Shares, either (i) Holder incurs a Separation by reason of Holder's death, or Disability, or (ii) there is a Change in Control, or (iii) without limiting the generality of Section 2(h)(5) of the Plan, Holder incurs a Separation for any reason other than Cause after the Commencement of a Change in Control, then the Restrictions on all remaining Award Restricted Shares shall lapse and all such Award Restricted Shares shall become Vested Shares, as of the date of such death, disability, Change in Control, or Change in Control following a Separation after the Commencement of a Change in Control. For all purposes of this Award, the term "Commencement of a Change in Control" shall mean any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, taken by a "person" (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a "group" (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after such material action, lead to a Change in Control as defined in Section 2(h)(2), (3) or (4) of the Plan involving such person, group, or their affiliates. 3. Restrictions - Forfeiture of Award Restricted Shares. The Award Restricted Shares are subject to the Restriction that all rights of Holder to any Award Restricted Shares which have not become Vested Shares, or do not become Vested Shares as a result of Holder's Separation after the Commencement of a Change in Control, automatically and without notice, shall terminate and be permanently forfeited on the date of Holder's Separation. 4. Withholding. On the date Award Restricted Shares become Vested Shares, the minimum withholding required to be made by the Company shall be paid by Holder to the Administrator in cash, or by delivery of Shares, which Shares may be in whole or in part Vested Shares, based on the Fair Market Value of such Shares on the date of delivery. The Holder, in his sole discretion, may direct that the Company withhold at any rate which is in excess of the minimum withholding rate described in the preceding sentence, but not in excess of the highest incremental tax rate for Holder, and such additional directed withholding will be made in the same manner as described in the preceding sentence except that no portion of such additional directed withholding may be paid in Shares which have not Vested, or which have not been purchased and held by Holder for, at least six (6) months prior to the date of delivery. A-2 5. Issuance of Shares. Without limitation, Holder shall have all of the rights and privileges of an owner of the Award Restricted Shares (including voting rights) except that Holder shall not be entitled to delivery of the certificates evidencing any of the Shares unless and until they become Vested Shares, nor shall Holder be entitled to receive Restricted Share Distributions (i.e. dividends) unless and until Holder is entitled either (i) to receive the certificates for the related Vested Shares, or (ii) such Award Restricted Shares become Retained Vested Shares, as defined below. Notwithstanding the foregoing, on the date Award Restricted Shares become Vested Shares, the Administrator shall deliver to the Holder such Vested Shares, reduced by the number of Vested Shares delivered to the Administrator to pay required withholding under Section 4 above. 6. No Transfers Permitted. The rights under this Award are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Vested Shares. 7. No Right To Continued Employment. Neither the Plan nor this Award shall confer upon the Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall they interfere in any way with Holder's right to terminate employment, or the Company's right to terminate Holder's employment, at any time. 8. Governing Law. WITHOUT LIMITATION, THIS AWARD SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. 9. Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto. 10. Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law. IN WITNESS WHEREOF, the Company has caused these presents to be executed on its behalf and its corporate seal to be affixed hereto by its duly authorized representative and the Holder has hereunto set his or her hand and seal, all on the day and year first above written. Dated as of this 6th day of August, 2004. DENBURY RESOURCES INC. By: _______________________________ Gareth Roberts President and CEO By: _______________________________ Phil Rykhoek Sr. VP, CFO and Secretary A-3 Assignment Separate From Certificate FOR VALUE RECEIVED, the undersigned hereby sells, assigns and transfers unto Denbury Resources Inc. the _____________ Shares subject to this Award, standing in the undersigned's name on the books of said Denbury Resources Inc., represented by Certificate No. _____herewith and do hereby irrevocably constitute and appoint the corporate secretary of Denbury Resources Inc. as attorney to transfer the said stock on the books of Denbury Resources Inc. with full power of substitution in the premises. Dated ____________________ ------------------------------ ___________________ -Holder ACKNOWLEDGMENT The undersigned hereby acknowledges (i) my receipt of this Award, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Award with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Award and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Award and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Administrator upon any questions arising under the Plan, or this Award, or both. Dated as of this ________ day of ______________, 200__. ------------------------------ _____________________ - Holder A-4 EX-10 15 fy2004-exhibit10m.txt EXHIBIT 10(M), FORM OF RESTRICTED STOCK AWARD Exhibit 10(m) Form of Restricted Stock Award to Directors ___________ Shares Date of Grant: _____________ RESTRICTED STOCK AWARD YEARLY VESTING AWARDS 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. RESTRICTED STOCK AWARD ("Award") made effective _________________ ("Date of Grant") between Denbury Resources Inc. (the "Company") and ____________________ ("Holder"). WHEREAS, the Company desires to grant to the Holder ________________ Restricted Shares under and for the purposes of the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (the "Plan"); WHEREAS, in accordance with the provisions of Section 16(d) of the Plan, the Restricted Shares (together with a stock power (set forth below)), will be delivered to the Company, to be held in escrow by the Company for the benefit of Holder until such time as such Restricted Shares are Vested by reason of the lapse of the applicable Restrictions, after which time the Company shall make delivery of the Vested Shares (but not Retained Vested Shares, as described in Section 5) to Holder; and WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award. NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows: 1. Restricted Share Award. The Company hereby sells, transfers, assigns and delivers to the Holder an aggregate of ____________ Restricted Shares ("Award Restricted Shares") on the terms and conditions set forth in the Plan and supplemented in this Award, including, without limitation, the restrictions more specifically set forth in Section 2 below, subject only to Holder's execution of this Award agreement. 2. Vesting of Award Restricted Shares. The Restrictions on the Award Restricted Shares shall lapse (Award Restricted Shares with respect to which Restrictions have lapsed being herein referred to as "Vested Shares") with respect to 20% of the Award Restricted Shares on the First Anniversary of the Date of Grant, and A-1 Restrictions with respect to an additional 20% of Award Restricted Shares shall lapse on each subsequent Anniversary of the Date of Grant, so that, without limitation, Restrictions on all of the Award Restricted Shares will have lapsed no later than the Fifth Anniversary of the Date of Grant. Without limiting the generality of the foregoing, in the event that, prior to lapse of Restrictions with respect to all Award Restricted Shares, either (i) Holder incurs a Separation (as defined below) by reason of Holder's death, or Disability, or (ii) there is a Change in Control as to which the Company or its shareholders have received a favorable fairness opinion from an independent third party investment bank or similar firm, or (iii) there is an unsolicited hostile take-over of the Company, or (iv) without limiting the generality of Section 2(h)(5) of the Plan, Holder incurs a Separation (as defined below) for any reason other than Cause after the Commencement of a Change in Control as to which the Company or its shareholders have received a favorable fairness opinion from an independent third party investment bank or similar firm or as a result of an unsolicited hostile take-over, then the Restrictions on all remaining Award Restricted Shares shall lapse and all such Award Restricted Shares shall become Vested Shares, as of the date of such death, disability, Change in Control, or Change in Control following a Separation after the Commencement of such Change in Control. For all purposes of this Award, the term "Commencement of a Change in Control" shall mean any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, taken by a "person" (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a "group" (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after such material action, lead to a Change in Control as defined in Section 2(h)(2), (3) or (4) of the Plan involving such person, group, or their affiliates. Without limitation, for all purposes of this Award, the term "Separation" shall mean in the case of a non-employee Director, upon his or her ceasing to be a Director. The definition of "Separation" for a non-employee Director shall automatically be amended by any changes to, and shall be identical to, the definition of "Separation" for non-employee Directors in the Company's 2004 Omnibus Stock and Incentive Plan, as that portion of such definition may be amended in that Plan from time to time. 3. Restrictions - Forfeiture of Award Restricted Shares. The Award Restricted Shares are subject to the Restriction that all rights of Holder to any Award Restricted Shares which have not become Vested Shares, or do not become Vested Shares as a result of Holder's Separation after the Commencement of a Change in Control, automatically and without notice, shall terminate and be permanently forfeited on the date of Holder's Separation. 4. Withholding. No tax withholding is required for a non-employee director. 5. Issuance of Shares. Without limitation, Holder shall have all of the rights and privileges of an owner of the Award Restricted Shares (including voting rights) except that Holder shall not be entitled to delivery of the certificates evidencing any of the Shares unless and until they become Vested Shares, nor shall Holder be entitled to receive Restricted Share Distributions (i.e. dividends) unless and until Holder is entitled either (i) to receive the certificates for the related Vested Shares, or (ii) such Award Restricted Shares A-2 become Retained Vested Shares, as defined below. Notwithstanding the foregoing, on the date Award Restricted Shares become Vested Shares, the Administrator shall retain sixty percent (60%) of the Vested Shares ("Retained Vested Shares") in escrow until the date of Holder's Separation, and immediately after such Separation shall deliver all such Retained Vested Shares to Holder. During the period in which the Company holds the Retained Vested Shares, Holder is entitled to receive what would be Restricted Share Distributions if Holder was in possession of such Retained Vested Shares, except Holder shall not be entitled to receive a Restricted Share Distribution made in the form of Shares, but rather such Shares will be retained by the Company as additional Retained Vested Shares. 6. No Transfers Permitted. The rights under this Award are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Vested Shares. 7. No Right To Continued Employment. Neither the Plan nor this Award shall confer upon the Holder any right to provide services as a director to the Company, nor shall they interfere in any way with Holder's right to terminate their services as a director. 8. Governing Law. WITHOUT LIMITATION, THIS AWARD SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. 9. Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto. 10. Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law. IN WITNESS WHEREOF, the Company has caused these presents to be executed on its behalf and its corporate seal to be affixed hereto by its duly authorized representative and the Holder has hereunto set his or her hand and seal, all on the day and year first above written. Dated as of this _______day of _________________, 2004. DENBURY RESOURCES INC. By: ________________________ __________________________ Gareth Roberts Phil Rykhoek President and CEO Senior VP, CFO and Secretary A-3 Assignment Separate From Certificate FOR VALUE RECEIVED, the undersigned hereby sells, assigns and transfers unto Denbury Resources Inc. the _______________ Shares subject to this Award, standing in the undersigned's name on the books of said Denbury Resources Inc., represented by Certificate No. _____herewith and do hereby irrevocably constitute and appoint the corporate secretary of Denbury Resources Inc. as attorney to transfer the said stock on the books of Denbury Resources Inc. with full power of substitution in the premises. Dated ____________________ ------------------------------ Holder ACKNOWLEDGMENT The undersigned hereby acknowledges (i) my receipt of this Award, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Award with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Award and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Award and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Administrator upon any questions arising under the Plan, or this Award, or both. Dated as of this ________ day of ______________, 200__. ------------------------------ Holder A-4 EX-10 16 fy2004-exhibit10o.txt EXHIBIT 10(O), ANNUAL STOCK OPTION AGREEMENT Exhibit 10(o) Form of Incentive Stock Option Agreement that Cliff Vests No. Shares:___________ Date of Grant:____________ ANNUAL INCENTIVE STOCK OPTION AGREEMENT 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. An Annual Incentive Stock Option (the "Option") for a total of __________ shares (collectively, "Option Shares") of Denbury Resources Inc.(the "Company"), is hereby granted to _______________________ (the "Optionee") on _______________ ("Date of Grant") at the Option Price determined in this Option and in all respects subject to the terms, definitions and provisions, of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (the "Plan"), which is incorporated herein by reference except to the extent otherwise expressly provided in this Option. 1. Option Price. The Option Price is __________________ for each Share, which price is the Fair Market Value of a Share on the Date of Grant. 2. Vesting of Option Shares. The Option Shares shall remain 100% forfeitable, until the fourth (4th) anniversary of the Date of Grant, and on such fourth (4th) anniversary of the Date of Grant, this Option shall become 100% Vested, and all Option Shares subject to this Option shall become "Vested Option Shares". Without limiting the generality of the forgoing, in the event that, prior to the fourth (4th) anniversary of the Date of Grant, either (i) Optionee incurs a Separation by reason of Optionee's death, or Disability, or (ii) there is a Change in Control, then all of the Option Shares which have not previously become Vested Option Shares shall become Vested Option Shares as of the date of such death, disability or Change in Control. 3. Exercisability of Option. This Option shall not be exercisable prior to the first date on which Option Shares become Vested Option Shares, and thereafter (and prior to the termination of this Option), this Option shall be exercisable, in whole or in part, with respect to Vested Option Shares. (a) Method of Exercise. Without limitation, this Option shall be exercised by a written notice delivered to the Administrator which shall: (i) state the election to exercise the Option and the number of Vested Option Shares in respect of which it is being exercised; and (ii) be signed by the person or persons entitled to exercise the Option and, if the Option is being exercised by any person or persons other 1 than the Optionee, be accompanied by proof, satisfactory to the Administrator, of the rights of such person or persons to exercise the Option. (b) Payment. The Option Price of any Vested Option Shares purchased shall be paid by the Optionee to the Administrator in cash, or by the delivery of Shares held by Optionee for at least 6 months (which period may, in the sole discretion of the Administrator, be increased to the extent the Administrator deems necessary in order to avoid a charge to the Company's earnings), or both. To the extent Shares are used in payment of the Option Price, the value of such Shares shall be their Fair Market Value on the date of delivery to the Administrator. (c) Issuance of Shares. No person shall be, or have any of the rights or privileges of, a holder of the Shares subject to this Option unless and until certificates representing such Shares shall have been issued and delivered to such person, such issuance, without limitation, being subject to the terms of the Plan. (d) Surrender of Option. Upon exercise of this Option in part, if requested by the Administrator, the Optionee shall deliver this Option and other written agreements executed by the Company and the Optionee with respect to this Option to the Administrator who shall endorse or cause to be endorsed thereon a notation of such exercise and return all agreements to the Optionee. 4. Term of Option. Without limitation, the unexercised portion of this Option shall automatically terminate at the time of the earliest to occur of the following: (i) on the 90th day following Optionee's Separation for any reason except death, Disability or for Cause; or (ii) immediately upon Optionee's Separation as a result, in whole or in material part, of a discharge for Cause; or (iii) on the first anniversary of a Optionee's Separation by reason of death or Disability; (iv) if you are a 10% Person, on the fifth (5th ) anniversary of the Date of Grant; or (v) on the tenth (10th) anniversary of the Date of Grant. 5. No Transfers Permitted. The rights under this Option are not transferable by the Optionee otherwise than by will or the laws of descent and distribution, and so long as Optionee lives, only Optionee or his or her guardian or legal representative shall have the right to exercise this Option. 6. No Right To Continued Employment. Neither the Plan nor this Option shall confer upon the Optionee any right with respect to continuation of employment by 2 the Company, or any right to provide services to the Company, nor shall it interfere in any way Optionee's right to terminate employment, nor the Company's right to terminate Optionee's employment, at any time. 7. Law Governing. WITHOUT LIMITATION, THIS OPTION SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. Dated as of this _____ day of__________, 2005. DENBURY RESOURCES INC. Per:____________________________ Gareth Roberts, President Per:____________________________ Phil Rykhoek, Sr. Vice President & C.F.O. Acknowledgment The undersigned hereby acknowledges (i) my receipt of this Option, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Option with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Option and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Option and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Option, or both) of the Administrator upon any questions arising under the Plan, or this Option, or both. Dated as of this ________ day of ______________, 200__. ________________________________ Optionee Name 3 EX-10 17 fy2004-exhibit10n.txt EXHIBIT 10(N), INCENTIVE STOCK OPTION AGREEMENT Exhibit 10(n) Form of Incentive Stock Option Agreement that Vests 25% per Annum No. Shares: ____________ Date of Grant: ___________ INCENTIVE STOCK OPTION AGREEMENT 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. An Incentive Stock Option (the "Option") for a total of _________________ Shares (collectively, "Option Shares") of Denbury Resources Inc.(the "Company"), is hereby granted to ________________ (the "Optionee") on _______________ ("Date of Grant") at the Option Price determined in this Option and in all respects subject to the terms, definitions and provisions, of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (the "Plan"), which is incorporated herein by reference except to the extent otherwise expressly provided in this Option. 1. Option Price. The Option Price is _______________________ for each Share, which price is the Fair Market Value of a Share on the Date of Grant. 2. Vesting of Option Shares. The Option Shares shall Vest and become Vested Option Shares in accordance with the dates set forth in the following Vesting Schedule: (i) 25% of the Option Shares on the first anniversary of the Date of Grant, (ii) 25% of the Option Shares on the second anniversary of the Date of Grant; (iii) 25% of the Option Shares on the third anniversary of the Date of Grant; and (iv) 25% of the Option Shares on the fourth anniversary of the Date of Grant. Without limiting the generality of the forgoing, in the event that, prior to the fourth (4th) anniversary of the Date of Grant, either (i) Optionee incurs a Separation by reason of Optionee's death, or Disability, or (ii) there is a Change in Control, then all of the Option Shares which have not previously become Vested Option Shares shall become Vested Option Shares as of the date of such death, Disability or Change in Control. 3. Exercisability of Option. This Option shall not be exercisable prior to the first date on which Shares become Vested, and thereafter (and prior to the 1 termination of this Option), this Option shall be exercisable, in whole or in part, with respect to Vested Option Shares. (a) Method of Exercise. Without limitation, this Option shall be exercised by a written notice delivered to the Administrator which shall: (i) state the election to exercise the Option and the number of Vested Option Shares in respect of which it is being exercised; and (ii) be signed by the person or persons entitled to exercise the Option and, if the Option is being exercised by any person or persons other than the Optionee, be accompanied by proof, satisfactory to the Administrator, of the rights of such person or persons to exercise the Option. (b) Payment. The Option Price of any Vested Option Shares purchased shall be paid by the Optionee to the Administrator in cash, or by the delivery of Shares held by Optionee for at least 6 months (which period may, in the sole discretion of the Administrator, be increased to the extent the Administrator deems necessary in order to avoid a charge to the Company's earnings), or both. To the extent Shares are used in payment of the Option Price, the value of such Shares shall be their Fair Market Value on the date of delivery to the Administrator. (c) Issuance of Shares. No person shall be, or have any of the rights or privileges of, a holder of the Shares subject to this Option unless and until certificates representing such Shares shall have been issued and delivered to such person, such issuance, without limitation, being subject to the terms of the Plan. (d) Surrender of Option. Upon exercise of this Option in part, if requested by the Administrator, the Optionee shall deliver this Option and other written agreements executed by the Company and the Optionee with respect to this Option to the Administrator who shall endorse or cause to be endorsed thereon a notation of such exercise and return all agreements to the Optionee. 4. Term of Option. Without limitation, the unexercised portion of this Option shall automatically terminate at the time of the earliest to occur of the following: (i) on the 90th day following Optionee's Separation for any reason except death, Disability or for Cause; or (ii) immediately upon Optionee's Separation as a result, in whole or in material part, of a discharge for Cause; or (iii) on the first anniversary of a Optionee's Separation by reason of death or Disability; (iv) if you are a 10% Person, on the fifth (5th ) anniversary of the Date of Grant; or 2 (v) on the tenth (10th) anniversary of the Date of Grant 5. No Transfers Permitted. The rights under this Option are not transferable by the Optionee otherwise than by will or the laws of descent and distribution, and so long as Optionee lives, only Optionee or his or her guardian or legal representative shall have the right to exercise this Option. 6. No Right To Continued Employment. Neither the Plan nor this Option shall confer upon the Optionee any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall it interfere in any way Optionee's right to terminate employment, nor the Company's right to terminate Optionee's employment, at any time. 7. Law Governing. WITHOUT LIMITATION, THIS OPTION SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. Dated as of this _______ day of ______________, 2005. DENBURY RESOURCES INC. Per:____________________________ Gareth Roberts, President Per:____________________________ Phil Rykhoek, Sr. V.P., C.F.O. and Secretary 3 Acknowledgment The undersigned hereby acknowledges (i) my receipt of this Option, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Option with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Option and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Option and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Option, or both) of the Administrator upon any questions arising under the Plan, or this Option, or both. Dated as of this ________ day of ______________, 200__. ________________________________ Optionee Name 4 EX-10 18 fy2004-exhibit10i.txt EXHIBIT 10(I), EMPLOYEE CASH BONUS COMPENSATION Exhibit 10(i) Description of Cash Bonus Compensation Arrangements for Employees and Officers Since 1995, we have had a practice of paying cash bonuses to all of our employees each year except in 1998, when no bonuses were paid to employees. There is no formal bonus plan, nor any written formulas for determining bonus amounts. Because whether or not bonuses will be paid and in what amounts is determined by the Compensation Committee of our Board of Directors on a Company-wide basis; executive officers receive bonuses only if all employees receive bonuses. Our bonus practices currently classify employees into four levels for bonus compensation purposes, whereby at the first level, which includes all employees, bonuses generally range from zero to ten percent of base salaries, although in the past bonuses paid at this and all other levels have been as high as twelve and one-half percent of base salary in an exceptionally good year. There is an additional compensation layer for all employees in the professional group (the second level), whereby these employees may receive an additional level of bonuses of up to ten percent of base salaries, for or a total bonus ranging from zero to twenty percent. In addition, certain members of the professional group that are part of management or have been exceptional performers during a year (the third level) are eligible to receive an additional level of bonuses of up to ten percent of base salaries, for a total bonus ranging from zero to thirty percent. Lastly, our officers and other senior management (the fourth level) are eligible to receive an additional level of bonuses of up to ten percent of base salaries, for a total bonus ranging from zero to forty percent. All of our executive officers are eligible for bonuses at all four levels. All bonuses are paid at the same percentage for each level (i.e. if level one is 10%, levels two, three and four are also 10%). Since this practice began in 1995, we have paid cash bonuses ranging from 0% to 50% of base salary to our executive officers, depending on the Company's results for that year, as determined by the Compensation Committee of our Board of Directors. In addition to the aforementioned bonus practice, we have usually paid a Christmas bonus each year that is equivalent to one week of each employee's base salary. Bonus determinations are made by the directors on our Compensation Committee subjectively, not based on arithmetic methods or formulas, generally based on our overall corporate results and whether or not the Company has achieved predetermined Company-wide goals and objectives. Any measure that might be considered to determine whether or not an oil and gas company had a good year (or other measures of success or failure) is a possible consideration by the Compensation Committee. These measures have historically included an evaluation of production levels, stock performance, achievement of acquisition or disposition goals, completion of significant transactions, completion of significant projects (such as software systems or significant construction projects), operating and administrative expense levels as compared to budget, capital expenditures as compared to budget, and the changes in our proved, probable and possible reserves for that period as compared to costs incurred. As the Compensation Committee's decisions are subjective evaluations made on an overall basis, it is not possible to determine how these measures are weighted or evaluated by the Compensation Committee. EX-10 19 fy2004-exhibit10p.txt EXHIBIT 10(P), NON-QUALIFIED STOCK OPTION Exhibit 10(p) Form of Non-qualified Stock Option Agreement that Vests 25% per Annum No. Shares: ____________ Date of Grant:____________ NON-QUALIFIED STOCK OPTION AGREEMENT 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. A Non-Qualified Stock Option (the "Option") for a total of __________________ Shares (collectively, "Option Shares") of Denbury Resources Inc.(the "Company"), is hereby granted to ___________________________ (the "Optionee") on __________________ ("Date of Grant") at the Option Price determined in this Option and in all respects subject to the terms, definitions and provisions, of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (the "Plan"), which is incorporated herein by reference except to the extent otherwise expressly provided in this Option. 1. Option Price. The Option Price is _____________________ for each Share, which price is the Fair Market Value of a Share on the Date of Grant. 2. Vesting of Option Shares. The Option Shares shall Vest and become Vested Option Shares in accordance with the dates set forth in the following Vesting Schedule: (i) 25% of the Option Shares on the first anniversary of the Date of Grant, (ii) 25% of the Option Shares on the second anniversary of the Date of Grant; (iii) 25% of the Option Shares on the third anniversary of the Date of Grant; and (iv) 25% of the Option Shares on the fourth anniversary of the Date of Grant. 1 Without limiting the generality of the forgoing, in the event that, prior to the fourth (4th) anniversary of the Date of Grant, either (i) Optionee incurs a Separation by reason of Optionee's death, or Disability, or (ii) there is a Change in Control, then all of the Option Shares which have not previously become Vested Option Shares shall become Vested Option Shares as of the date of such death, Disability or Change in Control. 3. Exercisability of Option. This Option shall not be exercisable prior to the first date on which Option Shares become Vested Option Shares, and thereafter (and prior to the termination of this Option), this Option shall be exercisable, in whole or in part, with respect to Vested Option Shares. (a) Method of Exercise. Without limitation, this Option shall be exercised by a written notice delivered to the Administrator which shall: (i) state the election to exercise the Option and the number of Vested Option Shares in respect of which it is being exercised; and (ii) be signed by the person or persons entitled to exercise the Option and, if the Option is being exercised by any person or persons other than the Optionee, be accompanied by proof, satisfactory to the Administrator, of the rights of such person or persons to exercise the Option. (b) Payment and Withholding. The Option Price of any Vested Option Shares purchased, and any withholding required by the Company, shall be paid by the Optionee to the Administrator in cash, or by the delivery of Shares held by Optionee for at least 6 months (which period may, in the sole discretion of the Administrator, be increased to the extent the Administrator deems necessary in order to avoid a charge to the Company's earnings), or both; provided, further, that the minimum amount of required withholding may be paid with Vested Option Shares acquired through the exercise of this Option. To the extent Shares are used in payment of the Option Price, or withholding, or both, the value of such Shares shall be their Fair Market Value on the date of delivery to the Administrator. (c) Issuance of Shares. No person shall be, or have any of the rights or privileges of, a holder of the Shares subject to this Option unless and until certificates representing such Shares shall have been issued and delivered to such person, such issuance, without limitation, being subject to the terms of the Plan. (d) Surrender of Option. Upon exercise of this Option in part, if requested by the Administrator, the Optionee shall deliver this Option and other written agreements executed by the Company and the Optionee with respect to this Option to the Administrator who shall endorse or cause to be endorsed thereon a notation of such exercise and return all agreements to the Optionee. 2 4. Term of Option. Without limitation, the unexercised portion of this Option shall automatically terminate at the time of the earliest to occur of the following: (i) on the 90th day following Optionee's Separation for any reason except death, Disability or for Cause; or (ii) immediately upon Optionee's Separation as a result, in whole or in material part, of a discharge for Cause; or (iii) on the first anniversary of a Optionee's Separation by reason of death or Disability; (iv) if you are a 10% Person, on the fifth (5th ) anniversary of the Date of Grant; or (v) on the tenth (10th) anniversary of the Date of Grant. 5. No Transfers Permitted. The rights under this Option are not transferable by the Optionee otherwise than by will or the laws of descent and distribution, and so long as Optionee lives, only Optionee or his or her guardian or legal representative shall have the right to exercise this Option. 6. No Right To Continued Employment. Neither the Plan nor this Option shall confer upon the Optionee any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall it interfere in any way Optionee's right to terminate employment, nor the Company's right to terminate Optionee's employment, at any time. 7. Law Governing. WITHOUT LIMITATION, THIS OPTION SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. Dated as of this ____ day of _________________, 2005. DENBURY RESOURCES INC. Per:____________________________ Gareth Roberts, President Per:____________________________ Phil Rykhoek, Sr. V.P., C.F.O. and Secretary 3 Acknowledgment The undersigned hereby acknowledges (i) my receipt of this Option, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Option with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Option and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Option and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Option, or both) of the Administrator upon any questions arising under the Plan, or this Option, or both. Dated as of this ________ day of ______________, 200__. ________________________________ Optionee Name 4 EX-10 20 fy2004-exhibit10q.txt EXHIBIT 10(Q), ANNUAL NONQUALIFIED STOCK OPTION Exhibit 10(q) Form of Non-qualified Stock Option Agreement that Cliff Vests No. Shares: ___________ Date of Grant: _______________ ANNUAL NONQUALIFIED STOCK OPTION AGREEMENT 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. An Annual Nonqualified Stock Option (the "Option") for a total of ______________ shares (collectively, "Option Shares") of Denbury Resources Inc.(the "Company"), is hereby granted to ___________________ (the "Optionee") on __________________ ("Date of Grant") at the Option Price determined in this Option and in all respects subject to the terms, definitions and provisions, of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (the "Plan"), which is incorporated herein by reference except to the extent otherwise expressly provided in this Option. 1. Option Price. The Option Price is _______________________ for each Share. 2. Vesting of Option Shares. The Option Shares shall remain 100% forfeitable, until the fourth (4th) anniversary of the Date of Grant, and on such fourth (4th) anniversary of the Date of Grant, this Option shall become 100% Vested, and all Option Shares subject to this Option shall become "Vested Option Shares". Without limiting the generality of the forgoing, in the event that, prior to the fourth (4th) anniversary of the Date of Grant, either (i) Optionee incurs a Separation by reason of Optionee's death, or Disability, or (ii) there is a Change in Control, then all of the Option Shares which have not previously become Vested Option Shares shall become Vested Option Shares as of the date of such death, disability or Change in Control 3. Exercisability of Option. This Option shall not be exercisable prior to the first date on which Option Shares become Vested Option Shares, and thereafter (and prior to the termination of this Option), this Option shall be exercisable, in whole or in part, with respect to Vested Option Shares. (a) Method of Exercise. Without limitation, this Option shall be exercised by a written notice delivered to the Administrator which shall: (i) state the election to exercise the Option and the number of Vested Option Shares in respect of which it is being exercised; and (ii) be signed by the person or persons entitled to exercise the Option and, if the Option is being exercised by any person or persons other than the Optionee, be accompanied by proof, satisfactory to the Administrator, of the rights of such person or persons to exercise the Option. 1 (b) Payment and Withholding. The Option Price of any Vested Option Shares purchased, and any withholding required by the Company, shall be paid by the Optionee to the Administrator in cash, or by the delivery of Shares held by Optionee for at least 6 months (which period may, in the sole discretion of the Administrator, be increased to the extent the Administrator deems necessary in order to avoid a charge to the Company's earnings), or both; provided, further, that the minimum amount of required withholding may be paid with Vested Option Shares acquired through the exercise of this Option. To the extent Shares are used in payment of the Option Price, or withholding, or both, the value of such Shares shall be their Fair Market Value on the date of delivery to the Administrator. (c) Issuance of Shares. No person shall be, or have any of the rights or privileges of, a holder of the Shares subject to this Option unless and until certificates representing such Shares shall have been issued and delivered to such person, such issuance, without limitation, being subject to the terms of the Plan. (d) Surrender of Option. Upon exercise of this Option in part, if requested by the Administrator, the Optionee shall deliver this Option and other written agreements executed by the Company and the Optionee with respect to this Option to the Administrator who shall endorse or cause to be endorsed thereon a notation of such exercise and return all agreements to the Optionee. 4. Term of Option. Without limitation, the unexercised portion of this Option shall automatically terminate at the time of the earliest to occur of the following: (i) on the 90th day following Optionee's Separation for any reason except death, Disability or for Cause; or (ii) immediately upon Optionee's Separation as a result, in whole or in material part, of a discharge for Cause; or (iii) on the first anniversary of a Optionee's Separation by reason of death or Disability; (iv) if you are a 10% Person, on the fifth (5th) anniversary of the Date of Grant; or (v) on the tenth (10th) anniversary of the Date of Grant. 5. No Transfers Permitted. The rights under this Option are not transferable by the Optionee otherwise than by will or the laws of descent and distribution, and so long as Optionee lives, only Optionee or his or her guardian or legal representative shall have the right to exercise this Option. 6. No Right To Continued Employment. Neither the Plan nor this Option shall confer upon the Optionee any right with respect to continuation of employment by 2 the Company, or any right to provide services to the Company, nor shall it interfere in any way Optionee's right to terminate employment, nor the Company's right to terminate Optionee's employment, at any time. 7. Law Governing. WITHOUT LIMITATION, THIS OPTION SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. Dated as of this ____ day of _________________, 2005. DENBURY RESOURCES INC. Per:____________________________ Gareth Roberts, President Per:____________________________ Phil Rykhoek, Sr. V.P., C.F.O. and Secretary Acknowledgment The undersigned hereby acknowledges (i) my receipt of this Option, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Option with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Option and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Option and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Option, or both) of the Administrator upon any questions arising under the Plan, or this Option, or both. Dated as of this ________ day of ______________, 200__. _________________________________ Optionee Name 3 EX-10 21 fy2004-exhibit10r.txt EXHIBIT 10(R), STOCK APPRECIATION RIGHTS AGRMNT. Exhibit 10(r) Form of Stock Appreciation Right that Vests 25% per Annum No. SARs [_________] Date of Grant [__________] STOCK APPRECIATION RIGHTS AGREEMENT 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. A total of _____ Stock Appreciation Rights (individually, and collectively, "SAR(s)") are hereby granted to ________ (the "Holder") on ________ ("Date of Grant") at the Grant Value determined in this SAR Agreement, and in all respects subject to the terms, definitions and provisions, of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (the "Plan"), which is incorporated herein by reference except to the extent otherwise expressly provided in this SAR Agreement. 1. Grant Value. The Grant Value is $_________ for each SAR, which value is equal to the Fair Market Value of a Share on the Date of Grant. 2. Vesting of SAR Agreement Shares. The SARs shall Vest and become "Vested SARs" in accordance with the following schedule: Percentage Becoming Vested Date on Which Percentage Vests - -------------------------- ------------------------------ 25% First Anniversary of Date of Grant 25% Second Anniversary of Date of Grant 25% Third Anniversary of Date of Grant 25% Fourth Anniversary of Date of Grant Without limiting the generality of the forgoing, in the event that, prior to the fourth (4th) anniversary of the Date of Grant, either (i) Holder incurs a Separation by reason of Holder's death, or Disability, or (ii) there is a Change in Control, then all of the SARs which have not previously become Vested SARs shall become Vested SARs as of the date of such death, disability or Change in Control. 3. Amount Payable, and Form of Payment, on Exercise of SAR. (a) Amount Payable on Exercise of SAR. Upon the Holder's exercise of a Vested SAR, the Holder shall be entitled to receive the SAR Spread, determined as of the date of exercise of the SAR Agreement, with respect to each SAR exercised on such date. The SAR Spread is the product of (i) the excess of the Fair Market Value of a Share on the date of exercise over the Grant Value, multiplied by (ii) the number of SARs exercised. A-1 (b) Form of Payment. Within a reasonable period following the exercise of a Vested SAR, the Holder will receive Shares having a Fair Market Value, as determined on the date of exercise of the Vested SAR, equal to the SAR Spread described in Section 3(a) above. Without limiting the generality of the foregoing, the Holder may choose to use a portion of such Shares to satisfy some or all of such Holder's withholding obligations under Section 4(b) of this SAR Agreement. 4. Exercise of SAR Agreement. This SAR Agreement shall not be exercisable prior to the first date on which a portion of the SARs become Vested SARs, and thereafter (and prior to the termination of this SAR Agreement), this SAR Agreement shall be exercisable, in whole or in part, with respect to Vested SARs. (a) Method of Exercise. Without limitation, this SAR Agreement shall be exercised by a written notice delivered to the Administrator which shall: (i) state the election to exercise the SAR Agreement and the number of Vested SARs in respect of which it is being exercised; and (ii) be signed by the person or persons entitled to exercise the SAR Agreement and, if the SAR Agreement is being exercised by any person or persons other than the Holder, be accompanied by proof, satisfactory to the Administrator, of the rights of such person or persons to exercise the SAR Agreement. (b) Withholding. Upon the exercise of the SAR, the minimum withholding required to be made by the Company shall be paid by the Holder to the Administrator in cash, or by the delivery of Shares, which Shares may be in whole or in part Shares acquired through the exercise of this SAR Agreement, based on the Fair Market Value of such Shares on the date of delivery. (c) Issuance of Shares. No person shall be, or have any of the rights or privileges of, a holder of the Shares which would be delivered as a result of the exercise of this SAR Agreement unless and until certificates representing such Shares shall have been issued and delivered to such person, such issuance, without limitation, being subject to the terms of the Plan. (d) Surrender of SAR Agreement. Upon exercise of this SAR Agreement in part, if requested by the Administrator, the Holder shall deliver this SAR Agreement and other written agreements (if any) executed by the Company and the Holder with respect to this SAR Agreement to the Administrator who shall endorse or cause to be endorsed thereon a notation of such exercise and return the SAR Agreement (and other agreements, if any) to the Holder. 5. Term of SAR Agreement. Without limitation, the unexercised portion of this SAR Agreement shall automatically and without notice terminate at the time of the earliest to occur of the following: (i) the 90th day following Holder's Separation for any reason except death, Disability, or for Cause; A-2 (ii) immediately upon Holder's Separation as a result, in whole or in material part, of a discharge for Cause; (iii) the first anniversary of Holder's Separation by reason of death or Disability; or (iv) the tenth (10th) anniversary of the Date of Grant. 6. No Transfers Permitted. Neither this SAR Agreement nor the SARs are transferable by Holder otherwise than by will or the laws of descent and distribution and, so long as an Holder lives, only Holder or his or her guardian or legal representative shall have the right to exercise Vested SARs. 7. No Right To Continued Employment. Neither the Plan, nor this SAR Agreement, shall confer upon Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall it interfere in any way Holder's right to terminate employment, or the Company's right to terminate Holder's employment, at any time. 8. Law Governing. WITHOUT LIMITATION, THIS SAR AGREEMENT SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. Dated as of this ________ day of __________, 200___. DENBURY RESOURCES INC. By: _____________________________ Acknowledgment The undersigned hereby acknowledges (i) my receipt of this SAR Agreement, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this SAR Agreement with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the SAR Agreement and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this SAR Agreement and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or SAR Agreement, or both) of the Administrator upon any questions arising under the Plan, or this SAR Agreement, or both. Dated as of this ________ day of ______________, 200__. ________________________________ Holder A-3 EX-10 22 fy2004-exhibit10s.txt EXHIBIT 10(S), STOCK APPRECIATION RIGHTS AGRMNT. Exhibit 10(s) Form of Stock Appreciation Rights Agreement that Cliff Vests No. SARs [_________] Date of Grant [_______] STOCK APPRECIATION RIGHTS AGREEMENT 2004 OMNIBUS STOCK AND INCENTIVE PLAN FOR DENBURY RESOURCES INC. A total of _____ Stock Appreciation Rights (individually, and collectively, "SAR(s)") are hereby granted to ________ (the "Holder") on ________ ("Date of Grant") at the Grant Value determined in this SAR Agreement, and in all respects subject to the terms, definitions and provisions, of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (the "Plan"), which is incorporated herein by reference except to the extent otherwise expressly provided in this SAR Agreement. 1. Grant Value. The Grant Value is $_________ for each SAR, which value is equal to the Fair Market Value of a Share on the Date of Grant. 2. Vesting of SAR Agreement Shares. The SARs shall Vest and become "Vested SARs" in accordance with the following schedule: Percentage Becoming Vested Date on Which Percentage Vests - -------------------------- ------------------------------ 100% Fourth Anniversary of Date of Grant Without limiting the generality of the forgoing, in the event that, prior to the fourth (4th) anniversary of the Date of Grant, either (i) Holder incurs a Separation by reason of Holder's death, or Disability, or (ii) there is a Change in Control, then all of the SARs which have not previously become Vested SARs shall become Vested SARs as of the date of such death, disability or Change in Control. 3. Amount Payable, and Form of Payment, on Exercise of SAR. (a) Amount Payable on Exercise of SAR. Upon the Holder's exercise of the a Vested SAR, the Holder shall be entitled to receive the SAR Spread, determined as of the date of exercise of the SAR Agreement, with respect to each SAR exercised on such date. The SAR Spread is the product of (i) the excess of the Fair Market Value of a Share on the date of exercise over the Grant Value, multiplied by (ii) the number of SARs exercised. (b) Form of Payment. Within a reasonable period following the exercise of a Vested SAR, the Holder will receive Shares having a Fair Market Value, as A-1 determined on the date of exercise of the Vested SAR, equal to the SAR Spread described in Section 3(a) above. Without limiting the generality of the foregoing, the Holder may choose to use a portion of such Shares to satisfy some or all of such Holder's withholding obligations under Section 4(b) of this SAR Agreement. 4. Exercise of SAR Agreement. This SAR Agreement shall not be exercisable prior to the first date on which a portion of the SARs become Vested SARs, and thereafter (and prior to the termination of this SAR Agreement), this SAR Agreement shall be exercisable, in whole or in part, with respect to Vested SARs. (a) Method of Exercise. Without limitation, this SAR Agreement shall be exercised by a written notice delivered to the Administrator which shall: (i) state the election to exercise the SAR Agreement and the number of Vested SARs in respect of which it is being exercised; and (ii) be signed by the person or persons entitled to exercise the SAR Agreement and, if the SAR Agreement is being exercised by any person or persons other than the Holder, be accompanied by proof, satisfactory to the Administrator, of the rights of such person or persons to exercise the SAR Agreement. (b) Withholding. Upon the exercise of the SAR, the minimum withholding required to be made by the Company shall be paid by the Holder to the Administrator in cash, or by the delivery of Shares, which Shares may be in whole or in part Shares acquired through the exercise of this SAR Agreement, based on the Fair Market Value of such Shares on the date of delivery. (c) Issuance of Shares. No person shall be, or have any of the rights or privileges of, a holder of the Shares which would be delivered as a result of the exercise of this SAR Agreement unless and until certificates representing such Shares shall have been issued and delivered to such person, such issuance, without limitation, being subject to the terms of the Plan. (d) Surrender of SAR Agreement. Upon exercise of this SAR Agreement in part, if requested by the Administrator, the Holder shall deliver this SAR Agreement and other written agreements (if any) executed by the Company and the Holder with respect to this SAR Agreement to the Administrator who shall endorse or cause to be endorsed thereon a notation of such exercise and return the SAR Agreement (and other agreements, if any) to the Holder. 5. Term of SAR Agreement. Without limitation, the unexercised portion of this SAR Agreement shall automatically and without notice terminate at the time of the earliest to occur of the following: (i) the 90th day following Holder's Separation for any reason except death, Disability, or for Cause; (ii) immediately upon Holder's Separation as a result, in whole or in material part, of a discharge for Cause; A-2 (iii) the first anniversary of Holder's Separation by reason of death or Disability; or (iv) the tenth (10th) anniversary of the Date of Grant. 6. No Transfers Permitted. Neither this SAR Agreement nor the SARs are transferable by Holder otherwise than by will or the laws of descent and distribution and, so long as an Holder lives, only Holder or his or her guardian or legal representative shall have the right to exercise Vested SARs. 7. No Right To Continued Employment. Neither the Plan, nor this SAR Agreement, shall confer upon Holder any right with respect to continuation of employment by the Company, or any right to provide services to the Company, nor shall it interfere in any way Holder's right to terminate employment, or the Company's right to terminate Holder's employment, at any time. 8. Law Governing. WITHOUT LIMITATION, THIS SAR AGREEMENT SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF DELAWARE. Dated as of this ________ day of __________, 200___. DENBURY RESOURCES INC. By:_____________________________ Acknowledgment The undersigned hereby acknowledges (i) my receipt of this SAR Agreement, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this SAR Agreement with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the SAR Agreement and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this SAR Agreement and the Plan. Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or SAR Agreement, or both) of the Administrator upon any questions arising under the Plan, or this SAR Agreement, or both. Dated as of this ________ day of ______________, 200__. ________________________________ Holder A-3 -----END PRIVACY-ENHANCED MESSAGE-----