Note 1. Basis of Presentation

Interim Financial Statements

     The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Denbury” or “Company” refer to Denbury Resources Inc. and its subsidiaries. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2008. Any capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial Statements have the same meaning given to them in the Form 10-K.

     Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments (of a normal recurring nature) necessary to present fairly the consolidated financial position of Denbury as of June 30, 2009, the consolidated results of its operations for the three and six month periods ended June 30, 2009 and 2008 and cash flows for the six months ended June 30, 2009 and 2008. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter. We have evaluated events that occurred subsequent to June 30, 2009 through August 10, 2009, the financial statement issuance date.

Net Income (Loss) Per Common Share

     Basic net income (loss) per common share is computed by dividing net income 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 on net income and common shares for the potential dilution from stock options, stock appreciation rights (“SARs”), non-vested restricted stock and any other convertible securities outstanding. For the three and six month periods ended June 30, 2009 and 2008, there were no adjustments to net income (loss) for purposes of calculating diluted net income (loss) per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income (loss) per common share calculations for the three and six month periods ended June 30, 2009 and 2008.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
In thousands		2009				2008				2009				2008
Weighted average common shares — basic			246,084				243,623				245,830				243,189
Potentially dilutive securities:
Stock options and SARs			—				7,389				—				8,043
Restricted stock			—				1,389				—				1,371
Weighted average common shares - diluted			246,084				252,401				245,830				252,603

     The weighted average common shares — basic amount excludes 2,928,022 shares at June 30, 2009 and 2,668,538 shares at June 30, 2008, of non-vested restricted stock that is subject to future vesting over time. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although all restricted stock is issued and outstanding upon grant). For purposes of calculating weighted average common shares — diluted during the three and six months ended June 30, 2008, 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.

     For the three and six months ended June 30, 2008, stock options and SARs to purchase approximately 49,000 and 691,000 shares of common stock, respectively, were outstanding but excluded from the diluted net income per common share calculations, as the exercise prices of the options exceeded the average market price of the Company’s common stock during these periods and would be anti-dilutive to the calculations.

     For the three and six months ended June 30, 2009, all outstanding stock options, SARs and non-vested restricted stock were excluded from the calculation of weighted average common shares - diluted as their impact would have been antidilutive to the net losses incurred during those periods. During the three and six months ended June 30, 2009, 11.2 million and 11.1 million, respectively, of stock options and SARs were excluded from the calculation of weighted average common shares - diluted and for both 2009 periods, 2.8 million shares of non-vested restricted stock were excluded.

CO₂ Pipelines

     CO₂ pipelines are used for transportation of CO₂ to our tertiary floods from our CO₂ source field located near Jackson, Mississippi. We are continuing expansion of our CO₂ pipeline infrastructure with several pipelines currently under construction. At June 30, 2009 and December 31, 2008, we had $761.7 million and $402.0 million of costs, respectively, related to pipeline construction in progress, recorded under “CO₂ properties, equipment and pipelines” in our Unaudited Condensed Consolidated Balance Sheets. These costs of CO₂ pipelines under construction were not being depreciated at June 30, 2009 or December 31, 2008. Depreciation will commence as each pipeline is placed into service. Each pipeline is depreciated on a straight-line basis over its estimated useful life as determined for GAAP purposes, which range between 20 to 30 years.

Goodwill

     Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather it is tested for impairment annually and also when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. In the case of Denbury, we have only one reporting unit. The fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, the recorded goodwill is impaired to its implied fair value with a charge to operating expense.

Recently Adopted Accounting Pronouncements

     Business Combinations. In December 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 141 (Revised 2008), “Business Combinations.” SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. We adopted this statement on January 1, 2009. We have applied SFAS 141(R) to an acquisition that we made during the first quarter (see Note 2, “Acquisitions and Divestitures”).

     Equity Method Accounting. In November 2008, the FASB reached a consensus on Emerging Issues Task Force (“EITF”) Issue 08-6, “Equity Method Investment Accounting Considerations” which was issued to clarify how the application of equity method accounting will be affected by SFAS No. 141(R) and SFAS No. 160, “Non-Controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.” EITF 08-6 clarifies that an entity shall continue to use the cost accumulation model for its equity method investments. It also confirms past accounting practices related to the treatment of contingent consideration and the use of the impairment model under Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock”. Additionally, it requires an equity method investor to account for a share issuance by an investee as if the investor had sold a proportionate share of the investment. This Issue was effective January 1, 2009, applies prospectively and did not have any impact on our financial position or results of operations.

     Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160 which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest, and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. We adopted SFAS No. 160 on January 1, 2009. Since we currently do not have any noncontrolling interests, the adoption of SFAS No. 160 did not have any impact on our financial position or results of operations.

     Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of SFAS No. 133.” SFAS No. 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS No. 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” have been applied, and the impact that hedges have on an entity’s financial position, financial performance, and cash flows. We adopted the disclosure requirement of SFAS No. 161 beginning January 1, 2009 (see Note 6, “Derivative Instruments and Hedging Activities”). The adoption of this statement did not have any impact on our financial position or results of operations.

     Fair Value Measurements. On February 12, 2008, the FASB issued FASB Staff Position (“FSP”) SFAS No. 157-2 “Effective Date of FASB Statement No. 157,” which delayed the effective date of SFAS No. 157, “Fair Value Measurements,” for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We adopted FSP FASB No. 157-2 on January 1, 2009. The adoption of this FSP did not have any impact on our financial position or results of operations.

     In April 2009, the FASB issued three FASB Staff Positions to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. FSP SFAS No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” provides guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157. FSP SFAS No. 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. FSP SFAS No. 115-2 and SFAS No. 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. These three FSPs are effective for interim and annual periods ending after June 15, 2009. The adoption of these FSPs enhanced our interim financial statement disclosures but did not have any impact on our financial position or results of operations.

     Subsequent Events. In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” to establish accounting standards for events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 does not significantly change current practice. The new standard does require companies to disclose the date through which subsequent events were evaluated and whether or not that date was the date the financial statements were issued or available for issuance. The Company adopted SFAS No. 165 upon issuance. This standard did not have any impact on the Company’s financial position or results of operations.

Recently Issued Accounting Pronouncements

     Modernization of Oil and Gas Reporting. On December 31, 2008, the Securities and Exchange Commission adopted major revisions to its rules governing oil and gas company reporting requirements. These include provisions that permit the use of new technologies to determine proved reserves, and that allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new disclosure requirements also require companies that have an audit performed on their reserves to report the independence and qualifications of the auditor of the reserve estimates, and to file reports when a third party reserve engineer is relied upon to prepare reserve estimates. The new rules also require that oil and gas reserves be reported and the full cost ceiling value calculated using an average price based upon the prior twelve-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. We are currently evaluating the impact the new rules may have on our financial condition or results of operations.

     FASB Accounting Standards Codification^TM. In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles”, which becomes effective for financial statements issued for interim and annual periods ending after September 15, 2009. SFAS No. 168 replaces SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. The FASB Accounting Standards Codification ^TM will become the source of U.S. GAAP recognized by the FASB for nongovernmental entities. The Company will apply this standard to our financial statements issued for the nine months ended September 30, 2009. This standard will not have any impact on the Company’s financial position or results of operations.

     Transfers of Financial Assets. In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets — an amendment to FASB Statement No. 140.” SFAS No. 166 removes the concept of a qualifying special-purpose entity (“QSPE”) from FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities a replacement of FASB Statement 125”, creates a new unit of account definition that must be met for transfers of portions of financial assets to be eligible for sale accounting, clarifies the derecognition criteria for a transfer to be accounted for as a sale, changes the amount of recognized gains or losses on the transfer of financial assets accounted for as a sale when beneficial interests are received by the transferor and introduces new disclosure requirements. SFAS No. 166 is effective for us beginning January 1, 2010. We do not anticipate the adoption of SFAS No. 166 will have a material impact on our financial condition or results of operations.

     Consolidation of Variable Interest Entities. In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R).” This standard eliminates the exemption in FASB Interpretation No. 46(R) for QSPEs, introduces a new approach for determining who should consolidate a variable interest entity and changes the requirement as to when it is necessary to reassess who should consolidate a variable-interest entity. This standard is effective for us beginning January 1, 2010. We are currently evaluating the impact the new rule may have on our financial condition or results of operations.

Note 2. Acquisitions and Divestitures

Hastings Field Acquisition

     During November 2006, we entered into an agreement with a subsidiary of Venoco, Inc., that gave us an option to purchase their interest in Hastings Field, a strategically significant potential tertiary flood candidate located near Houston, Texas. We exercised the purchase option prior to September 2008, and closed the acquisition during February 2009. As consideration for the option agreement, during 2006 through 2008, we made cash payments totaling $50 million which we recorded as a deposit. The purchase price of approximately $196 million, which was paid in cash, was determined as of January 1, 2009 (the effective date) with closing on February 2, 2009. The deposit plus purchase price, adjusted for interim net cash flows between the effective date and closing date of the acquisition (including minor purchase price adjustments), totaled approximately $248.2 million.

     Under the terms of the agreement, Venoco, Inc., the seller, retained a 2% override and a reversionary interest of approximately 25% following payout, as defined in the option agreement. The Hastings Field proved reserves were not included in the Company’s year-end 2008 proved reserves. We plan to commence flooding the field with CO₂ beginning in 2011, after completion of our Green Pipeline currently under construction and construction of field recycling facilities. Under the agreement, we are required to make aggregate net cumulative capital expenditures in this field of approximately $179 million over the next six years cumulating as follows: $26.8 million by December 31, 2010, $71.5 million by December 31, 2011, $107.2 million by December 31, 2012, $142.9 million by December 31, 2013, and $178.7 million by December 31, 2014. If we fail to spend the required amounts by the due dates, we are required to make a cash payment equal to 10% of the cumulative shortfall at each applicable date. Further, we are committed to inject at least an average of 50 MMcf/day of CO₂ (total of purchased and recycled) in the West Hastings Unit for the 90 day period prior to January 1, 2013. If such injections do not occur, we must either (1) relinquish our rights to initiate (or continue) tertiary operations and reassign to Venoco all assets previously purchased for the value of such assets at that time based upon the discounted value of the field’s proved reserves using a 20% discount rate, or (2) make an additional payment of $20 million in January 2013, less any payments made for failure to meet the capital spending requirements as of December 31, 2012, and a $30 million payment for each subsequent year (less amounts paid for capital expenditure shortfalls) until the CO₂ injection rate in the Hastings Field equals or exceeds the minimum required injection rate.

     This acquisition of Hastings Field qualifies as a business under SFAS No. 141(R), “Business Combinations.” As such, we estimated the fair value of this property as of the acquisition date, as defined in SFAS No. 141(R) to be the date on which the acquirer obtains control of the acquiree, which for this acquisition is February 2, 2009 (the closing date). SFAS No. 157, “Fair Value Measurements,” defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). Further, SFAS No. 157 emphasizes that a fair value measurement should be based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions should not impact the measurement of fair value unless those assumptions are consistent with market participant views.

     In applying these accounting principles we estimated that the fair value of these properties on the acquisition date to be approximately $107.0 million. This measurement resulted in the recognition of goodwill totaling $138.7 million. SFAS No. 141(R) defines goodwill as an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. For this acquisition, goodwill is the excess of the cash paid to acquire the Hastings Field over the acquisition date estimated fair value. This resultant goodwill is due primarily to two factors. The first factor is the decrease in the NYMEX oil and natural gas futures prices between the effective date of January 1, 2009 and the acquisition date of February 2, 2009. The purchase agreement provided that the Hastings reserves be valued using the NYMEX oil and gas futures prices on the effective date of January 1, 2009. The second factor is the estimated fair value assigned to the estimated oil reserves recoverable through a CO₂ enhanced oil recovery (“EOR”) project. Denbury has one of the few known significant natural sources of CO₂ in the United States, and the largest known source east of the Mississippi river. This source of CO₂ that we own will allow Denbury to carry out CO₂ EOR activities in this field at a much lower cost than other market participants. However, SFAS No. 157 does not allow entity-specific assumptions in the measurement of fair value. Therefore, we estimated the fair value of the oil reserves recoverable through CO₂ EOR using an estimated cost of CO₂ to other market participants. This assumption of a higher cost of CO₂ resulted in an estimated fair value of the projected CO₂ EOR reserves that would not have been economically viable and therefore no value has been assigned to undeveloped properties in this acquisition.

     The fair value of Hastings Field was based on significant inputs not observable in the market, which SFAS No. 157 refers to as Level 3 inputs. Key assumptions include (1) NYMEX oil and natural gas futures (this input is observable), (2) projections of the estimated quantities of oil and natural gas reserves, (3) projections of future rates of production, (4) timing and amount of future development and operating costs, (5) projected cost of CO₂ to a market participant, (6) projected recovery factors and, (7) risk adjusted discount rates. The fair value of these properties was assigned to the assets and liabilities acquired, which included $107.0 million to evaluated properties in the full cost pool and $2.4 million (net) for land, oilfield equipment and other related assets. Denbury applies SEC full cost accounting rules, under which the acquisition cost of oil and gas properties are recognized on a cost center basis (country), of which Denbury has only one cost center (United States). The goodwill of $138.7 million was assigned to this single reporting unit. All of the goodwill is deductible for tax purposes as property cost. This purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

     The transaction related costs (legal, accounting, due diligence, etc.) have been expensed in accordance with the provisions of SFAS No. 141(R). We have not presented any pro forma information for the acquired business as the pro forma effect was not material to our results of operations for the three or six month periods ended June 30, 2009 or 2008.

Sale of Barnett Shale Assets

     In May 2009, we entered into an agreement to sell 60% of our Barnett Shale natural gas assets to Talon Oil and Gas LLC, a privately held company, for $270 million (before closing adjustments). In June 2009, we closed on approximately three-quarters of the sale with net proceeds (after closing adjustments, but including the $10 million deposit) of $197.5 million. The agreement has an effective date of June 1, 2009, and consequently operating net revenues after June 1, net of capital expenditures, along with any other purchase price adjustments, were adjustments to the selling price. We did not record a gain or loss on the sale in accordance with the full cost method of accounting. The Company closed on the remaining portion of the sale on July 15, 2009 (see Note 9, “Subsequent Event”). We have not presented pro forma information for the disposal as the pro forma effect was not material.

Note 3. Asset Retirement Obligations

     In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil, natural gas and CO₂ wells, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement is 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.

     The following table summarizes the changes in our asset retirement obligations for the six months ended June 30, 2009.

		Six Months Ended
In thousands		June 30, 2009
Balance, beginning of period		$	45,064
Liabilities incurred and assumed during period			2,638
Revisions in estimated retirement obligations			857
Liabilities settled during period			(1,511	)
Accretion expense			1,637
Sales			(838	)
Balance, end of period		$	47,847

     At June 30, 2009, $1.6 million of our asset retirement obligation was classified in “Accounts payable and accrued liabilities” under current liabilities in our Unaudited Condensed Consolidated Balance Sheets. Liabilities incurred during the six month period ended June 30, 2009 are primarily related to the Hastings Field acquisition and sales during the period are primarily related to the Barnett Shale natural gas assets (see Note 2, “Acquisitions and Divestitures”). We hold cash and liquid investments in escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $7.4 million at both June 30, 2009 and December 31, 2008 and are included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets.

Note 4. Notes Payable and Long-Term Indebtedness

		June 30,				December 31,
In thousands		2009				2008
9.75% Senior Subordinated Notes due 2016		$	426,350			$	—
Discount on Senior Subordinated Notes due 2016			(28,566	)			—
7.5% Senior Subordinated Notes due 2015			300,000				300,000
Premium on Senior Subordinated Notes due 2015			556				599
7.5% Senior Subordinated Notes due 2013			225,000				225,000
Discount on Senior Subordinated Notes due 2013			(728	)			(826	)
NEJD financing — Genesis			172,163				173,618
Free State financing — Genesis			78,260				76,634
Senior bank loan			45,000				75,000
Capital lease obligations — Genesis			4,171				4,544
Capital lease obligations			2,484				2,705
Total			1,224,690				857,274
Less current obligations			4,586				4,507
Long-term debt and capital lease obligations		$	1,220,104			$	852,767

Issuance of 9.75% Senior Subordinated Notes due 2016

     On February 13, 2009, we issued $420 million of 9.75% Senior Subordinated Notes due 2016 (“2016 Notes”). The 2016 Notes, which carry a coupon rate of 9.75%, were sold at a discount (92.816% of par), which equates to an effective yield to maturity of approximately 11.25%. The net proceeds of $381.4 million were used to repay most of our then-outstanding borrowings under our bank credit facility, which increased from the December 31, 2008 balance, primarily associated with the funding of the Hastings Field acquisition (see Note 2, “Acquisitions and Divestitures”). In conjunction with this debt offering we amended our bank credit facility in early February 2009, which, among other things, allowed us to issue these senior subordinated notes.

     In June 2009, we issued an additional $6.35 million of the 2016 Notes to our founder, Gareth Roberts, as part of a Founder’s Retirement Agreement. In connection with this issuance, we recorded compensation expense of $6.35 million in General and administrative expense in our Unaudited Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2009.

     The 2016 Notes mature on March 1, 2016, and interest on the 2016 Notes is payable March 1 and September 1 of each year beginning on September 1, 2009. We may redeem the 2016 Notes in whole or in part at our option beginning March 1, 2013, at the following redemption prices: 104.875% after March 1, 2013, 102.4375% after March 1, 2014, and 100%, after March 1, 2015. In addition, we may at our option, redeem up to an aggregate of 35% of the 2016 Notes before March 1, 2012 at a price of 109.75%. 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 2016 Notes are not subject to any sinking fund requirements. All of our significant subsidiaries fully and unconditionally guarantee this debt.

Senior Bank Loan

     To clarify that Denbury entities are allowed to guarantee obligations of other Denbury entities, in May 2009 we amended our Sixth Amended and Restated Credit Agreement, the instrument governing our Senior Bank Loan, to explicitly permit these guarantees and waive any possible previous technical violations of this provision.

     In June 2009 we again amended our Senior Bank Loan agreement in connection with the sale of our Barnett Shale natural gas properties and (i) reduced our borrowing base from $1.0 billion to $900 million and (ii) allowed for an additional percentage of our forecasted production to be hedged through June 30, 2009. The amendment did not impact the banks’ commitment amount, which remains at $750 million.

Note 5. Related Party Transactions — Genesis

Interest in and Transactions with Genesis

     Denbury’s subsidiary, Genesis Energy, LLC, is the general partner of, and together with Denbury’s other subsidiaries, owns an aggregate 12% interest in Genesis Energy, L.P. (“Genesis”), a publicly traded master limited partnership. Genesis’ business is focused on the mid-stream segment of the oil and natural gas industry in the Gulf Coast area of the United States, and its activities include gathering, marketing and transportation of crude oil and natural gas, refinery services, wholesale marketing of CO₂, and supply and logistic services.

     We account for our 12% 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 investment in Genesis is included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets. Denbury received cash distributions from Genesis of $5.1 million and $2.8 million during the six months ended June 30, 2009 and 2008, respectively. We also received $0.1 million during both the six months ended June 30, 2009 and 2008 as directors’ fees for certain officers of Denbury that are board members of Genesis. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, LLC.

     At June 30, 2009, the balance of our equity investment in Genesis was $78.9 million. Based on quoted market values of Genesis’ publicly traded limited partnership units at June 30, 2009, the estimated market value of our publicly traded common units of Genesis was approximately $51.2 million. Since the general partner units we hold are not publicly traded, there is not a readily available market value for these units. Due to the capital market conditions during the latter part of 2008 and in 2009, we have reviewed the value of our investment in Genesis as of June 30, 2009 for impairment. Based upon this review, which considered the current and future expected cash flows of Genesis, we do not believe the investment balance is impaired.

Incentive Compensation Agreement

     In late December 2008, our subsidiary, Genesis Energy, LLC, entered into agreements with three members of Genesis management, for the purpose of providing them incentive compensation, which agreements make them Class B Members in Genesis Energy, LLC. The compensation agreements provide Genesis management with the ability to earn up to an approximate aggregate 17% interest in the incentive distributions that Genesis Energy, LLC receives (commencing in 2009) from Genesis. The percentage interest in the incentive distribution earned in any given period can vary based upon the Cash Available Before Reserves (“CABR”) per unit as generated by Genesis (excluding any transactions between Genesis and the Company) over each of the three individual’s base amount of CABR per unit as stated in their compensation agreement, subject to vesting and other requirements. As the amount of CABR per unit increases, the members’ share of the incentive distributions increases, up to a maximum aggregate 17% in any given period.

     The amount payable under the award in the event of an employee termination is the present value of the member’s share of forecasted incentive distributions assuming the then current level of distributions continue into perpetuity. The award agreement dictates that the member’s share of future incentive distributions be discounted back to the payment date using a discount rate equal to the current distribution yield of market comparable general partners of master limited partnerships.

     The awards vest 25% on each anniversary grant date. The awards are mandatorily redeemable upon termination of employment or change in control and require the membership interests of the holders of the awards to be redeemed for cash (or in certain circumstances Genesis limited partnership units) by Genesis Energy, LLC. Under the provisions of SFAS 123(R), “Share-Based Payment”, the estimated fair value of these awards is measured each reporting period and recorded as a liability to the extent vested. Changes in the liability are recorded as compensation expense in “General and administrative” expenses in our Unaudited Condensed Consolidated Statement of Operations. We use the graded attribution method to recognize the share-based compensation expense associated with these awards. As of June 30, 2009, we had approximately $5.3 million recorded as a liability for these awards in our Unaudited Condensed Consolidated Balance Sheet. We recorded approximately $2.9 million in the three month period ended June 30, 2009 and $2.6 million in the three month period ended March 31, 2009 in “General and administrative” expenses on our Unaudited Condensed Consolidated Statement of Operations, of which $0.1 million in each three month period relates to cash payments made under these awards and $2.8 million and $2.5 million, respectively, are associated with the fair value of the award.

     The fair value of these awards is estimated using a discounted cash flow analysis which includes assumptions regarding a number of variables, including Genesis management’s estimates of future CABR generated by Genesis, the distribution yield of market comparable publicly-traded general partners of master limited partnerships and a discount rate which considers the risk of forecasted items being realized, the time value of money and the risk of nonperformance by Denbury.

NEJD Pipeline and Free State Pipeline Transactions

     On May 30, 2008, we closed on two transactions with Genesis involving our Northeast Jackson Dome (“NEJD”) pipeline system and Free State Pipeline, which included a long-term transportation service agreement for the Free State Pipeline and a 20-year financing lease for the NEJD system. We have recorded both of these transactions as financing leases. At June 30, 2009, we have recorded $172.2 million for the NEJD financing and $78.3 million for the Free State financing as debt, $3.1 million of which was recorded in current liabilities on our Unaudited Condensed Consolidated Balance Sheet. At December 31, 2008, we had $173.6 million for the NEJD pipeline and $76.6 million for the Free State Pipeline recorded as debt, of which $3.0 million was included in current liabilities in our Unaudited Condensed Consolidated Balance Sheet. (See Note 4, “Notes Payable and Long-Term Indebtedness”).

Oil Sales and Transportation Services

     We utilize Genesis’ trucking services and common carrier pipeline to transport certain of our crude oil production to sales points where it is sold to third party purchasers. We expensed $2.0 million and $1.9 million, respectively, for these transportation services during the three months ended June 30, 2009 and 2008, respectively, and $4.2 million and $3.4 million during the six months ended June 30, 2009 and 2008, respectively.

Transportation Leases

     We have pipeline transportation agreements with Genesis to transport our crude oil from certain of our fields in Southwest Mississippi, and to transport CO₂ from our main CO₂ pipeline to Brookhaven Field for our tertiary operations. We have accounted for these agreements as capital leases. At June 30, 2009 and December 31, 2008, we had $4.2 million and $4.5 million, respectively, of capital lease obligations with Genesis recorded as liabilities in our Unaudited Condensed Consolidated Balance Sheets.

CO₂ Volumetric Production Payments

     During 2003 through 2005, we sold 280.5 Bcf of CO₂ to Genesis under three separate volumetric production payment agreements. We have recorded the net proceeds of these volumetric production payment sales as deferred revenue and recognize such revenue as CO₂ is delivered under the volumetric production payments. At June 30, 2009 and December 31, 2008, $22.0 million and $24.0 million, respectively, was recorded as deferred revenue, of which $4.1 million was included in current liabilities at both June 30, 2009 and December 31, 2008. We recognized deferred revenue of $1.0 million and $1.1 million for the three month periods ended June 30, 2009 and 2008, respectively, and $2.0 million and $2.2 million during the six month periods ended June 30, 2009 and 2008, respectively, for deliveries under these volumetric production payments. We provide Genesis with certain processing and transportation services in connection with transporting CO₂ to their industrial customers for a fee of approximately $0.20 per Mcf of CO₂. For these services, we recognized revenues of $1.3 million and $1.4 million for the three months ended June 30, 2009 and 2008, respectively, and $2.5 million and $2.6 million for the six months ended June 30, 2009 and 2008, respectively.

Note 6. Derivative Instruments and Hedging Activities

Oil and Natural Gas Derivative Contracts

     We do not apply hedge accounting treatment to our oil and natural gas derivative contracts and therefore the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts are shown under “Commodity derivative expense” in our Unaudited Condensed Consolidated Statements of Operations.

     From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps.

     As a result of the recent economic conditions, and in order to protect our liquidity in the event that commodity prices decline, during early October 2008 we purchased oil derivative contracts for 2009 with a floor price of $75 per Bbl and a ceiling price of $115 per Bbl for total consideration of $15.5 million. In March 2009, we entered into crude oil swap contracts covering 25,000 Bbls/d for the first quarter of 2010 at a weighted average price of $51.85 per barrel, and crude oil collar contracts covering 25,000 Bbls/d for the second quarter of 2010 with a weighted average floor price of $50.00 per Bbl and a weighted average ceiling price of $74.60 per Bbl. Also during March 2009, we entered into natural gas derivative swap contracts covering 55,000 MMBtu/d for 2010 at a weighted average price of $5.66 per MMBtu, and 40,000 MMBtu/d for 2011 at a weighted average price of $6.21 per MMBtu. In May 2009, we entered into crude oil collar contracts covering 25,000 Bbls/d for the third quarter of 2010 with a weighted average floor price of $57.50 per Bbl and a weighted average ceiling price of $80.34 per Bbl. In conjunction with the sale of our Barnett Shale assets (see Note 2, “Acquisitions and Divestitures”), we transferred a portion of our 2010 and 2011 natural gas derivative swap contracts to the purchaser, Talon Oil and Gas LLC. At June 30, 2009, we retained natural gas derivative swap contracts covering 42,000 MMBtu/d for 2010 at an average price of $5.67 per MMBtu and 29,000 MMBtu/d for 2011 at a weighted average price of $6.23 per MMBtu.

     At June 30, 2009, our oil and natural gas derivative contracts were recorded at their fair value, which was a net liability of $47.0 million. All of the mark-to-market valuations used for our oil and natural gas derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our derivative contracts are with parties that are lenders under our Senior Bank Loan.

     The following is a summary of “Commodity derivative expense” included in our Unaudited Condensed Consolidated Statements of Operations:

		Three Months Ended June 30,								Six Months Ended June 30,
In thousands		2009				2008				2009				2008
Receipt (payment) on settlements of derivative contracts — oil		$	42,002			$	(12,131	)		$	127,838			$	(19,523	)
Receipt (payment) on settlements of derivative contracts — gas			—				(16,463	)			—				(17,119	)
Fair value adjustments to derivative contracts — expense			(194,791	)			(30,223	)			(301,142	)			(68,956	)
Commodity derivative expense		$	(152,789	)		$	(58,817	)		$	(173,304	)		$	(105,598	)

Fair Value of Crude Oil Derivative Contracts Not Classified as Hedging Instruments under SFAS No. 133:

																		Estimated Fair Value
		NYMEX Contract Prices Per Bbl																Asset (Liability)
										Collar Prices								June 30,				December 31,
Type of Contract and Period		Bbls/d				Swap Price				Floor				Ceiling				2009				2008
																		(In thousands)
Collar Contracts
July 2009 - Dec. 2009			30,000				—			$	75.00			$	115.00			$	39,279			$	249,746
April 2010 - June 2010			5,000				—				50.00				76.00				(3,089	)			—
April 2010 - June 2010			10,000				—				50.00				73.15				(7,416	)			—
April 2010 - June 2010			5,000				—				50.00				76.40				(3,009	)			—
April 2010 - June 2010			5,000				—				50.00				74.30				(3,447	)			—
July 2010 - Sept. 2010			2,500				—				55.00				80.10				(1,145	)			—
July 2010 - Sept. 2010			10,000				—				55.00				80.00				(4,616	)			—
July 2010 - Sept. 2010			7,500				—				60.00				80.40				(2,588	)			—
July 2010 - Sept. 2010			5,000				—				60.00				81.05				(1,613	)			—
Swap Contracts
Jan. 2010 - March 2010			6,667			$	52.50				—				—				(12,369	)			—
Jan. 2010 - March 2010			3,333				52.20				—				—				(6,270	)			—
Jan. 2010 - March 2010			5,000				52.10				—				—				(9,449	)			—
Jan. 2010 - March 2010			5,000				50.90				—				—				(9,969	)			—
Jan. 2010 - March 2010			5,000				51.45				—				—				(9,731	)			—

Fair Value of Natural Gas Derivative Contracts Not Classified as Hedging Instruments under SFAS No. 133:

     On July 15, 2009, in conjunction with closing the second portion of our sale of 60% of our Barnett Shale natural gas assets (see Note 2, “Acquisitions and Divestitures”) we transferred 3,000 MMBtu/d of our 2010 natural gas derivative swap contracts, and 2,000 MMBtu/d of our 2011 natural gas derivative swap contracts, to the purchaser, Talon Oil and Gas LLC.

										Estimated Fair Value
		NYMEX Contract								Asset (Liability)
		Prices Per MMBtu								June 30,				December 31,
Type of Contract and Period		MMBtu/d				Swap Price				2009				2008
										(In thousands)
Swap Contracts
Jan. 2010 - Dec. 2010			42,000			$	5.67			$	(5,514	)		$	—
Jan. 2011 - Dec. 2011			10,000				6.27				(1,980	)			—
Jan. 2011 - Dec. 2011			10,000				6.25				(2,027	)			—
Jan. 2011 - Dec. 2011			9,000				6.16				(2,095	)			—

Additional Disclosures about Derivative Instruments:

     At June 30, 2009 and December 31, 2008, we had derivative financial instruments under SFAS No. 133 recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

				Estimated Fair Value
				Asset (Liability)
				June 30,				December 31,
Type of Contract		Balance Sheet Location		2009				2008
				(In thousands)
Derivatives not designated as hedging instruments:
Derivative Asset
Crude Oil contracts		Derivative assets - current		$	39,279			$	249,746
Derivative Liability
Crude Oil contracts		Derivative liability - current			(64,750	)			—
Natural Gas contracts		Derivative liability - current			(205	)			—
Crude Oil contracts		Derivative liability - long-term			(9,962	)			—
Natural Gas contracts		Derivative liability - long-term			(11,410	)			—
Total derivatives not designated as hedging instruments				$	(47,048	)		$	249,746

     For the three and six months ended June 30, 2009 and 2008, the effect on income of derivative financial instruments under SFAS No. 133 was as follows:

						Amount of Gain / (Loss)								Amount of Gain / (Loss)
						Recognized in Income For								Recognized in Income For
						Three Months Ended								Six Months Ended
		Location of Gain/(Loss)				June 30,				June 30,				June 30,				June 30,
Type of Contract		Recognized in Income				2009				2008				2009				2008
						(In thousands)
Derivatives not designated as hedging instruments:
Commodity Contracts
Crude Oil Contracts		Commodity derivative expense				$	(147,316	)		$	(19,688	)		$	(157,341	)		$	(24,442	)
Natural Gas Contracts		Commodity derivative expense					(5,473	)			(39,129	)			(15,963	)			(81,156	)
Total derivatives not designated as hedging instruments						$	(152,789	)		$	(58,817	)		$	(173,304	)		$	(105,598	)

Note 7. Fair Value Measurements

     As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

     Level 1 — Quoted prices in active markets for identical assets or liabilities as of the reporting date. During 2008 we had no level 1 recurring measurements.

     Level 2 — Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

     Instruments in this category include non-exchange-traded oil and natural gas derivatives such as over-the-counter swaps. We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts as required by SFAS No. 157. We have measured nonperformance risk based upon credit default swaps or credit spreads. At both June 30, 2009 and December 31, 2008, the fair value of our oil and natural gas derivative contracts was reduced by $3.7 million for estimated nonperformance risk.

     Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

     The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009.

		Fair Value Measurements at June 30, 2009 Using:
						Significant
		Quoted Prices				Other				Significant
		in Active				Observable				Unobservable
		Markets				Inputs				Inputs
In thousands		(Level 1)				(Level 2)				(Level 3)				Total
Assets:
Oil derivative contracts		$	—			$	39,279			$	—			$	39,279
Liabilities:
Oil and natural gas derivative contracts			—				(86,327	)			—				(86,327	)
Total		$	—			$	(47,048	)		$	—			$	(47,048	)

     The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements.

		June 30, 2009								December 31, 2008
		Carrying				Estimated				Carrying				Estimated
In thousands		Amount				Fair Value				Amount				Fair Value
9.75% Senior Subordinated Notes due 2016		$	397,784			$	438,075			$	—			$	—
7.5% Senior Subordinated Notes due 2015			300,556				285,000				300,599				213,000
7.5% Senior Subordinated Notes due 2013			224,272				214,875				224,174				171,000
Senior Bank Loan			45,000				41,128				75,000				64,000

     The fair values of our senior subordinated notes are based on quoted market prices. The carrying value of our Senior Bank Loan is approximately fair value based on the fact that it is subject to short-term floating interest rates that approximate the rates available to us for those periods. We adjusted the estimated fair value measurement of our Senior Bank Loan in accordance with SFAS No. 157 for estimated nonperformance risk. This estimated nonperformance risk totaled approximately $3.9 million and $11.0 million at June 30, 2009 and December 31, 2008, respectively, and was determined utilizing industry credit default swaps. 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 8. Condensed Consolidating Financial Information

     Our subordinated debt is fully and unconditionally guaranteed jointly and severally by all of Denbury Resources Inc.’s subsidiaries other than minor subsidiaries, except that with respect to our $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources Inc. is the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. The results of our equity interest in Genesis are reflected through the equity method by one of our subsidiaries, Denbury Gathering & Marketing. Each subsidiary guarantor and the subsidiary co-obligor are 100% owned, directly or indirectly, by Denbury Resources Inc. The following is condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and subsidiary guarantors:

Condensed Consolidating Balance Sheets

		June 30, 2009
		Denbury				Denbury
		Resources Inc.				Onshore, LLC												Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
In thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Assets
Current assets		$	453,561			$	256,901			$	17,236			$	(466,337	)		$	261,361
Property and equipment			—				3,215,096				111,650				—				3,326,746
Investment in subsidiaries (equity method)			1,268,178				—				1,212,347				(2,480,525	)			—
Other assets			747,393				204,921				56,205				(738,028	)			270,491
Total assets		$	2,469,132			$	3,676,918			$	1,397,438			$	(3,684,890	)		$	3,858,598
Liabilities and Stockholders’ Equity
Current liabilities		$	15,857			$	698,317			$	122,762			$	(466,337	)		$	370,599
Long-term liabilities			698,340				1,766,254				6,498				(738,028	)			1,733,064
Stockholders’ equity			1,754,935				1,212,347				1,268,178				(2,480,525	)			1,754,935
Total liabilities and stockholders’ equity		$	2,469,132			$	3,676,918			$	1,397,438			$	(3,684,890	)		$	3,858,598

		December 31, 2008
		Denbury				Denbury
		Resources Inc.				Onshore, LLC												Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
In thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Assets
Current assets		$	458,051			$	408,940			$	14,992			$	(466,784	)		$	415,199
Property and equipment			—				2,973,947				28,250				—				3,002,197
Investment in subsidiaries (equity method)			1,371,347				—				1,313,656				(2,685,003	)			—
Other assets			312,239				114,372				56,002				(310,335	)			172,278
Total assets		$	2,141,637			$	3,497,259			$	1,412,900			$	(3,462,122	)		$	3,589,674
Liabilities and Stockholders’ Equity
Current liabilities		$	970			$	810,476			$	41,405			$	(466,784	)		$	386,067
Long-term liabilities			300,599				1,373,127				148				(310,335	)			1,363,539
Stockholders’ equity			1,840,068				1,313,656				1,371,347				(2,685,003	)			1,840,068
Total liabilties and stockholders’ equity		$	2,141,637			$	3,497,259			$	1,412,900			$	(3,462,122	)		$	3,589,674

Condensed Consolidating Statements of Operations

		Three Months Ended June 30, 2009
		Denbury				Denbury
		Resources Inc.				Onshore, LLC												Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
In thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Revenues		$	15,862			$	215,538			$	1,854			$	(15,862	)		$	217,392
Expenses			17,380				354,224				2,318				(15,862	)			358,060
Income (loss) before the following:			(1,518	)			(138,686	)			(464	)			—				(140,668	)
Equity in net earnings of subsidiaries			(85,722	)			—				(85,015	)			170,737				—
Income before income taxes			(87,240	)			(138,686	)			(85,479	)			170,737				(140,668	)
Income tax provision (benefit)			—				(53,671	)			243				—				(53,428	)
Net income (loss)		$	(87,240	)		$	(85,015	)		$	(85,722	)		$	170,737			$	(87,240	)

		Three Months Ended June 30, 2008
		Denbury				Denbury
		Resources Inc.				Onshore, LLC												Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
In thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Revenues		$	5,625			$	417,218			$	767			$	(5,625	)		$	417,985
Expenses			5,746				233,361				828				(5,625	)			234,310
Income (loss) before the following:			(121	)			183,857				(61	)			—				183,675
Equity in net earnings of subsidiaries			114,171				—				114,449				(228,620	)			—
Income before income taxes			114,050				183,857				114,388				(228,620	)			183,675
Income tax provision (benefit)			(3	)			69,408				217				—				69,622
Net income		$	114,053			$	114,449			$	114,171			$	(228,620	)		$	114,053

Condensed Consolidating Statements of Operations (continued)

		Six Months Ended June 30, 2009
		Denbury				Denbury
		Resources Inc.				Onshore, LLC												Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
In thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Revenues		$	26,720			$	387,598			$	3,553			$	(26,720	)		$	391,151
Expenses			29,053				553,188				5,273				(26,720	)			560,794
Income (loss) before the following:			(2,333	)			(165,590	)			(1,720	)			—				(169,643	)
Equity in net earnings of subsidiaries			(103,204	)			—				(101,345	)			204,549				—
Income before income taxes			(105,537	)			(165,590	)			(103,065	)			204,549				(169,643	)
Income tax provision (benefit)			—				(64,245	)			139				—				(64,106	)
Net income (loss)		$	(105,537	)		$	(101,345	)		$	(103,204	)		$	204,549			$	(105,537	)

		Six Months Ended June 30, 2008
		Denbury				Denbury
		Resources Inc.				Onshore, LLC												Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
In thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Revenues		$	11,250			$	734,462			$	858			$	(11,250	)		$	735,320
Expenses			11,491				433,883				1,632				(11,250	)			435,756
Income (loss) before the following:			(241	)			300,579				(774	)			—				299,564
Equity in net earnings of subsidiaries			187,275				—				188,254				(375,529	)			—
Income before income taxes			187,034				300,579				187,480				(375,529	)			299,564
Income tax provision (benefit)			(21	)			112,325				205				—				112,509
Net income		$	187,055			$	188,254			$	187,275			$	(375,529	)		$	187,055

Condensed Consolidating Statements of Cash Flows

     Denbury Resources Inc. (Parent) has no independent assets or operations. Denbury Onshore, LLC is our operating subsidiary. Cash flow activity of Denbury Resources Inc. consists of intercompany loans between Denbury Resources Inc. and Denbury Onshore, LLC to service the parent company issued debt. This intercompany cash flow activity is eliminated in consolidation. Cash flow activity of Denbury Onshore, LLC combined with the other guarantor subsidiaries is presented in our Unaudited Condensed Consolidated Statements of Cash Flows.

		Six Months Ended June 30, 2009
		Denbury				Denbury
		Resources Inc.				Onshore, LLC												Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
In thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Cash flow from operations		$	—			$	260,548			$	241			$	—			$	260,789
Cash flow from investing activities			(388,391	)			(574,840	)			—				388,391				(574,840	)
Cash flow from financing activities			388,391				356,941				—				(388,391	)			356,941
Net increase in cash			—				42,649				241				—				42,890
Cash, beginning of period			24				16,898				147				—				17,069
Cash, end of period		$	24			$	59,547			$	388			$	—			$	59,959

		Six Months Ended June 30, 2008
		Denbury				Denbury
		Resources Inc.				Onshore, LLC												Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
In thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Cash flow from operations		$	(10	)		$	370,325			$	14			$	—			$	370,329
Cash flow from investing activities			(23,757	)			(384,797	)			2,725				23,757				(382,072	)
Cash flow from financing activities			23,757				98,645				—				(23,757	)			98,645
Net increase (decrease) in cash			(10	)			84,173				2,739				—				86,902
Cash, beginning of period			34				58,343				1,730				—				60,107
Cash, end of period		$	24			$	142,516			$	4,469			$	—			$	147,009

Note 9. Subsequent Event

     On July 15, 2009, we closed the remaining balance of the sale of 60% of our Barnett Shale natural gas assets (see Note 2, “Acquisitions and Divestitures”). Net proceeds from the second closing were approximately $62.3 million, bringing total net proceeds of the sale to approximately $259.8 million (after closing adjustments and net of $8.1 million for natural gas swaps transferred in the sale). We did not record any gain or loss on the sale in accordance with the full cost method of accounting.