10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2008

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

Commission File Number 1-12935

DENBURY RESOURCES INC.

(Exact name of Registrant as specified in its charter)

Delaware	20-0467835
(State or other jurisdictions of	(I.R.S. Employer
incorporation or organization)	Identification No.)
5100 Tennyson Parkway
Suite 1200
Plano, TX	75024
(Address of principal executive offices)	(Zip code)
Registrant’s telephone number, including area code:	(972) 673-2000

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at October 31, 2008
Common Stock, $.001 par value	247,042,565

INDEX

	Page
Part I. Financial Information
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at September 30, 2008 and December 31, 2007		3
Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2008 and 2007		4
Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2008 and 2007		5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Nine Months Ended September 30, 2008 and 2007		6
Notes to Unaudited Condensed Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 3. Quantitative and Qualitative Disclosures about Market Risk		38
Item 4. Controls and Procedures		38
Part II. Other Information
Item 1. Legal Proceedings		39
Item 1A. Risk Factors		39
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		39
Item 3. Defaults Upon Senior Securities		39
Item 4. Submission of Matters to a Vote of Security Holders		39
Item 5. Other Information		39
Item 6. Exhibits		39
Signatures		40
Exhibit 10(a)
Exhibit 10(b)
Exhibit 10(c)
Exhibit 31(a)
Exhibit 31(b)
Exhibit 32

2

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except shares)

	September 30,			December 31,
	2008			2007
Assets
Current assets
Cash and cash equivalents	$	175,310		$	60,107
Accrued production receivable		146,904			136,284
Trade and other receivables, net of allowance of $362 and $369		70,017			28,977
Deferred tax asset		30,504			12,708
Derivative assets		1,673			2,283
Total current assets		424,408			240,359
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved		3,193,577			2,682,932
Unevaluated		244,622			366,518
CO2 properties and equipment		673,086			436,591
Other		66,304			50,116
Less accumulated depletion and depreciation		(1,302,961	)		(1,143,282	)
Net property and equipment		2,874,628			2,392,875
Deposits on property under option or contract		49,193			49,097
Other assets		120,303			88,746
Total assets	$	3,468,532		$	2,771,077
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	180,981		$	147,580
Oil and gas production payable		108,535			84,150
Derivative liabilities		7,881			28,096
Deferred revenue — Genesis		4,070			4,070
Current maturities of long-term debt		3,932			737
Total current liabilities		305,399			264,633
Long-term liabilities
Long-term debt — Genesis		251,379			4,544
Long-term debt		525,612			675,786
Asset retirement obligations		42,943			38,954
Deferred revenue — Genesis		21,041			24,424
Deferred tax liability		521,636			347,370
Other		12,537			10,988
Total long-term liabilities		1,375,148			1,102,066
Stockholders’ equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.001 par value, 600,000,000 shares authorized; 247,581,299 and 245,386,951 shares issued at September 30, 2008 and December 31, 2007, respectively		248			245
Paid-in capital in excess of par		702,163			662,698
Retained earnings		1,095,782			751,179
Accumulated other comprehensive loss		(645	)		(1,591	)
Treasury stock, at cost, 624,715 and 637,795 shares at September 30, 2008 and December 31, 2007, respectively		(9,563	)		(8,153	)
Total stockholders’ equity		1,787,985			1,404,378
Total liabilities and stockholders’ equity	$	3,468,532		$	2,771,077

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

3

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008		2007
Revenues and other income
Oil, natural gas and related product sales	$	402,108		$	248,213		$	1,128,548	$	634,826
CO2 sales and transportation fees		3,471			3,594			9,705		10,079
Interest income and other		4,675			1,702			7,321		5,269
Total revenues		410,254			253,509			1,145,574		650,174
Expenses
Lease operating expenses		85,308			59,323			228,134		167,087
Production taxes and marketing expenses		17,104			10,956			50,978		28,819
Transportation expense — Genesis		2,231			1,720			5,623		4,447
CO2 operating expenses		1,240			1,304			2,836		3,211
General and administrative		15,005			11,541			45,821		34,669
Interest, net of amounts capitalized of $6,713, $5,431, $19,524 and $13,785, respectively		10,906			8,628			23,988		23,059
Depletion, depreciation and amortization		56,324			52,797			160,896		140,059
Commodity derivative expense (income)		(62,007	)		(3,973	)		43,591		7,885
Abandoned acquisition cost		30,426			—			30,426		—
Total expenses		156,537			142,296			592,293		409,236
Income before income taxes		253,717			111,213			553,281		240,938
Income tax provision
Current income taxes		12,689			5,197			44,769		14,158
Deferred income taxes		83,480			38,028			163,909		79,609
Net income	$	157,548		$	67,988		$	344,603	$	147,171
Net income per common share — basic	$	0.64		$	0.28		$	1.41	$	0.61
Net income per common share — diluted	$	0.63		$	0.27		$	1.36	$	0.59
Weighted average common shares outstanding
Basic		244,426			240,867			243,604		239,489
Diluted		251,831			250,449			252,708		250,809

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

4

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Cash flow from operating activities:
Net income	$	157,548		$	67,988		$	344,603		$	147,171
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization		56,324			52,797			160,896			140,059
Deferred income taxes		83,480			38,028			163,909			79,609
Deferred revenue — Genesis		(1,201	)		(1,230	)		(3,383	)		(3,252	)
Stock based compensation		3,594			2,820			10,979			8,270
Non-cash fair value derivative adjustments		(86,051	)		5,496			(17,048	)		27,217
Amortization of debt issue costs and other		(2,525	)		877			(2,921	)		2,422
Changes in assets and liabilities related to operations:
Accrued production receivable		33,739			(8,325	)		(10,620	)		(30,395	)
Trade and other receivables		549			(11,351	)		(46,330	)		(23,136	)
Other assets		(81	)		(259	)		188			(405	)
Accounts payable and accrued liabilities		19,511			16,864			9,069			1,363
Oil and gas production payable		(2,680	)		4,077			24,385			13,288
Other liabilities		235			1,432			(956	)		2,600
Net cash provided by operating activities		262,442			169,214			632,771			364,811
Cash flow used for investing activities:
Oil and natural gas capital expenditures		(136,868	)		(170,812	)		(435,871	)		(470,121	)
Acquisitions of oil and gas properties		(1,905	)		1,959			(4,262	)		(44,701	)
Change in accrual for capital expenditures		30,272			4,908			24,273			(3,861	)
Acquisitions of CO2 assets and CO2 capital expenditures		(127,583	)		(33,981	)		(236,433	)		(102,408	)
Distributions from Genesis		2,128			—			4,853			—
Investment in Genesis		—			(28,563	)		(515	)		(28,563	)
Net purchases of other assets		(3,772	)		(3,796	)		(20,703	)		(6,530	)
Net proceeds from sales of oil and gas property and equipment		(81	)		127			48,948			5,967
Other		2,204			(887	)		2,033			(1,847	)
Net cash used for investing activities		(235,605	)		(231,045	)		(617,677	)		(652,064	)
Cash flow from financing activities:
Bank repayments		—			—			(222,000	)		(140,000	)
Bank borrowings		—			60,000			72,000			236,000
Income tax benefit from equity awards		3,219			7,504			17,362			16,344
Pipeline financing — Genesis		63			—			225,311			—
Issuance of subordinated debt		—			—			—			150,750
Issuance of common stock		1,977			4,371			11,687			15,058
Other		(3,795	)		(3,207	)		(4,251	)		(5,358	)
Net cash provided by financing activities		1,464			68,668			100,109			272,794
Net increase (decrease) in cash and cash equivalents		28,301			6,837			115,203			(14,459	)
Cash and cash equivalents at beginning of period		147,009			32,577			60,107			53,873
Cash and cash equivalents at end of period	$	175,310		$	39,414		$	175,310		$	39,414
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	6,962		$	2,980		$	29,959		$	24,329
Cash paid during the period for income taxes		11,720			1,431			70,349			8,801
Interest capitalized		6,713			5,431			19,524			13,785

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

5

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF

COMPREHENSIVE OPERATIONS

(In thousands)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008		2007
Net income	$	157,548	$	67,988		$	344,603	$	147,171
Other comprehensive income, net of income tax:
Change in fair value of derivative contracts designated as a hedge, net of tax of $-, $458, ($49) and $421, respectively		—		(716	)		12		(659	)
Interest rate lock derivative contracts reclassified to income, net of taxes of $11 and $573, respectively		16		—			934		—
Comprehensive income	$	157,564	$	67,272		$	345,549	$	146,512

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

6

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2007. 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 September 30, 2008 and the consolidated results of its operations and cash flows for the three and nine month periods ended September 30, 2008 and 2007. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Stock Split

     On November 19, 2007, stockholders of Denbury Resources Inc. approved an amendment to our Restated Certificate of Incorporation to increase the number of shares of our authorized common stock from 250,000,000 shares to 600,000,000 shares and to split our common stock on a 2-for-1 basis. Stockholders of record on December 5, 2007, received one additional share of Denbury common stock for each share of common stock held at that time. Information pertaining to shares and earnings per share has been retroactively adjusted in the accompanying financial statements and related notes thereto to reflect the stock split.

Net Income Per Common Share

     Basic net income 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 nine month periods ended September 30, 2008 and 2007, there were no adjustments to net income for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three and nine month periods ended September 30, 2008 and 2007.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Share amounts in thousands	2008		2007		2008		2007
Weighted average common shares — basic		244,426		240,867		243,604		239,489
Potentially dilutive securities:
Stock options and SARs		6,035		8,021		7,439		9,877
Restricted stock		1,370		1,561		1,665		1,443
Weighted average common shares — diluted		251,831		250,449		252,708		250,809

     The weighted average common shares – basic amount excludes 2,242,699 shares at September 30, 2008 and 2,702,740 shares at September 30, 2007, of non-vested restricted stock that is subject to future vesting over time. As

7

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant). 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 dilution impact of these shares on our earnings per share calculation may increase in future periods, depending on the market price of our common stock during those periods.

     For the three months ended September 30, 2008 and 2007, stock options and SARs to purchase approximately 1,028,000 and 16,000 shares of common stock, and for the nine months ended September 30, 2008 and 2007, stock options and SARs to purchase approximately 1,011,000 and 173,000 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.

Accounting for Tertiary Injection Costs

     Prior to January 1, 2008, we expensed all costs associated with injecting CO₂ used in our tertiary recovery operations, even though some of these costs were incurred prior to any tertiary related oil production. Commencing January 1, 2008, we began capitalizing, as a development cost, injection costs in tertiary fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO₂ injections (i.e. a production response). These capitalized development costs are included in our unevaluated property costs until we record proved tertiary reserves in that field associated with those costs. After we see a production response to the CO₂ injections (i.e. the production stage), injection costs are expensed as incurred, and any previously deferred development costs included in unevaluated properties become subject to depletion upon recognition of proved tertiary reserves. Since we are continuing to initiate new tertiary floods, this means that we are now capitalizing certain costs that we historically expensed. Had we continued with the prior accounting methodology of expensing all tertiary injectant costs, we would have expensed an additional $2.9 million during the first quarter of 2008, $1.4 million during the second quarter of 2008, and $1.1 million during the third quarter of 2008. During the first nine months of 2007, the impact of this accounting methodology was not material, as only $1.5 million would have been capitalized under the new accounting procedure.

Recently Adopted Accounting Pronouncement

Fair Value Measurements

     During the first quarter of 2008, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with United States generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. On February 12, 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date of SFAS No. 157 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). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. This deferral of SFAS No. 157 applies to our asset retirement obligation (“ARO”), which uses fair value measures at the date incurred to determine our liability. However, we do not expect the adoption of SFAS No. 157 to significantly change the methodology we use to estimate the initial fair value of our ARO, because the guidance in SFAS No. 157 is consistent with the fair value guidance in SFAS No. 143, “Accounting for Asset Retirement Obligations” which we apply to determine our ARO.

     In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.” FSP FAS 157-3 clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued. Revisions resulting from a change in the valuation technique or its application should be accounted for as a change in accounting estimate following the guidance in FASB Statement No. 154, “Accounting Changes and Error Corrections.” FSP FAS 157-3 is effective for the

8

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

financial statements included in the Company’s quarterly report for the period ended September 30, 2008, but had no impact on the Company’s Unaudited Condensed Consolidated Financial Statements.

     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). The Company utilizes 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.

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. During 2008 we had no level 3 recurring measurements.

     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 September 30, 2008.

	Fair Value Measurements at September 30, 2008 Using
			Significant
	Quoted Prices		Other			Significant
	in Active		Observable			Unobservable
	Markets		Inputs			Inputs
Amounts in thousands	(Level 1)		(Level 2)			(Level 3)		Total
Assets:
Oil and natural gas derivative contracts	$	—	$	1,673		$	—	$	1,673
Liabilities:
Oil and natural gas derivative contracts		—		(7,881	)		—		(7,881	)
Total	$	—	$	(6,208	)	$	—	$	(6,208	)

See “Note 6. Derivative Instruments and Hedging Activities” for further information about these contracts.

Recently Issued Accounting Pronouncement

     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

9

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

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 have been applied, and the impact that hedges have on an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for us beginning January 1, 2009. We have not yet determined what impact, if any, this pronouncement will have on our disclosures about derivatives.

Note 2. Oil and Natural Gas Properties Acquisitions and Divestitures

Sale of Louisiana Natural Gas Assets

     In October 2007, we entered into an agreement to sell our Louisiana natural gas assets to a privately held company for approximately $180 million (before closing adjustments), plus we retained a net profits interest in one well. In late December 2007, we closed on approximately 70% of that sale with net proceeds of approximately $108.6 million (including estimated final purchase price adjustments). We closed on the remaining portion of the sale in February 2008 and received net proceeds of approximately $48.9 million. The agreement has an effective date of August 1, 2007, and consequently operating net revenue after August 1, 2007, net of capital expenditures, along with any other minor closing items were adjustments to the purchase price. The potential net profits interest relates to a well in the South Chauvin field and is only earned if operating income from that well exceeds certain levels. The operating results of these sold properties are included in our financial statements through the applicable closing dates of the sold properties. We did not record any gain or loss on the sale in accordance with the full cost method of accounting.

Cancellation of Conroe Field Acquisition

     In August 2008, we entered into an agreement with a privately owned company to purchase a 91.4% interest in Conroe Field, a significant potential tertiary flood north of Houston, Texas, for $600 million, plus additional potential consideration if oil prices were to exceed $121 per barrel during the next three years. Closing was provided for in early October 2008. Based on current capital market conditions, and a desire to refrain from increasing our leverage in the current environment, we cancelled the contract to purchase the Conroe Field, forfeiting a $30 million non-refundable deposit. The $30 million deposit plus miscellaneous acquisition costs of $0.4 million are included in “Abandoned acquisition costs” in our Unaudited Condensed Consolidated Statement of Operations.

Pending Hastings Acquisition

     In September 2008, we exercised our option with a subsidiary of Venoco, Inc. (“Venoco”) to purchase the Hastings Field located near Houston, Texas, a potential tertiary oil field to be supplied by the Green Pipeline which is about to commence construction. The option agreement stipulates that the purchase price is to be determined by mutual agreement between the two companies, or failing agreement by December 1, 2008, by following a prescribed contractual formula based upon the present discounted value (PV10 Value) of the field’s proved reserves as determined by the independent engineering firm DeGoyler MacNaughton, using year-end 2008 strip prices. The acquisition will be effective January 1, 2009 and is expected to close early February 2009. Venoco agreed to extend the deadlines for capital expenditures, commencement of CO₂ injections and certain other contractual requirements by one year in consideration of us exercising the option in 2008 rather than 2009. Since this acquisition will likely be based upon year-end 2008 prices, the purchase price has not yet been determined. Based on commodity prices as of the end of October 2008, the estimated purchase price would be between $150 million and $250 million, assuming that Venoco does not exercise their option to take a volumetric production payment in lieu of a cash payment.

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 obligation 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

10

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

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 nine months ended September 30, 2008.

	Nine Months Ended
Amounts in thousands	September 30, 2008
Balance, beginning of period	$	41,258
Liabilities incurred and assumed during period		1,261
Revisions in estimated retirement obligations		1,483
Liabilities settled during period		(1,928	)
Accretion expense		2,286
Sales of properties		(352	)
Balance, end of period	$	44,008

     At September 30, 2008, $1.1 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 nine month period ended September 30, 2008 are primarily for oil, natural gas and CO₂ wells drilled during the period. 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 was $7.3 million at September 30, 2008 and $9.5 million at December 31, 2007 and are included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets.

Note 4. Long-Term Debt

	September 30,			December 31,
Amounts in thousands	2008			2007
7.5% Senior Subordinated Notes due 2015	$	300,000		$	300,000
Premium on Senior Subordinated Notes due 2015		621			685
7.5% Senior Subordinated Notes due 2013		225,000			225,000
Discount on Senior Subordinated Notes due 2013		(874	)		(1,020	)
NEJD financing — Genesis		174,317			—
Free State financing — Genesis		75,994			—
Senior bank loan		—			150,000
Capital lease obligations — Genesis		4,724			5,238
Capital lease obligations		1,142			1,164
Total		780,924			681,067
Less current obligations		3,932			737
Long-term debt and capital lease obligations	$	776,992		$	680,330

NEJD Financing and Free State Financing

     On May 30, 2008, we closed on two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines. The two transactions have been recorded as financing leases. See “Note 5. Related Party Transactions – Genesis – NEJD Pipeline and Free State Pipeline Transactions.”

11

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Senior Bank Loan

     Effective April 1, 2008, we amended our Sixth Amended and Restated Credit Agreement, the instrument governing our senior bank loan, which increased our borrowing base from $500 million to $1.0 billion. In early October 2008, we further amended our bank credit facility which increased the banks’ commitment amount from $350 million to $750 million and maintained the borrowing base at $1.0 billion. This most recent bank amendment also (i) allowed us to divest of our Barnett Shale properties, (ii) allowed us to do a tax free like-kind exchange of the Barnett Shale properties for Conroe, Hastings and other fields, (iii) allowed for additional permitted indebtedness of up to $600 million in the form of subordinated or convertible debt, and (iv) modified the commitment fees and pricing grid for the loan, raising the pricing grid by 25 basis points.

     With regard to our bank credit facility, the borrowing base represents the amount that can be borrowed from a credit standpoint based on our mortgaged assets, as confirmed by the banks, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request by us in excess of the commitment amount ($750 million), up to the borrowing base limit ($1.0 billion), although the banks are not obligated to fund any amount in excess of the commitment amount. At September 30, 2008, we had no debt outstanding on our bank credit line.

5. Related Party Transactions – Genesis

Interest in and Transactions with Genesis

     Denbury’s subsidiary, Genesis Energy, Inc. is the general partner of, and together with Denbury’s other subsidiaries, owns an aggregate 12% interest in Genesis, a publicly traded master limited partnership. Genesis’ business is focused on the mid stream segment of the oil and 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 $4.9 million and $0.9 million during the nine months ended September 30, 2008 and 2007, respectively. We also received $0.1 million in each of these periods 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, Inc.

NEJD Pipeline and Free State Pipeline Transactions

     On May 30, 2008, we closed two transactions with Genesis involving our Northeast Jackson Dome (NEJD) pipeline system and Free State CO₂ 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 received from Genesis $225 million in cash and $25 million in Genesis common limited partnership units. We used the proceeds to repay our outstanding borrowing on our bank credit facility and the balance we have temporarily invested in cash. We have recorded both of these transactions as financing leases. At September 30, 2008, we had $174.3 million for the NEJD financing and $76.0 million for the Free State financing recorded as debt on our Unaudited Condensed Consolidated Balance Sheet (see “Note 4. Long-Term Debt”).

     The NEJD pipeline system is a 183-mile, 20” pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldsonville, Louisiana, and is currently being used by us to transport CO₂ for our tertiary operations in southwest Mississippi. We have the rights to exclusive use of the NEJD pipeline system, we will be responsible for all operations and maintenance on the system, and we will bear and assume all obligations and liabilities with respect to the pipeline. The NEJD financing lease requires us to make quarterly base rent payments beginning August 30, 2008. These quarterly rent payments are fixed at $5.2 million per quarter or approximately $20.7 million per year (prorated for 2008) during the 20-year term, at an interest rate of approximately 10.25% per annum. At the end of the term, Genesis will release its secured interest in the line to us for $1.00. We have the option or obligation upon the occurrence of certain events specified in the financing lease, and may have the obligation if we default, to prepay our financing lease

12

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

obligations. In the event of significant downgrades of our corporate credit rating by the rating agencies, Genesis can require certain credit enhancements from us, and possibly other remedies under the lease.

     The Free State pipeline is an 86-mile, 20” pipeline that extends from our CO₂ source fields at the Jackson Dome, near Jackson, Mississippi, to our oil fields in east Mississippi. Under the terms of the transportation agreement, Genesis is responsible for owning, operating, maintaining and making improvements to the pipeline. We have exclusive use of the pipeline and are required to use the pipeline to supply CO₂ to certain of our tertiary operations in east Mississippi. The Free State transportation agreement requires us to make monthly payments of $0.1 million plus a through-put fee based on average daily volumes per month with no minimum volumes required. Based on our forecasted through-put, we currently project that we will initially pay Genesis approximately $9.3 million per annum (prorated for 2008). Approximately $1.5 million (increasing at 1% per year) of the annual payments will be expensed as operating costs, with the remainder recognized as principal and interest expense. The implicit rate on the financing is approximately 13.2% per annum.

Oil Sales and Transportation Services

     We utilize Genesis’ trucking services and common carrier pipeline in Mississippi to transport certain of our crude oil production to sales points where it is sold to third party purchasers. In the first nine months of 2008 and 2007, we expensed $5.6 million and $4.4 million, respectively, for these transportation services.

Transportation Leases

     In late 2004 and early 2005, we entered into 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. 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 September 30, 2008, and December 31, 2007, we had $4.7 million and $5.2 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 September 30, 2008 and December 31, 2007, $25.1 million and $28.5 million, respectively, were recorded as deferred revenue of which $4.1 million was included in current liabilities at both September 30, 2008 and December 31, 2007. We recognized deferred revenue for deliveries under these volumetric production payments of $1.2 million during each of the three month periods ended September 30, 2008 and 2007 and $3.4 million and $3.3 million for the nine month periods ended September 30, 2008 and 2007, respectively. We provide Genesis with certain processing and transportation services in connection with these agreements for a fee of approximately $0.18 per Mcf of CO_2. For these services, we recognized revenues of $1.5 million for each of the three month periods ended September 30, 2008 and 2007 and $4.1 million and $3.8 million for the nine months ended September 30, 2008 and 2007, 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 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 (income)” in our Unaudited Condensed Consolidated Statements of Operations.

13

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     The following is a summary of commodity derivative income and expense included in our Unaudited Condensed Consolidated Statements of Operations:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Amounts in thousands	2008			2007			2008			2007
Receipt (payment) on settlements of derivative contracts — Oil	$	(11,186	)	$	(3,018	)	$	(30,709	)	$	(3,999	)
Receipt (payment) of settlements of derivative contracts — Gas		(12,886	)		12,432			(30,005	)		23,383
Fair value adjustments to derivative contracts — income (expense)		86,079			(5,441	)		17,123			(27,269	)
Commodity derivative income (expense)	$	62,007		$	3,973		$	(43,591	)	$	(7,885	)

Oil and Natural Gas Commodity Derivative Contracts at September 30, 2008:

Crude Oil Contracts at September 30, 2008:

						Estimated
						Fair Value Liability
		NYMEX Contract Prices Per Bbl				at September 30, 2008
Type of Contract and Period	Counterparty	Bbls/d		Swap Price		(In Thousands)
Swap Contracts
Oct. 2008 - Dec. 2008	Comerica Bank		2,000		$57.34	$	(7,881	)

Natural Gas Contracts at September 30, 2008:

						Estimated
						Fair Value Asset
		NYMEX Contract Prices Per MMBtu				at September 30, 2008
Type of Contract and Period	Counterparty	MMBtu/d		Swap Price		(In Thousands)
Swap Contracts
Oct. 2008 - Nov. 2008	JPMorgan Chase Bank		20,000	$	7.89	$	529
Oct. 2008 - Nov. 2008	Wells Fargo Bank		20,000		7.91		554
Oct. 2008 - Nov. 2008	Bank of America		20,000		7.94		590

     During September 2008, in anticipation of the possible sale of our Barnett Shale properties, we settled the December 2008 portion of each of our existing natural gas derivative contracts for a net receipt of $61,000. This amount is included in “Commodity derivative expense (income)” in our Unaudited Condensed Consolidated Statement of Operations. At September 30, 2008, our oil and natural gas derivative contracts were recorded at their fair value, which was a net liability of $6.2 million.

     In October 2008, we purchased oil derivative contracts for calendar year 2009 covering 30,000 Bbls/d. These contracts have a floor price of $75 / Bbl and a ceiling price of $115 / Bbl, and were purchased for $15.5 million. These 2009 contracts were entered into with the following counterparties: JPMorgan Chase Bank (10,000 Bbls/d), Wells Fargo Bank (7,500 Bbls/d), Keybank (5,000 Bbls/d), Fortis Energy Marketing and Trading GP (5,000 Bbls/d) and Comerica Bank (2,500 Bbls/d).

Interest Rate Lock Derivative Contracts

     In January 2007, we entered into interest rate lock contracts to remove our exposure to possible interest rate fluctuations related to our commitment to the sale-leaseback financing of certain equipment for CO₂ recycling facilities at our tertiary oil fields. We are applying hedge accounting to these contracts as provided under SFAS No. 133. For these instruments designated as interest rate hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Amounts representing hedge

14

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

ineffectiveness are recorded in earnings. Hedge effectiveness is assessed quarterly based on the total change in the contract’s fair value.

     On June 30, 2008, we settled our remaining interest rate lock contracts for a payment due to the counterparty of approximately $1.6 million. During the second quarter of 2008, we determined that we would not complete the anticipated sale-leaseback transactions which were designated as the forecasted hedged transactions for several of the interest rate lock contracts. As a result, we reclassified the $1.4 million in fair market value changes for these contracts that was in “Accumulated other comprehensive loss” to expense during the second quarter of 2008. We have $0.6 million (net of taxes of $0.4 million) in “Accumulated other comprehensive loss” in our September 30, 2008 Unaudited Condensed Consolidated Balance Sheet. We recognized ineffectiveness totaling $0.1 million as expense in our Unaudited Condensed Consolidated Statement of Operations for the nine months ended September 30, 2008.

Note 7. Income Taxes

     The Company recently obtained approval from the Internal Revenue Service (“IRS”) to change its method of tax accounting for certain assets used in its tertiary oilfield recovery operations. Previously, the Company capitalized and depreciated these costs, but now it can deduct these costs once the assets are placed into service. As a result, the Company expects to receive tax refunds of approximately $10.6 million for tax years through 2007, and in the third quarter of 2008 has reduced its current income tax expense to adjust for the impact of this change. The reduction in current income tax expense has been offset by a corresponding increase in deferred income tax expense of approximately the same amount. Although this change is not expected to have a significant impact on the Company’s overall tax rate, it is anticipated that it will reduce the amount of cash taxes the Company expects to pay over the next several years.

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:

15

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Balance Sheets

	September 30, 2008
	Denbury		Denbury
	Resources Inc.		Onshore, LLC		Other					Denbury
	(Parent and Co-		(Issuer and Co-		Guarantor					Resources Inc.
Amounts in thousands	Obligor)		Obligor)		Subsidiaries		Eliminations			Consolidated
Assets
Current assets	$	472,081	$	427,482	$	18,246	$	(493,401	)	$	424,408
Property and equipment		—		2,860,335		14,293		—			2,874,628
Investment in subsidiaries (equity method)		1,307,870		—		1,251,272		(2,559,142	)		—
Other assets		319,860		110,951		55,796		(317,111	)		169,496
Total assets	$	2,099,811	$	3,398,768	$	1,339,607	$	(3,369,654	)	$	3,468,532
Liabilities and Stockholders’ Equity
Current liabilities	$	11,205	$	756,019	$	31,576	$	(493,401	)	$	305,399
Long-term liabilities		300,621		1,391,477		161		(317,111	)		1,375,148
Stockholders’ equity		1,787,985		1,251,272		1,307,870		(2,559,142	)		1,787,985
Total liabilities and stockholders’ equity	$	2,099,811	$	3,398,768	$	1,339,607	$	(3,369,654	)	$	3,468,532

	December 31, 2007
	Denbury		Denbury
	Resources Inc.		Onshore, LLC		Other					Denbury
	(Parent and Co-		(Issuer and Co-		Guarantor					Resources Inc.
Amounts in thousands	Obligor)		Obligor)		Subsidiaries		Eliminations			Consolidated
Assets
Current assets	$	430,518	$	237,273	$	7,263	$	(434,695	)	$	240,359
Property and equipment		—		2,392,865		10		—			2,392,875
Investment in subsidiaries (equity method)		961,990		—		905,796		(1,867,786	)		—
Other assets		312,556		78,230		57,226		(310,169	)		137,843
Total assets	$	1,705,064	$	2,708,368	$	970,295	$	(2,612,650	)	$	2,771,077
Liabilities and Stockholders’ Equity
Current liabilities	$	—	$	691,062	$	8,266	$	(434,695	)	$	264,633
Long-term liabilities		300,686		1,111,510		39		(310,169	)		1,102,066
Stockholders’ equity		1,404,378		905,796		961,990		(1,867,786	)		1,404,378
Total liabilities and stockholders’ equity	$	1,705,064	$	2,708,368	$	970,295	$	(2,612,650	)	$	2,771,077

16

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2008
	Denbury			Denbury
	Resources Inc.			Onshore, LLC		Other					Denbury
	(Parent and Co-			(Issuer and Co-		Guarantor					Resources Inc.
Amounts in thousands	Obligor)			Obligor)		Subsidiaries		Eliminations			Consolidated
Revenues	$	5,625		$	407,823	$	2,431	$	(5,625	)	$	410,254
Expenses		5,745			155,578		839		(5,625	)		156,537
Income (loss) before the following:		(120	)		252,245		1,592		—			253,717
Equity in net earnings of subsidiaries		157,658			—		156,791		(314,449	)		—
Income before income taxes		157,538			252,245		158,383		(314,449	)		253,717
Income tax provision (benefit)		(10	)		95,454		725		—			96,169
Net income	$	157,548		$	156,791	$	157,658	$	(314,449	)	$	157,548

	Three Months Ended September 30, 2007
	Denbury			Denbury
	Resources Inc.			Onshore, LLC		Other						Denbury
	(Parent and Co-			(Issuer and Co-		Guarantor						Resources Inc.
Amounts in thousands	Obligor)			Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	5,625		$	253,316	$	193		$	(5,625	)	$	253,509
Expenses		5,750			141,539		632			(5,625	)		142,296
Income (loss) before the following:		(125	)		111,777		(439	)		—			111,213
Equity in net earnings of subsidiaries		68,505			—		68,996			(137,501	)		—
Income before income taxes		68,380			111,777		68,557			(137,501	)		111,213
Income tax provision		392			42,781		52			—			43,225
Net income	$	67,988		$	68,996	$	68,505		$	(137,501	)	$	67,988

17

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations (continued)

	Nine Months Ended September 30, 2008
	Denbury			Denbury
	Resources Inc.			Onshore, LLC		Other					Denbury
	(Parent and Co-			(Issuer and Co-		Guarantor					Resources Inc.
Amounts in thousands	Obligor)			Obligor)		Subsidiaries		Eliminations			Consolidated
Revenues	$	16,875		$	1,142,285	$	3,289	$	(16,875	)	$	1,145,574
Expenses		17,236			589,461		2,471		(16,875	)		592,293
Income (loss) before the following:		(361	)		552,824		818		—			553,281
Equity in net earnings of subsidiaries		344,933			—		345,045		(689,978	)		—
Income before income taxes		344,572			552,824		345,863		(689,978	)		553,281
Income tax provision (benefit)		(31	)		207,779		930		—			208,678
Net income	$	344,603		$	345,045	$	344,933	$	(689,978	)	$	344,603

	Nine Months Ended September 30, 2007
	Denbury			Denbury
	Resources Inc.			Onshore, LLC		Other						Denbury
	(Parent and Co-			(Issuer and Co-		Guarantor						Resources Inc.
Amounts in thousands	Obligor)			Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	13,969		$	649,927	$	247		$	(13,969	)	$	650,174
Expenses		14,300			406,985		1,920			(13,969	)		409,236
Income (loss) before the following:		(331	)		242,942		(1,673	)		—			240,938
Equity in net earnings of subsidiaries		147,884			—		149,566			(297,450	)		—
Income before income taxes		147,553			242,942		147,893			(297,450	)		240,938
Income tax provision		382			93,376		9			—			93,767
Net income	$	147,171		$	149,566	$	147,884		$	(297,450	)	$	147,171

18

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2008
	Denbury			Denbury
	Resources Inc.			Onshore, LLC			Other						Denbury
	(Parent and Co-			(Issuer and Co-			Guarantor						Resources Inc.
Amounts in thousands	Obligor)			Obligor)			Subsidiaries			Eliminations			Consolidated
Cash flow from operations	$	(10	)	$	622,674		$	10,107		$	—		$	632,771
Cash flow from investing activities		(25,344	)		(612,064	)		(5,613	)		25,344			(617,677	)
Cash flow from financing activities		25,344			100,109			—			(25,344	)		100,109
Net increase (decrease) in cash		(10	)		110,719			4,494			—			115,203
Cash, beginning of period		34			58,343			1,730			—			60,107
Cash, end of period	$	24		$	169,062		$	6,224		$	—		$	175,310

	Nine Months Ended September 30, 2007
	Denbury			Denbury
	Resources Inc.			Onshore, LLC			Other					Denbury
	(Parent and Co-			(Issuer and Co-			Guarantor					Resources Inc.
Amounts in thousands	Obligor)			Obligor)			Subsidiaries		Eliminations			Consolidated
Cash flow from operations	$	33		$	364,108		$	670	$	—		$	364,811
Cash flow from investing activities		(177,291	)		(652,064	)		—		177,291			(652,064	)
Cash flow from financing activities		177,291			272,794			—		(177,291	)		272,794
Net increase (decrease) in cash		33			(15,162	)		670		—			(14,459	)
Cash, beginning of period		1			52,225			1,647		—			53,873
Cash, end of period	$	34		$	37,063		$	2,317	$	—		$	39,414

Note 9. Subsequent Events

     In October 2008, we amended our bank credit facility which, among other things, increased the commitment amount on our bank credit facility from $350 million to $750 million. See “Note 4. Long Term Debt” for a complete description of this amendment.

     In October 2008, we purchased oil derivative contracts for calendar year 2009. See “Note 6. Derivative Instruments and Hedging Activities” for further information about these contracts.

19

DENBURY RESOURCES INC.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     You should read the following in conjunction with our financial statements contained herein and our Form 10-K for the year ended December 31, 2007, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K.

     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 carbon dioxide (“CO₂”) reserves east of the Mississippi River used for tertiary oil recovery, and hold significant operating acreage in the Barnett Shale play near Fort Worth, Texas, onshore Louisiana and Alabama, and properties in Southeast Texas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, including secondary and tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have four primary field offices located in Laurel, Mississippi; McComb, Mississippi; Jackson, Mississippi; and Cleburne, Texas.

Overview

     Operating Results. During the third quarter of 2008 our production averaged 45,913 BOE/d, a 13% increase over third quarter 2007 production after adjusting for the sale of our Louisiana natural gas properties in December 2007 and February 2008, and approximately the same as second quarter 2008 production levels. The third quarter 2008 production was negatively impacted by two hurricanes, reducing our targeted third quarter 2008 production by approximately 1,250 BOE/d. In spite of the hurricanes, our tertiary oil production increased to 19,784 Bbls/d, a 1,123 Bbls/d sequential increase over its level in the second quarter of 2008, but production from our second largest production area, the Barnett Shale, decreased sequentially to 12,339 BOE/d, a 1,095 BOE/d decrease, primarily as a result of the hurricanes. (See “Results of Operations — Operating Results — Production” for more information about the impact of the two hurricanes).

     Commodity prices began to decline during the third quarter of 2008, down only 3% on an average per BOE quarterly basis from second quarter of 2008 levels, although commodity prices were significantly lower by quarter-end. However, average prices for the third quarter were still 61% higher on a per BOE basis than prices received during the third quarter of 2007. During the period of rising commodity prices in the first six months of 2008, we recognized non-cash fair value losses on our oil and natural gas derivative contracts of $68.9 million, but more than reversed that loss when prices declined in the third quarter of 2008, during which we recognized non-cash fair value income of $86.1 million on those same contracts. During the third quarter of 2008, we made cash payments of $24.1 million on our derivative contracts, in addition to the $36.6 million paid during the first six months of 2008. This compares to a $27.3 million non-cash fair value charge on our derivative contracts in the nine month period of 2007 and net cash receipts of $19.4 million on those contracts during that same period. On a comparative quarterly basis, during the third quarter of 2007, we recognized non-cash fair value losses of $5.4 million and had net cash receipts of $9.4 million.

     Virtually all of our expenses increased on both an absolute and per BOE basis during the third quarter of 2008, due to (i) higher overall industry costs, (ii) a higher percentage of operations related to tertiary operations (which have higher operating costs per BOE), and (iii) higher compensation expense resulting from additional employees and increased salaries, which we consider necessary in order to remain competitive in the industry. In addition, the sale of our Louisiana natural gas properties in late 2007 and early 2008, which had lower operating costs per BOE, increased our operating cost per BOE by over $1.00, based on 2007 average costs. Interest expense increased in the third quarter of 2008 primarily as a result of the incremental interest on the financing leases relating to the CO₂ pipeline transactions with Genesis in May 2008 (see “Genesis Transactions” below). During the third quarter of 2008 we also recognized a $30.4 million charge primarily relating to a deposit we forfeited when we decided not to close the Conroe Field acquisition (see “Capital Resources and Liquidity” below). The net result was net income of $157.5 million during the third quarter of 2008, a company quarterly record, as compared to $68.0 million of net income during the third quarter of 2007. On a nine month basis, net income was $344.6 million during the first nine months of 2008, as compared to net income of $147.2 million during the first nine months of 2007, as higher commodity prices and production and non-cash fair value income from commodity derivatives in 2008 more than offset the higher expenses.

20

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     Acquisition and Sale Update. See “Capital Resources and Liquidity” for information about the cancelled acquisition of Conroe Field, the pending acquisition of Hastings Field and changes in the likelihood of our being able to sell our Barnett Shale properties.

     Overview of Tertiary Operations. Oil production from our tertiary operations increased to an average of 19,784 BOE/d in the third quarter of 2008, a 23% increase over the third quarter 2007 tertiary production level of 16,101 BOE/d and a 6% increase over our second quarter 2008 tertiary production level, even though our third quarter 2008 average was reduced by approximately 550 Bbls/d as a result of production deferred due to two hurricanes. For a further discussion, see the section entitled “CO₂ Operations” below and contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2007 Form 10-K.

     Increased Bank Credit Line. In early October 2008, we amended our bank credit facility, which increased the banks’ commitment amount from $350 million to $750 million and maintained our borrowing base at $1.0 billion. The borrowing base represents the amount that can be borrowed from a credit standpoint while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement.

     The bank amendment also (i) allowed us to divest of our Barnett Shale properties, (ii) allowed us to do a tax free like-kind exchange of the Barnett Shale properties for Conroe, Hastings and other fields, (iii) allowed for additional permitted indebtedness of up to $600 million in the form of subordinated or convertible debt, and (iv) modified the commitment fees and pricing grid for the loan, raising the pricing grid by 25 basis points. At the present time, we have decided not to pursue the issuance of any additional subordinated or convertible debt, and we believe that the sale of the Barnett Shale properties is doubtful in the current market which means it is unlikely that we will enter into a tax free like-kind exchange (see “Capital Resources and Liquidity”).

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

     Change in Tax Accounting Method for Certain Tertiary Costs. During the third quarter, we obtained approval from the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. Previously, we had capitalized and depreciated these costs, but now we can deduct these costs once the assets are placed into service. As a result, we expect to receive tax refunds of approximately $10.6 million for tax years through 2007 and we have reduced our estimated current income tax for 2008 to adjust for the impact of this change. The reduction in current income tax expense has been offset by a corresponding increase in deferred income tax expense of approximately the same amount. This change is not expected to have a significant impact on our overall tax rate; however, we expect that it will reduce the amount of cash taxes we will pay over the next several years.

     Our acceleration of tax deductions and resultant lower current cash income taxes will change the overall economics of certain financing-type transactions we have historically utilized, primarily equipment lease financing and certain transactions with Genesis (see paragraph below). For several years, we have entered into seven or ten year operating leases for certain equipment used in our tertiary production facilities. Through June 30, 2008, we had leased approximately $104.5 million of such equipment and had anticipated leasing additional equipment during 2008. In order to fully take advantage of the change in tax accounting, we have discontinued this leasing program, which is estimated to increase our 2008 capital budget by approximately $78 million, with the offset being a reduction of future lease operating expenses. However, if commodity prices remain low and capital resources remain limited, we may resume this leasing program in 2009 by leasing up to $100 million in equipment during the year, assuming that we can obtain lease financing on a favorable basis.

21

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The economic impact of our acceleration of tax deductions will also likely lead us to eliminate certain types of future asset “drop-downs” to Genesis. Transactions which are not sales for tax purposes, such as the recent $175 million financing lease on the NEJD CO₂ Pipeline (see “Overview — Genesis Transactions” above) would not be affected provided that they meet other necessary tax structuring criteria. Those transactions which constitute a sale for tax purposes, such as the recent $75 million sale and associated long-term transportation service agreement entered into with Genesis on our Free State CO₂ Pipeline (see “Overview - Genesis Transactions” above), are likely to be discontinued.

     Sale of Louisiana Natural Gas Assets. We completed the remaining 30% of the sale of our Louisiana natural gas assets in February 2008 with additional proceeds received at that time of approximately $48.9 million, the prior 70% of which closed in December 2007. Production attributable to the sold properties averaged 302 BOE/d (approximately 81% natural gas) during the first quarter of 2008, representing the production prior to the closing date for the portion of the sale that closed in February. Production attributable to the sold properties averaged approximately 30.6 MMcfe/d (82% natural gas) during the fourth quarter of 2007, representing approximately 10% of our total fourth quarter production and approximately 4% of our total proved reserve quantities as of December 31, 2006.

Capital Resources and Liquidity

     In early October 2008, we announced several steps we had taken to improve our liquidity as a result of current conditions in the capital markets. These included an increase to our bank commitment amount as discussed above (see “Overview — Increased Bank Credit Line”), cancellation of the $600 million acquisition of Conroe Field, purchase of oil derivative contracts covering approximately 75% to 80% of our currently estimated 2009 oil production, and reduction of our capital budget for 2009.

     Prior to the recent decline in economic conditions we were intending to do a tax free exchange of the Barnett Shale properties for Conroe Field and Hastings Field, both future tertiary flood candidates located near Houston, Texas. However, because of the current capital market conditions, we believe that the sale of our Barnett Shale properties at a price that we would consider reasonable is doubtful, and without the certainty of a Barnett Shale property sale, we did not feel comfortable increasing our leverage in the current environment. As such, we cancelled our contract to purchase Conroe Field for $600 million, forfeiting a $30 million non-refundable deposit. To further protect our liquidity in the event that commodity prices continue to decline, we purchased oil derivative contracts for 2009 with a floor price of $75 / Bbl and a ceiling price of $115 / Bbl for total consideration of $15.5 million. The collars cover 30,000 Bbls/d representing between 75% and 80% of our currently anticipated 2009 oil production including anticipated production from Hastings Field, but excluding any liquid production from our Barnett Shale assets.

     In September 2008, we exercised our option with a subsidiary of Venoco, Inc. (“Venoco”) to purchase the Hastings Field located near Houston, Texas, a potential tertiary oil field to be supplied by the Green Pipeline which is about to commence construction. The purchase price is to be determined by mutual agreement between the two companies, or failing agreement by December 1, 2008, by following a prescribed contractual formula based upon the present discounted value (PV10 Value) of the field’s proved reserves as determined by the independent engineering firm of DeGolyer and MacNaughton, using year-end 2008 strip prices. The acquisition will be effective January 1, 2009 and is expected to close in early February 2009. Venoco agreed to extend the deadlines for capital expenditures, commencement of CO₂ injections and certain other contractual requirements by one year in consideration of us exercising the option in 2008 rather than 2009. Since this acquisition will likely be based upon year-end prices, we are not sure what the purchase price will be. Based on commodity prices as of the end of October 2008, the estimated purchase price is between $150 million and $250 million, assuming that Venoco does not exercise its option to take a volumetric production payment in lieu of a cash payment.

     We currently estimate that our 2008 total capital spending will be between $900 million and $950 million, less than our current budget of $1.0 billion, although a portion of these costs will be carried over into 2009. When we announced our preliminary 2009 capital budget of $825 million in early October, that budget did not include any expenditures for the Barnett Shale (as it was presumed that these properties would have been sold), nor did it consider any possible carryover items from 2008. If such items were included, the total capital budget would be almost $1.0 billion. In light of the continued lack of liquidity in the capital markets and the further deterioration of commodity prices, we have further revised our all inclusive 2009 capital budget downward by $250 million to $750 million. The revised 2009 capital

22

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

budget retains approximately $485 million relating to our CO₂ pipelines, the majority of which is for the Green Pipeline. The budget also assumes that we fund approximately $100 million of the budgeted equipment purchases with operating leases, a practice we had discontinued a few months ago as a result of our favorable tax ruling (see “Overview — Change in Tax Accounting Method for Certain Tertiary Costs”). Use of these operating leases is subject to locating acceptable financing, which we do not have at this time. The revised budget incorporates significantly reduced spending in the Barnett Shale and in other conventional areas such as the Heidelberg Selma Chalk, and a slower development program for our tertiary operations. Based on our current cash flow projections, using $65.00 per barrel oil and $6.50 per Mcf natural gas prices, we anticipate that our capital expenditures could exceed projected cash flow by $150 million to $200 million, excluding any acquisitions. We anticipate funding this shortfall during 2009, along with the pending Hastings acquisition, with our bank credit line, which currently has $750 million of availability. We monitor our capital expenditures on a regular basis, adjusting them up or down depending on commodity prices and the resultant cash flow. Therefore, should our cash flow be less than expected, we would plan to reduce our capital expenditures to the extent possible during the year, which could in turn, have the impact of reducing our anticipated production levels in future years. For 2009, we have contracted for certain capital expenditures, including a portion of the Green Pipeline and two drilling rigs, but estimate that we could eliminate approximately $344 million of our 2009 projected expenditures if necessary without penalty (see also “Off-Balance Sheet Arrangements — Commitments and Obligations”) and, if necessary, an additional $332 million (relating to the Green Pipeline) could be eliminated, subject to an estimated penalty of $26 million.

     Based on our long-term models and assuming only the properties that we currently own, we expect our future capital spending to decrease significantly in 2010 from 2008 and 2009 levels. Therefore, even if commodity prices remain at current levels after 2009, we anticipate that we will be able to match our capital spending with our projected cash flow from operations in order to preserve our liquidity as necessary, although any spending reductions from our current long-term plans would likely lower our anticipated rate of production growth.

     As part of our recent bank amendment (see “Overview — Increased Bank Credit Line”), our bank borrowing base was reaffirmed at $1.0 billion. This borrowing base is higher than our current bank commitment of $750 million and assumed that our Barnett Shale properties were to be sold and that we would issue an additional $600 million in subordinated or convertible debt. While bank borrowing bases are likely to be reduced in the future to reflect the recent reduction in commodity prices, with the $250 million cushion between our borrowing base and commitment amount and the incremental value added by retaining our Barnett Shale properties (which are not expected to be sold at this time), we do not expect our bank commitment level to be reduced below $750 million unless prices were to further decrease significantly from current prices of approximately $65.00 per barrel for oil and $6.50 per Mcf for natural gas. As of October 31, 2008, we had outstanding $525 million (principal amount) of subordinated notes and no bank debt and approximately $75 million of cash on hand.

     We continue to pursue acquisitions of mature oil fields that we believe have potential as future tertiary flood candidates, although with the general lack of liquidity in the capital markets, we currently have no plans to make any significant acquisitions until capital is more readily available, other than the Hastings Field as previously discussed.

23

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Sources and Uses of Capital Resources

	Nine Months Ended
	September 30,
Amounts in thousands	2008		2007
Capital expenditures
Oil and natural gas exploration and development
Drilling	$	186,249	$	248,718
Geological, geophysical and acreage		14,084		16,624
Facilities		117,423		89,372
Recompletions		104,476		102,490
Capitalized interest		13,639		12,917
Total oil and gas exploration and development expenditures		435,871		470,121
Oil and natural gas property acquisitions		4,262		44,701
Total oil and natural gas capital expenditures		440,133		514,822
CO2 capital expenditures, including capitalized interest		236,433		102,408
Total	$	676,566	$	617,230

     Our capital expenditures for the first nine months of 2008 were funded with $632.8 million of cash flow from operations, $225 million from the drop-down of CO₂ pipelines to Genesis, and $48.9 million of proceeds from the second closing on our Louisiana property sale. The excess cash generated from these sources was used to repay our outstanding bank debt of $150 million, while the remainder of this excess increased our cash balances.

     Our 2007 capital expenditures were funded with $364.8 million of cash flow from operations, $150.0 million from our issuance of subordinated debt in April 2007, $96.0 million of net bank borrowings, and the balance funded with working capital.

Off-Balance Sheet Arrangements

Commitments and Obligations

     Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in the proved reserve reports. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Note 6 to the Unaudited Condensed Consolidated Financial Statements.

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

     During the second quarter of 2008, we entered into a long-term commitment to purchase manufactured CO₂ from a proposed gasification plant in Kentucky proposed by Cash Creek Generation LLC and cancelled a contract we had executed for a proposed facility in Beaumont which we do not expect to be constructed. The plant proposed by Cash Creek is not only conditioned on that plant being built, but also upon Denbury contracting additional volumes of CO₂ for purchase in the general area of the proposed plant which aggregate 600 MMcf/d in order to justify the cost of a CO₂ pipeline. Both the new contract and the cancelled contract called for production of approximately 200 MMcf/d of CO₂ and the delivered price of CO₂ in both contracts is similar. If this most recently proposed plant and the other two

24

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

proposed plants are built, the aggregate purchase obligation for CO₂ from our contracted potential synthetic sources could be up to $150 million per year, assuming a $75 per barrel oil price and comparable compression levels, before any potential savings from our share of any carbon emissions credits enacted. All of the contracts have price adjustments that fluctuate based on the price of oil. Construction has not yet commenced on any of these plants, and their construction is contingent on the satisfactory resolution of various issues, including financing. While it is possible that not every plant currently under contract will be built, there are several other plants under consideration that may be built and concerning which we are having ongoing negotiations. These amounts were not included in the commitment table included in our Form 10-K as these payments are contingent on the plants being built.

     During the third quarter of 2008, we exercised our option to purchase Hastings Field (see “Capital Resources and Liquidity — Pending Hastings Acquisition”). The purchase price for this acquisition is not yet known as it will be based upon commodity prices as of December 31, 2008, but based on prices as of the end of October 2008, the purchase price is estimated to be between $150 million and $250 million.

     We have committed to certain contracts relating to the construction of our proposed Green Pipeline being built from Louisiana to Texas with an aggregate of approximately $389 million which is expected to be incurred during 2009 under these contracts. We can eliminate $332 million of these contracts if necessary, subject to an estimated penalty of $26 million.

     Neither the amounts nor the terms of any other commitments or contingent obligations have changed significantly from the year-end 2007 amounts reflected in our Form 10-K filed in February 2008, except for the transactions with Genesis noted above. Please refer to the “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Off-Balance Sheet Arrangements-Commitments and Obligations” contained in our 2007 Form 10-K for further information regarding our commitments and obligations.

Results of Operations

CO₂ Operations

     Our focus on CO₂ operations is becoming an ever-increasing part of our business and operations. We believe that there are significant additional oil reserves and production that can be obtained through the use of CO₂, and we have outlined certain of this potential in our annual report and other public disclosures. In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results. Please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the section entitled “CO₂ Operations” contained in our 2007 Form 10-K for further information regarding these matters.

     During the remainder of 2008 and 2009, we plan to drill five additional CO₂ source wells to further increase our production capacity and reserves. We estimate that we are currently capable of producing between 750 MMcf/d and 850 MMcf/d of CO₂, but anticipate this increasing to almost 1 Bcf/d by year-end 2008. During the third quarter of 2008, our CO₂ production averaged 630 MMcf/d, as compared to an average of approximately 596 MMcf/d during the second quarter of 2008, and average production of 593 MMcf/d during the first nine months of 2008. We used 85% of this production, or 507 MMcf/d, in our tertiary operations during the first nine months of 2008, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.

     Oil production from our tertiary operations increased to an average of 19,784 BOE/d in the third quarter of 2008, a 23% increase over the third quarter 2007 tertiary production level of 16,101 BOE/d and a 6% increase over the second quarter 2008 tertiary production level of 18,661 BOE/d, even though our third quarter 2008 average was reduced by approximately 550 Bbls/d as a result of production deferred (primarily in our Phase I properties) because of two hurricanes (see further discussion about the impact of the two hurricanes under “Results of Operations — Operating Results — Production”).

     The table below shows our tertiary oil production by field for the first three quarters of 2008 and all four quarters of 2007. We saw our initial production from Tinsley Field (Phase III) in the second quarter of 2008, with tertiary production there averaging 675 Bbls/d during the second quarter and increasing to 1,518 Bbls/d during the third quarter. As a result

25

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

of this production response to our CO₂ injections, we recognized approximately 29.8 MMBbls of proved reserves at Tinsley Field in the second quarter of 2008, although we do not believe that these proved reserve quantities represent the total ultimate reserves we expect to recover from this field with tertiary operations. During the third quarter of 2008, we had our initial production from Lockhart Crossing Field, and correspondingly recognized approximately 4.2 MMBbls of proved reserves at this field in the third quarter. The majority of the remaining production increase came from our Phase II operations in eastern Mississippi (Soso, Eucutta and Martinville Fields) which contributed 2,394 BOE/d (approximately two-thirds) to the increase over the prior year’s third quarter production.

	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First		Second		Third
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Tertiary Oil Field	2007		2007		2007		2007		2008		2008		2008
Phase I:
Brookhaven		1,422		1,794		2,452		2,507		2,638		2,714		2,772
Little Creek area		2,117		1,974		2,011		1,957		1,807		1,661		1,556
Mallalieu area		5,470		5,802		5,823		6,304		6,099		6,260		5,339
McComb area		1,811		1,884		1,853		2,096		1,632		1,818		2,061
Lockhart Crossing		—		—		—		—		—		—		182
Phase II:
Martinville		320		521		1,101		883		793		715		736
Eucutta		614		1,338		2,035		2,572		2,699		2,933		3,262
Soso		25		370		826		1,109		1,488		1,885		2,358
Phase III:
Tinsley		—		—		—		—		—		675		1,518
Total tertiary oil production		11,779		13,683		16,101		17,428		17,156		18,661		19,784

     We spent approximately $0.25 per Mcf to produce our CO₂ during the first nine months of 2008, an increase over our average for the first nine months of 2007 of $0.21 per Mcf. On a quarterly basis, we spent approximately $0.26 per Mcf to produce our CO₂ during the third quarter of 2008, down slightly from the $0.27 per Mcf spent in the second quarter of 2008, as compared to $0.23 per Mcf in the third quarter of 2007, with the higher cost in the 2008 period due to higher operating costs and higher oil costs which impacts the amount we pay royalty owners for the CO₂. Our estimated total cost per thousand cubic feet of CO₂ during the first nine months of 2008 was approximately $0.33, after inclusion of depreciation and amortization expense, higher than the 2007 nine month average of $0.29 per Mcf. Our estimated total cost per thousand cubic feet of CO₂ during the third quarter of 2008 was approximately $0.35, after inclusion of depreciation and amortization expense.

     Since the most significant component of our operating cost, the cost of CO_2, has significantly increased along with oil prices as outlined above, and the second largest component of our tertiary operating expenses, power and fuel, also generally follow the same trend as commodity prices, our operating costs per BOE for our tertiary properties have generally increased during the last couple of years. While commodity prices trended down during the third quarter of 2008, average oil prices were only slightly less in the third quarter of 2008 than in the second quarter of 2008. We would expect to see some savings on operating costs commencing in the fourth quarter of 2008, assuming commodity prices remain low or continue to decrease. During the third quarter of 2008, we spent approximately $12.6 million on CO₂, or approximately $6.95 per tertiary barrel of oil, and spent approximately $10.4 million on power and fuel, or approximately $5.69 per tertiary barrel of oil.

     Higher rental lease payments on equipment that we have historically leased (see “Overview — Change in Tax Accounting Method for Certain Tertiary Costs” regarding future leasing activities) and rising labor costs also contributed to escalating costs, although the timing of new floods and field production levels can also have a significant impact on the per BOE amounts. During the third quarter of 2008, we also incurred an incremental $4.0 million (approximately $2.20 per tertiary barrel of oil) in workover costs, primarily related to remedial well work to repair tubing at Eucutta Field. Operating costs per BOE on our tertiary operations averaged $20.81, $24.67, and $26.81 during the first, second, and third quarters of 2008 as compared to $20.27, $20.47, and $18.65 during the first, second and third quarters of 2007,

26

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

respectively. Operating costs on our tertiary operations averaged $19.71 per BOE during the first nine months of 2007 as compared to $24.25 per BOE during the first nine months of 2008.

     Prior to January 1, 2008, we expensed all costs associated with injecting CO₂ used in our tertiary recovery operations, even though some of these costs were incurred prior to any tertiary related oil production. Commencing January 1, 2008, we began capitalizing, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO₂ injections (i.e. a production response). These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO₂ injections (i.e. the production stage), injection costs will be expensed as incurred, and any previously deferred unevaluated development costs will become subject to depletion upon recognition of proved tertiary reserves. Since we are continuing to initiate new tertiary floods, this means that we are now capitalizing certain costs that we historically expensed. Had we continued with the prior accounting methodology of expensing all tertiary injection costs, we would have expensed an additional $2.9 million or $1.84 per BOE (tertiary properties only) during the first quarter of 2008, as there were injection costs during the period in new tertiary floods without tertiary related oil production, primarily in the two new tertiary floods at Tinsley and Lockhart Crossing Fields. The amount of capitalized injection costs that we historically would have expensed was reduced during the second quarter of 2008 as we began to expense the injection costs at Tinsley Field when we commenced tertiary oil production in April, which contributed to the rise in operating costs per BOE between the first and second quarters of 2008. During the third quarter of 2008, we began to expense the CO₂ injection costs at Lockhart Crossing Field when we commenced tertiary oil production in July of 2008. In the third quarter of 2008, we would have expensed an additional $1.1 million or $0.62 per BOE (tertiary properties only) had we followed our prior year’s accounting methodology. During the first nine months of 2007, the accounting methodology was not material, as only $1.5 million would have been capitalized under the new accounting procedure.

Operating Results

     As summarized in the “Overview” section above and discussed in more detail below, for the third quarter of 2008, higher production, higher commodity prices and non-cash fair value income adjustments for commodity derivative contracts more than offset overall higher expenses, resulting in record quarterly earnings and a quarterly record cash flow from operations. On a nine month basis, the same trend applied, resulting in significant increases in our operating results.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Amounts in thousands, except per share amounts	2008		2007		2008		2007
Net income	$	157,548	$	67,988	$	344,603	$	147,171
Net income per common share — basic		0.64		0.28		1.41		0.61
Net income per common share — diluted		0.63		0.27		1.36		0.59
Cash flow from operations		262,442		169,214		632,771		364,811

     Certain of our operating results and statistics for the comparative third quarters and first nine months of 2008 and 2007 are included in the following table:

27

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Average daily production volumes
Bbls/d		31,078			28,680			30,859			26,319
Mcf/d		89,009			102,239			89,087			94,129
BOE/d (1)		45,913			45,720			45,707			42,007
Operating revenues (in thousands)
Oil sales	$	321,965		$	190,685		$	899,368		$	459,995
Natural gas sales		80,143			57,528			229,180			174,831
Total oil and natural gas sales	$	402,108		$	248,213		$	1,128,548		$	634,826
Oil and gas derivative contracts (2) (in thousands)
Cash receipt (payment) on settlements of derivative contracts	$	(24,072	)	$	9,414		$	(60,714	)	$	19,384
Non-cash fair value adjustment income (expense)		86,079			(5,441	)		17,123			(27,269	)
Total income (expense) from oil and gas derivative contracts	$	62,007		$	3,973		$	(43,591	)	$	(7,885	)
Operating expenses (in thousands)
Lease operating expenses	$	85,308		$	59,323		$	228,134		$	167,087
Production taxes and marketing expenses (3)		19,335			12,676			56,601			33,266
Total production expenses	$	104,643		$	71,999		$	284,735		$	200,353
Non-tertiary CO2 operating margin (in thousands)
CO2 sales and transportation fees (4)	$	3,471		$	3,594		$	9,705		$	10,079
CO2 operating expenses		(1,240	)		(1,304	)		(2,836	)		(3,211	)
Non-tertiary CO2 operating margin	$	2,231		$	2,290		$	6,869		$	6,868
Unit prices — including impact of derivative settlements (2)
Oil price per Bbl	$	108.70		$	71.12		$	102.74		$	63.46
Gas price per Mcf		8.21			7.44			8.16			7.71
Unit prices — excluding impact of derivative settlements (2)
Oil price per Bbl	$	112.61		$	72.27		$	106.37		$	64.02
Gas price per Mcf		9.79			6.12			9.39			6.80
Oil and gas operating revenues and expenses per BOE (1)
Oil and natural gas revenues	$	95.20		$	59.01		$	90.11		$	55.36
Oil and gas lease operating expenses	$	20.20		$	14.10		$	18.22		$	14.57
Oil and gas production taxes and marketing expense		4.58			3.01			4.52			2.90
Total oil and gas production expenses	$	24.78		$	17.11		$	22.74		$	17.47

(1)	Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of natural gas (“BOE”).
(2)	See also “Market Risk Management” below for information concerning the Company’s derivative transactions.
(3)	Includes “Transportation expense — Genesis.”
(4)	Includes deferred revenue of $1.2 million for each of the three months ended September 30, 2008 and 2007, and $3.4 million and $3.3 million for the nine months ended September 30, 2008 and 2007, respectively, associated with a volumetric production payment with Genesis. Includes transportation income from Genesis of $1.5 million for each of the three months ended September 30, 2008 and 2007, and $4.1 million and $3.8 million for the nine months ended September 30, 2008 and 2007, respectively.

28

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     Production: Production by area for each of the quarters of 2007 and the first, second, and third quarters of 2008 is listed in the following table.

	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First		Second		Third
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Operating Area	2007		2007		2007		2007		2008		2008		2008
Mississippi — CO2 floods		11,779		13,683		16,101		17,428		17,156		18,661		19,784
Mississippi — non - CO2 floods		12,738		12,525		12,131		12,530		12,128		11,617		11,694
Texas		6,989		9,048		10,695		13,488		13,522		14,068		12,701
Onshore Louisiana		5,591		5,391		5,546		5,638		905		663		512
Alabama and other		1,208		1,269		1,247		1,287		1,189		1,296		1,222
Total Company		38,305		41,916		45,720		50,371		44,900		46,305		45,913

     While we suffered minimal physical damage as a result of Hurricanes Gustav and Ike, we did shut-in and defer production during the third quarter of 2008 as a result of each of these storms. During Hurricane Gustav, we temporarily lost electrical power at most of our Phase I tertiary oil floods in Southwest Mississippi and as a result of Hurricane Ike, over half of our Barnett Shale production was temporarily shut-in as refineries on the Gulf Coast were unable to accept natural gas liquids production from the Barnett. We estimate that our total deferred tertiary oil production as a result of the two hurricanes ranged between 45,000 and 55,000 Bbls (approximately 550 Bbls/d for the third quarter estimated daily production using the mid-point of the estimate) and that our total deferred production was between 110,000 and 120,000 BOEs (approximately 1,250 BOE/d for the third quarter daily production using the mid-point of the estimate).

     As outlined in the above table, adjusting for the impact of the deferred production as a result of the two hurricanes discussed above and the sale of our Louisiana natural gas properties in December 2007 and February 2008 — see “Overview — Sale of Louisiana Natural Gas Assets”, production in the third quarter of 2008 increased 16% (6,449 BOE/d) over third quarter of 2007 levels, and 26% in the first nine months of 2008 compared to production in the first nine months of 2007. The production increases were primarily due to increased production from our tertiary operations, coupled with production increases in the Barnett Shale. The increase in our tertiary operations is discussed above under “Results of Operations — CO₂ Operations”.

     Production in the Mississippi — non-CO₂ floods area has fluctuated somewhat from quarter to quarter, but is generally on a slight decline, as our continued drilling activity developing the Selma Chalk natural gas reservoir in the Heidelberg and Sharon areas has helped offset the gradual declines in oil production.

     Our Barnett Shale production has leveled off as our steady drilling program is generally maintaining a consistent production level. During 2006 and 2007, we drilled between 45 and 50 wells each year and we plan to do the same in 2008. Since these wells are characterized by high depletion rates, particularly in their first year of production, we anticipate that we will maintain a relatively steady production level there during 2008 at this drilling pace. This trend is evident in that the Barnett Shale production has remained relatively unchanged since the fourth quarter of 2007, if adjusted for the deferred production in the third quarter of 2008 related to the hurricanes. Production for the third quarter of 2008 averaged 12,339 BOE/d (down about 650 BOE/d related to deferred production from the hurricanes) as compared to 10,063 BOE/d for the comparative third quarter of 2007, 12,729 BOE/d in the fourth quarter of 2007, 12,801 BOE/d in the first quarter of 2008 and 13,434 BOE/d in the second quarter of 2008. The Texas property acquisition we made late in the first quarter of 2007 contributed approximately 336 BOE/d to the third quarter 2008 production, less than the 634 BOE/d added during the second quarter of 2008 as a portion of this production was also deferred because of the two hurricanes.

29

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     Our production for the third quarter of 2008 was weighted toward oil (68%), about the same as our proportion of oil production during the third quarter of 2007, as the increases in natural gas production in the Barnett Shale area, offset by the sale of our natural gas assets in Louisiana, generally have been matched by increases in our tertiary oil production.

     Oil and Natural Gas Revenues: Oil and natural gas revenues for the third quarter of 2008 increased $153.9 million, or 62%, from revenues in the comparable quarter of 2007, primarily as a result of higher commodity prices, accompanied by slightly higher production levels. The increase in production volumes in the third quarter of 2008 increased oil and natural gas revenues by $1.0 million, while the increase in overall commodity prices in the third quarter of 2008 increased revenues by $152.8 million, or 62%, over prior year’s third quarter levels. When comparing the respective nine month periods, revenues increased $493.7 million, or 78%, due to both increased prices and production. The increase in production during the first nine months of 2008 increased revenues by $58.4 million, or 9%, while the increase in overall commodity prices during the first nine months of 2008 increased oil and natural gas revenues by $435.3 million, or 69% over the prior year’s first nine months levels.

     Excluding any impact of our derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first, second and third quarters and first nine months periods of 2007 and 2008:

	Three Months Ended						Three Months Ended						Three Months Ended						Nine Months Ended
	March 31,						June 30,						September 30,						September 30,
	2008			2007			2008			2007			2008			2007			2008			2007
Net Realized Prices:
Oil price per Bbl	$	91.24		$	54.57		$	114.67		$	63.48		$	112.61		$	72.27		$	106.37		$	64.02
Gas price per Mcf		7.80			6.63			10.55			7.71			9.79			6.12			9.39			6.80
Price per BOE		76.65			49.06			98.07			57.02			95.20			59.01			90.11			55.36
NYMEX differentials:
Oil per Bbl	$	(6.50	)	$	(3.73	)	$	(9.64	)	$	(1.61	)	$	(6.06	)	$	(2.91	)	$	(7.23	)	$	(2.22	)
Natural Gas per Mcf		(0.90	)		(0.51	)		(0.93	)		0.07			0.75			(0.10	)		(0.35	)		(0.19	)

     Our oil NYMEX differential to prices received was the lowest in our corporate history during the first three quarters of 2007. The improved NYMEX differential during 2007 was related to higher prices received for both our light sweet barrels and our sour barrels primarily as a result of NYMEX (WTI) prices being depressed due to lack of available storage capacity in the mid-continent area, an oversupply of crude from Canada, capacity/transportation issues in moving crude oil out of the Cushing, Oklahoma area and unanticipated refinery outages. This trend reversed itself by the fourth quarter of 2007, with average NYMEX oil differentials during that quarter of $ (7.27) per Bbl, higher than our historical averages due to the significant increase in liquids extracted from our natural gas production in the Barnett Shale, which is recorded as oil production but sells at a significant discount to NYMEX. The differentials for the first quarter of 2008 improved only slightly over fourth quarter of 2007 levels, but widened to one of the highest differentials in our corporate history in the second quarter of 2008 to $(9.64) per Bbl as the differentials on the heavier sour crudes and the Barnett Shale liquid production widened as oil prices increased. The differentials for the third quarter of 2008 returned to first quarter 2008 levels as oil prices began to decline during the period.

     Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during a month as most of our natural gas is sold on an index price that is set near the first of the month. While the percentage change in the above table is quite large, these differentials are very seldom more than a dollar above or below the NYMEX amount.

     Oil and Natural Gas Derivative Contracts: We made cash payments of $24.1 million on settlements of our oil and natural gas derivative contracts during the third quarter of 2008, as compared to net cash receipts of $9.4 million during the third quarter of 2007, a negative differential of $33.5 million. Approximately 46% of the payments made during the third quarter of 2008 related to the 2,000 Bbls/d oil swaps for 2008 entered into when we made a large acquisition in January 2006, and the balance is due to natural gas swaps for 2008. On a nine month basis, we made cash payments of $60.7 million on settlements of our oil and natural gas derivative contracts during the 2008 period, as compared to net cash receipts of $19.4 million during the first nine months of 2007, a negative differential of $80.1 million.

30

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Approximately 51% of the payments made during the first nine months of 2008 related to the 2,000 Bbls/d oil swaps and the balance to the natural gas swaps.

     Our total non-cash mark-to-market income was $86.1 million during the third quarter of 2008, as compared to mark-to-market expense of $5.4 million during the third quarter of 2007, with the 2008 income primarily attributable to falling commodity prices during the quarter. On a nine month basis, our total mark-to-market income was $17.1 million during the first nine months of 2008, as compared to mark-to-market expense of $27.3 million during the first nine months of 2007. During the 2008 periods, both oil and natural gas prices increased during the first half of the year and then declined during the third quarter of 2008, ending the period at levels lower than at the beginning of the year. During the first nine months of 2007, natural gas prices fluctuated, causing a mark-to-market value charge for the first nine month period, comprised of a significant charge during the first quarter, income during the second quarter, and a modest charge in the third quarter. Because we do not utilize hedge accounting for our commodity derivative contracts, the adjustments in the fair value of these contracts are recognized currently in our income statement. See “Market Risk Management” for additional information regarding our derivative activities and Note 6 to the Unaudited Condensed Consolidated Financial Statements.

     Production Expenses: Our lease operating expenses increased between the comparable first nine months and third quarters on both a per BOE basis and in absolute dollars, primarily as a result of trends evident in our tertiary operations as more fully discussed under “CO₂ Operations” above, as our tertiary operating expenses were approximately 57% of our total operating expenses during the third quarter of 2008 as compared to approximately 47% during the third quarter of 2007. Other factors such as higher overall industry costs and increased personnel and related costs also contributed to higher expenses.

     During the third quarter of 2008, operating costs averaged $20.20 per BOE, up from $14.10 per BOE in the third quarter of 2007, and up from the $18.23 per BOE in the second quarter of 2008. The trends were similar when comparing the respective first nine month periods. A portion of the increase in per BOE expenses in the third quarter of 2008 resulted from the sale of our Louisiana natural gas properties in the fourth quarter of 2007 and first quarter of 2008. If the sold properties were excluded from the third quarter of 2007 results, our operating costs during that period would have been approximately $0.95 per BOE higher than reported, or $15.05 per BOE.

     Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes and therefore were higher in the third quarter of 2008 than in the comparable quarter of 2007. Transportation and plant processing fees were approximately $2.1 million higher in the third quarter of 2008 than in the third quarter of 2007 and approximately $6.8 million higher for the first nine months of 2008 than in the first nine months of 2007.

General and Administrative Expenses

     General and administrative (“G&A”) expenses increased 30% between the respective third quarters and increased 32% between the respective first nine months, as set forth below:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Amounts in thousands, except BOE data and employees	2008			2007			2008			2007
Net G&A expense
Gross G&A expenses	$	35,433		$	28,412		$	103,469		$	83,554
State franchise taxes		863			705			2,548			2,163
Operator labor and overhead recovery charges		(18,027	)		(15,041	)		(50,788	)		(43,741	)
Capitalized exploration and development costs		(3,264	)		(2,535	)		(9,408	)		(7,307	)
Net G&A expense	$	15,005		$	11,541		$	45,821		$	34,669
Average G&A cost per BOE	$	3.55		$	2.74		$	3.66		$	3.02
Employees as of September 30		768			668			768			668

31

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     Gross G&A expenses increased $7.0 million, or 25%, between the respective third quarters and $19.9 million, or 24%, between the respective first nine months. Approximately $4.6 million of the increase in gross G&A expenses between the respective quarters is related to increases in compensation and personnel related costs (approximately $17.1 million between the respective first nine months), due primarily to the increase in employees and salary increases, which we consider necessary in order to remain competitive in our industry. During 2007, we increased our employee count by 15% and we further increased our employee count by approximately 12% during the first nine months of 2008. Stock compensation expense reflected in gross G&A expenses was approximately $4.1 million for the third quarter of 2008 and $3.2 million for the third quarter of 2007. On a nine month basis, stock compensation was approximately $12.6 million for the first nine months of 2008 and $9.3 million for the first nine months of 2007. Due to increased competitive pressures in the industry, our wages have been increasing at a rate higher than general inflation and we expect this trend to continue.

     The increase in gross G&A was offset in part by an increase in operator overhead recovery charges in the third quarter and first nine months of 2008. 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 additional operated wells from acquisitions, additional tertiary operations, drilling activity during the past year and increased compensation expense, the amount we recovered as operator overhead charges increased by 20% between the third quarters of 2008 and 2007 and increased by 16% between the first nine months of 2008 and 2007. Capitalized exploration and development costs also increased by 29% between the third quarters of 2008 and 2007 and increased by 29% between the first nine months of 2008 and 2007, primarily as a result of increases in personnel and compensation costs.

     The net effect was a 30% increase in net G&A expense between the respective third quarters and a 32% increase for these costs between the first nine months of 2008 and 2007. On a per BOE basis, G&A costs increased 30% in the third quarter of 2008 as compared to levels in the third quarter of 2007, and increased 21% between the comparative first nine months of 2008 and 2007.

Interest and Financing Expenses

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Amounts in thousands, except per BOE amounts	2008			2007			2008			2007
Cash interest expense	$	17,209		$	13,529		$	42,287		$	35,321
Non-cash interest expense		410			530			1,225			1,523
Less: Capitalized interest		(6,713	)		(5,431	)		(19,524	)		(13,785	)
Interest expense	$	10,906		$	8,628		$	23,988		$	23,059
Interest income and other	$	4,675		$	1,702		$	7,321		$	5,269
Average net cash interest expense per BOE (1)	$	2.10		$	1.61		$	1.59		$	1.49
Average interest rate (2)		8.8	%		7.5	%		7.9	%		7.5	%
Average debt outstanding	$	780,129		$	736,596		$	713,714		$	640,916

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

     Interest expense increased $2.3 million, or 26%, comparing the third quarters of 2007 and 2008, and $0.9 million, or 4%, comparing levels in the first nine months of 2007 and 2008, primarily as a result of higher debt levels in the 2008 periods, partially offset by higher capitalized interest during the 2008 periods. Interest expense increased significantly during the third quarter of 2008 as a result of the two transactions with Genesis which were recorded as financing leases (see “Overview – Genesis Transactions”) and which carry a higher imputed rate of interest. The higher rate of interest is partially offset by the cash distributions that we receive from Genesis which have increased from $0.3 million in the third

32

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

quarter of 2007 to $2.1 million during the third quarter of 2008. However, the cash receipts related to distributions from Genesis are not recognized in our income statement but rather as an adjustment to our investment account.

     Our interest capitalization increased in 2008 because of our growing balance of unevaluated property expenditures and higher overall interest rates. We discontinued the capitalization of interest at Tinsley Field after production commenced there in April 2008 and discontinued the capitalization of interest at Lockhart Crossing Field in the third quarter of 2008 after production commenced there in July 2008. However, we have continued to expend funds on our CO₂ pipelines and our average interest rate has increased as a result of the two Genesis transactions (see above paragraph).

     Interest income increased during the third quarter of 2008 as a result of interest earned on the excess funds received from the two Genesis transactions.

Depletion, Depreciation and Amortization

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Amounts in thousands, except per BOE amounts	2008		2007		2008		2007
Depletion and depreciation of oil and natural gas properties	$	48,638	$	47,347	$	140,648	$	124,290
Depletion and depreciation of CO2 assets		4,047		2,966		10,673		8,408
Asset retirement obligations		762		746		2,286		2,232
Depreciation of other fixed assets		2,877		1,738		7,289		5,129
Total DD&A	$	56,324	$	52,797	$	160,896	$	140,059
DD&A per BOE:
Oil and natural gas properties	$	11.69	$	11.43	$	11.41	$	11.03
CO2 assets and other fixed assets		1.64		1.12		1.44		1.18
Total DD&A cost per BOE	$	13.33	$	12.55	$	12.85	$	12.21

     Our depletion, depreciation and amortization (“DD&A”) rate for oil and natural gas properties on a per BOE basis increased 2% between the respective third quarters and increased 3% between the respective first nine months, primarily due to capital spending and increased costs. During the third quarter, the significant incremental reserves included approximately 4.2 MMBbls booked at Lockhart Crossing Field, a new tertiary flood with an initial production response in July 2008, and approximately 5.3 MMBOEs in the Barnett Shale. These incremental reserves were not as significant as those booked in the second quarter when we booked approximately 29.8 million barrels of incremental oil reserves related to our tertiary operations in Tinsley Field, following the oil production response to the CO₂ injections in that field in April 2008. At that time we correspondingly moved approximately $195 million from unevaluated properties to the full cost pool relating to Tinsley Field, representing a portion of the acquisition cost of that field and other expenditures incurred on the field prior to recognizing proved reserves. As a result of recognizing all of the unevaluated costs on that field and virtually all of the forecasted future capital costs, the recognition of proved reserves at Tinsley slightly increased our DD&A rate as the average net cost per barrel for the proved reserves was slightly higher than our prior average DD&A rate. We expect to recognize incremental proved reserves at Tinsley in the future, which we expect will bring the average ultimate cost per barrel at that field to less than $10 per barrel.

     During the second quarter of 2008, we also moved approximately $37 million of equipment costs into our depletion calculation due to our decision to abandon our operating lease program following a change in tax accounting for certain tertiary costs (see “Overview – Change in Tax Accounting Method for Certain Tertiary Costs”). This further increased our DD&A rate during the second and third quarters of 2008.

     We continually evaluate the performance of our other tertiary projects, and if performance indicates that we are reasonably certain of recovering additional reserves from these floods, we recognize those incremental reserves in that

33

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

quarter. Since we adjust our DD&A rate each quarter based on any changes in our estimates of oil and natural gas reserves and costs, our DD&A rate could change significantly in the future.

     Our DD&A rate for our CO₂ and other general corporate fixed assets increased in 2008 as compared to the rates during 2007, primarily as a result of expenditures related to the expansion of our corporate office space and the Tinsley, Lockhart and Gwinville CO₂ pipelines placed into service during 2008.

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Amounts in thousands, except per BOE amounts and tax rates	2008			2007			2008			2007
Current income tax expense	$	12,689		$	5,197		$	44,769		$	14,158
Deferred income tax expense		83,480			38,028			163,909			79,609
Total income tax expense	$	96,169		$	43,225		$	208,678		$	93,767
Average income tax expense per BOE	$	22.77		$	10.28		$	16.66		$	8.18
Effective tax rate		37.9	%		38.9	%		37.7	%		38.9	%

     In the fourth quarter of 2007, we lowered our estimated statutory income tax rate to 38% from 39% as result of our sale of our Louisiana natural gas assets. During the nine months of 2008, our effective rate was further reduced primarily as a result of higher section 199 deductions because of our higher pretax income.

     The Company recently obtained approval from the IRS to change its method of tax accounting for certain assets used in its tertiary oilfield recovery operations. Previously, the Company capitalized and depreciated these costs, but now it can deduct these costs once the assets are placed into service. As a result, the Company expects to receive tax refunds of approximately $10.6 million for tax years through 2007, and in the third quarter of 2008 has reduced its current income tax expense to adjust for the impact of this change. The reduction in current income tax expense has been offset by a corresponding increase in deferred income tax expense of approximately the same amount. Although this change is not expected to have a significant impact on the Company’s overall tax rate, it is anticipated that it will reduce the amount of cash taxes the Company expects to pay over the next several years.

Per BOE Data

     The following table summarizes our 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.

34

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Per BOE data	2008			2007			2008			2007
Oil and natural gas revenues	$	95.20		$	59.01		$	90.11		$	55.36
Gain (loss) on settlements of derivative contracts		(5.70	)		2.24			(4.84	)		1.69
Lease operating expenses		(20.20	)		(14.10	)		(18.22	)		(14.57	)
Production taxes and marketing expenses		(4.58	)		(3.01	)		(4.52	)		(2.90	)
Production netback		64.72			44.14			62.53			39.58
Non-tertiary CO2 operating margin		0.53			0.54			0.55			0.60
General and administrative expenses		(3.55	)		(2.74	)		(3.66	)		(3.02	)
Net cash interest expense		(2.10	)		(1.61	)		(1.59	)		(1.49	)
Abandoned acquisition costs		(7.20	)		—			(2.43	)		—
Current income taxes and other		(2.41	)		(0.68	)		(2.93	)		(0.66	)
Changes in assets and liabilities relating to operations		12.14			0.58			(1.94	)		(3.20	)
Cash flow from operations		62.13			40.23			50.53			31.81
DD&A		(13.33	)		(12.55	)		(12.85	)		(12.21	)
Deferred income taxes		(19.76	)		(9.04	)		(13.09	)		(6.94	)
Non-cash commodity derivative adjustments		20.38			(1.29	)		1.37			(2.38	)
Changes in assets and liabilities and other non-cash items		(12.12	)		(1.19	)		1.56			2.55
Net income	$	37.30		$	16.16		$	27.52		$	12.83

Market Risk Management

Debt

     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. We had no bank debt outstanding as of September 30, 2008 and $150 million outstanding at December 31, 2007. 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, although under the NEJD financing lease with Genesis (See “Overview – Genesis Transactions”) in the event of significant downgrades of our corporate credit rating by the rating agencies, Genesis can require certain credit enhancements from us, and possibly other remedies under the lease. See also Note 6 to the Unaudited Condensed Consolidated Financial Statements regarding the settlement of some minor interest rate lock derivative contracts. The following table presents the carrying and fair values of our debt as of September 30, 2008, along with average interest rates.

	Expected Maturity Dates				Carrying		Fair
Amounts in thousands	2013		2015		Value		Value
Fixed rate debt:
7.5% subordinated debt due 2013 (fixed rate of 7.5%)	$	225,000	$	—	$	224,126	$	212,625
7.5% subordinated debt due 2015 (fixed rate of 7.5%)		—		300,000		300,621		276,000

Oil and Gas Derivative Contracts

     From time to time, we enter into various oil and 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. Historically, we hedged up to 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt. Since 2005 and beyond, we have generally entered into fewer derivative contracts, primarily because of our strong financial position resulting from our lower levels of debt relative to our cash flow from operations, although we have hedged certain products from time to time. In late 2006 we swapped 80% to 90% of our forecasted

35

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

2007 natural gas production at a weighted average price of $7.96 per Mcf, and in September 2007 we swapped 70% to 80% of our remaining forecasted 2008 natural gas production (after the sale of our Louisiana natural gas properties) at a weighted average price of $7.91 per Mcf. We did this to protect our 2008 projected cash flow, primarily because we initially planned to spend $200 million to $250 million more than we expected to generate in cash flow from operations and we did not want to be exposed to the risk of lower natural gas prices. We cancelled the December 2008 natural gas swaps in the third quarter of 2008 because of our plans to sell our Barnett Shale properties, receiving approximately $61,000 from the cancellation.

     As a result of the current economic conditions and in order to protect our liquidity in the event that commodity prices continue to decline, during early October 2008, we purchased oil derivative contracts for 2009 with a floor price of $75 / Bbl and a ceiling price of $115 / Bbl for total consideration of $15.5 million. The collars cover 30,000 Bbls/d representing between 75% and 80% of our currently anticipated 2009 oil production including anticipated production from Hastings Field, but excluding any natural gas liquids production from our Barnett Shale assets (see also “Capital Resources and Liquidity”). These 2009 contracts were entered into with the following counterparties: JPMorgan Chase Bank (10,000 Bbls/d), Wells Fargo Bank (7,500 Bbls/d), Keybank (5,000 Bbls/d), Fortis Energy Marketing and Trading GP (5,000 Bbls/d) and Comerica Bank (2,500 Bbls/d).

     When we make a significant acquisition, we generally attempt to hedge a large percentage, up to 100%, of the forecasted proved production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. As of September 30, 2008, we had derivative contracts in place related to our $250 million acquisition that closed on January 31, 2006, on which we entered into contracts to cover 100% of the first three years of estimated proved producing production at the time we signed the purchase and sale agreement. These swaps cover 2,000 Bbls/d for remainder of 2008 at a price of $57.34 per Bbl.

     At September 30, 2008, our derivative contracts were recorded at their fair value, which was a net liability of approximately $6.2 million, an increase in value of approximately $17.1 million from the $23.3 million fair value liability recorded as of December 31, 2007 (See Note 6 to Unaudited Condensed Consolidated Financial Statements for a complete listing of our derivative contract positions at September 30, 2008). This change is the result of both the expiration of contracts during the first nine months of 2008 and the decreases in both oil and natural gas commodity futures prices between December 31, 2007 and September 30, 2008.

     Based on NYMEX crude oil futures prices at September 30, 2008, oil prices were considerably higher than the swap prices of our outstanding derivative contracts so we would expect to make future cash payments of $7.9 million on our oil commodity derivative contracts. If oil futures prices were to decline by 10%, the amount we would expect to pay under our oil commodity derivative contracts would decrease to $6.1 million, and if futures prices were to increase by 10% we would expect to pay $9.8 million. Based on NYMEX natural gas futures prices at September 30, 2008, we would expect to receive cash payments of $1.4 million on our natural gas commodity derivative contracts. If natural gas prices futures prices were to decline by 10%, we would expect to receive future cash payments of $4.2 million, and if futures prices were to increase by 10% we would expect to make future cash payments of $1.4 million.

Critical Accounting Policies

     For a discussion of our critical accounting policies, which are related to property, plant and equipment, depletion and depreciation, oil and natural gas reserves, accounting for tertiary injection costs, asset retirement obligations, income taxes, stock compensation plans and hedging activities, and which remain unchanged, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 2007. See also “Overview—Change in Tax Accounting Method for Certain Tertiary Costs” and “Results of Operations — CO₂ Operations” for discussions regarding changes in accounting policies and procedures during 2008.

Recent Accounting Pronouncements

Recently Issued Accounting Pronouncements

     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

36

DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 have been applied, and the impact that hedges have on an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for us beginning January 1, 2009. We have not yet determined what impact, if any, this pronouncement will have on our disclosures about derivatives.

     In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.” FSP FAS 157-3 clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued. Revisions resulting from a change in the valuation technique or its application should be accounted for as a change in accounting estimate following the guidance in FASB Statement No. 154, “Accounting Changes and Error Corrections.” FSP FAS 157-3 is effective for the financial statements included in the Company’s quarterly report for the period ended September 30, 2008, and application of FSP FAS 157-3 had no impact on the Company’s Unaudited Condensed Consolidated Financial Statements.

Forward-Looking Information

     The statements contained in this Quarterly Report on Form 10-Q 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 or forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values, potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based upon current and projected oil and gas prices, liquidity, availability of capital, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in 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.

37

DENBURY RESOURCES INC.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

     The information required by Item 3 is set forth under “Market Risk Management” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 4. Controls and Procedures

     Evaluation of Disclosure Controls and Procedures – As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of the Company’s management, including the CEO and CFO. Based on that evaluation, the Company’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2008 to ensure: that information required to be disclosed in the reports it files and submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

     Changes in Internal Control Over Financial Reporting — There have been no changes in the Company’s internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

38

DENBURY RESOURCES INC.

Part II. Other Information

Item 1. Legal Proceedings

     Information with respect to this item has been incorporated by reference from our Form 10-K for the year ended December 31, 2007. There have been no material developments in such legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

     Information with respect to the risk factors has been incorporated by reference from Item 1A. of our Form 10-K for the year ended December 31, 2007. There have been no material changes to the risk factors since the filing of such Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

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
July 1 through 31, 2008		198	$	34.19		—		—
August 1 through 31, 2008		141,150	$	24.42		—		—
September 1 through 30, 2008		6,758	$	23.00		—		—
Total		148,106	$	24.37		—		—

Item 3. Defaults Upon Senior Securities

     None.

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

     None.

Item 5. Other Information

     None.

Item 6. Exhibits

     Exhibits:

10(a)*	Second Amendment to Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, and JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other financial institutions dated as of October 7, 2008.
10(b)*	Option Agreement to Purchase Hastings Field By and Between Texcal Energy South Texas, L.P. and Denbury Onshore, LLC dated November 1, 2006.
10(c)*	First Amendment to Option Agreement, dated as of August 29, 2008, by and between TexCal Energy South Texas, L.P. and Denbury Onshore, LLC.
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.

* Filed herewith.

39

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DENBURY RESOURCES INC. (Registrant)
By:	/s/ Phil Rykhoek
	Phil Rykhoek
	Sr. Vice President and Chief Financial Officer
By:	/s/ Mark C. Allen
	Mark C. Allen
	Vice President and Chief Accounting Officer

Dated: November 7, 2008

40

EX-10.(A)

Exhibit 10 (a)

SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

     This Second Amendment to Sixth Amended and Restated Credit Agreement (this “Second Amendment”) is entered into effective as of the 7^th day of October, 2008 (the “Effective Date”), by and among Denbury Onshore, LLC, a Delaware limited liability company (“Borrower”), Denbury Resources Inc., a Delaware corporation (“Parent”), JPMorgan Chase Bank, N.A., as Administrative Agent (“Administrative Agent”), and the financial institutions parties hereto as Banks (“Banks”).

W I T N E S S E T H

     WHEREAS, Borrower, Parent, Administrative Agent, the other agents a party thereto and Banks are parties to that certain Sixth Amended and Restated Credit Agreement dated as of September 14, 2006 (as amended, the “Credit Agreement”) (unless otherwise defined herein, all terms used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement); and

     WHEREAS, pursuant to the Credit Agreement, Banks have made a Revolving Loan to Borrower and provided certain other credit accommodations to Borrower; and

     WHEREAS, Parent and Borrower have requested that the Credit Agreement be amended to (i) increase the Total Commitment from $350,000,000 to $750,000,000 to be reflected in a new Schedule 2.1 to the Credit Agreement and (ii) amend certain other terms of the Credit Agreement in certain respects as provided in this Second Amendment; and

     WHEREAS, Parent and Borrower have requested that The Bank of Nova Scotia, Keybank National Association and U.S. Bank National Association (each of the foregoing financial institutions are herein referred to as a “New Bank”) become new Banks under the Credit Agreement with Commitments as shown on Schedule 2.1 to the Credit Agreement (as amended hereby); and

     WHEREAS, Borrower, as buyer, and Wapiti Energy, LLC, a Texas limited liability company, Wapiti Operating, LLC, a Texas limited liability company and Wapiti Gathering, LLC a Texas limited liability company (collectively, “Seller”), as seller, entered into that certain Purchase and Sale Agreement dated as of August 19, 2008 (as amended from time to time, the “Conroe Purchase Agreement”), pursuant to which Borrower has agreed to purchase, directly or indirectly, from Seller certain oil and gas properties more particularly described therein (such acquisition, the “Conroe Acquisition” and such properties, the “Conroe Properties”); and

     WHEREAS, Borrower expects to structure the Conroe Acquisition to qualify for reverse like-kind exchange treatment under Section 1031 of the Code and the regulations and revenue procedures promulgated thereunder, including Rev. Proc. 2000-37; and

     WHEREAS, in furtherance of the reverse like-kind exchange, Borrower will assign the Conroe Purchase Agreement to Denbury Conroe LLC, a Delaware limited liability company

1

(“Denbury Conroe”), that is not affiliated with Borrower, and will lend to Denbury Conroe up to $600,000,000 from the proceeds of the Borrowings under the Credit Agreement (as amended hereby) (the “Conroe Loan”); and

     WHEREAS, the Conroe Loan will be evidenced by a promissory note issued by Denbury Conroe in favor of Borrower (the “Denbury Conroe Note”), which Denbury Conroe Note will be subsequently collaterally assigned and pledged by Borrower to Administrative Agent, for the benefit of itself, the Banks and their Affiliates for whom Obligations may be owed from time to time; and

     WHEREAS, the assignment of the Conroe Purchase Agreement to Denbury Conroe, the Conroe Acquisition, the making of the Conroe Loan, the pledging of the Denbury Conroe Note to Administrative Agent and all other transactions relating to or arising out of the foregoing are collectively referred to herein as the “Conroe Transactions”; and

     WHEREAS, the Parent and the Borrower have requested that the Administrative Agent and the Required Banks issue their consent to the Conroe Transactions and waive certain provisions of the Credit Agreement with respect to the Conroe Transactions; and

     WHEREAS, subject to and upon the terms and conditions set forth herein, Banks have agreed to Parent’s and Borrower’s requests.

     NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Parent, Borrower, Administrative Agent and Banks hereby agree as follows:

Section 1. Amendments. In reliance on the representations, warranties, covenants and agreements contained in this Second Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 4 hereof, the Credit Agreement shall be amended effective as of the Effective Date in the manner provided in this Section 1.

     1.1 Deleted Definitions. Section 2.1 of the Credit Agreement shall be amended to delete the definitions of “2005 Bond Exposure” and “Additional Permitted Revenue Bond Exposure” in their entirety, and all references in the Credit Agreement to such terms are deleted.

     1.2 Additional Definitions. Section 2.1 of the Credit Agreement shall be amended to add thereto in alphabetical order the following definitions which shall read in full as follows:

     “Barnett Shale Assets” means all of Borrower’s oil and gas properties owned by Borrower on October 7, 2008 and located in Parker, Wise, Tarrant and Johnson Counties, Texas.

     “Conroe Loan” has the meaning ascribed to such term in the Second Amendment.

     “Net Proceeds” means, with respect to any event, (a) the cash proceeds received in respect of such event including any cash

2

received in respect of any non-cash proceeds (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or purchase price adjustment receivable or otherwise, but excluding any interest payments), but only as and when received, net of (b) the sum of (i) all reasonable fees and out-of-pocket expenses paid to third parties (other than Affiliates) in connection with such event and (ii) the amount of all taxes paid (or reasonably estimated to be payable) during the year that such event occurred or the next succeeding year and that are directly attributable to such event (as determined reasonably and in good faith by a Financial Officer).

     “Prepayment Event” means, at any time the Obligations are outstanding, any sale, transfer or other disposition of an asset permitted by Section 10.5(e).

     “Second Amendment” means that certain Second Amendment to Sixth Amended and Restated Credit Agreement dated as of October 7, 2008 among Borrower, Parent, Administrative Agent and Banks.

     “Senior Managing Agent” means Comerica Bank in its capacity as Senior Managing Agent for Banks hereunder or any successor thereto.

     “Additional Exchange Properties” means those certain oil and gas properties (other than the Conroe Properties (as defined in the Second Amendment)) that Borrower may contract for and acquire (through a qualified intermediary) within 180 days of the consummation of the sale of the Barnett Shale Assets utilizing the proceeds from the disposition of the Barnett Shale Assets in excess of those required to conclude the Conroe Transactions.

     1.3 Amendment to Definitions. The definitions of “Additional Permitted Revenue Bonds”, “Agent”, “Applicable Margin”, “Commitment Fee Percentage”, “Documentation Agent”, “Loan Papers”, “Obligations”, “Permitted Investments”, “Permitted Subordinate Debt” and “Syndication Agent” contained in Section 2.1 of the Credit Agreement shall be amended and restated to read in full as follows:

     “Additional Permitted Revenue Bonds” means, whether one or more, Bond Issuer’s taxable industrial development revenue bonds issued after the date hereof in connection with an Additional Permitted Revenue Bond Transaction, which Additional Permitted Revenue Bonds shall (a) be in a maximum aggregate principal amount of not greater than $200,000,000, (b) bear interest at rates identical to the interest rates set forth in this Agreement, (c) have a maturity date that is two (2) years following the issuance thereof,

3

and (d) provide that Bond Purchaser’s obligation to make advances of the proceeds thereof shall expire two (2) years from the date of issuance of such Additional Permitted Revenue Bonds. Subject to the terms and conditions set forth in this Agreement, upon the date of any issuance and subsequent purchase by Bond Purchaser of any Additional Permitted Revenue Bonds pursuant to an Additional Permitted Revenue Bond Transaction, Bond Purchaser shall be deemed to have sold to each Bank, and each Bank shall be deemed to have unconditionally and irrevocably purchased from Bond Purchaser, a participation in such Additional Permitted Revenue Bonds equal to such Bank’s Commitment Percentage of any such Additional Permitted Revenue Bonds.

     “Agent” means Administrative Agent, each Syndication Agent, each Documentation Agent, Senior Managing Agent, Sole Lead Arranger or Book Manager, and “Agents” means Administrative Agent, each Syndication Agent, each Documentation Agent, Senior Managing Agent, Sole Lead Arranger and Book Manager, collectively.

     “Applicable Margin” means, on any date, with respect to each Type of Loan, an amount determined by reference to the ratio of Outstanding Credit to the Total Commitment on such date in accordance with the table below:

Ratio of Outstanding	Applicable			Applicable
Credit to Total	Margin for			Margin for Base
Commitment	Eurodollar Loans			Rate Loans
< .50 to 1		1.250	%		0	%
> .50 to 1 and < .75 to 1		1.500	%		0.250	%
> .75 to 1 and < .90 to 1		1.750	%		0.500	%
> .90 to 1		2.000	%		0.750	%

     “Commitment Fee Percentage” means, on any date, the percentage determined by reference to the ratio of Outstanding Credit to the Total Commitment on such date in accordance with the table below:

4

Ratio of Outstanding Credit	Commitment Fee
to Total Commitment	Percentage
< .50 to 1		.300	%
> .50 to 1 and < .75 to 1		.300	%
> .75 to 1 and < .90 to 1		.375	%
> .90 to 1		.375	%

     “Documentation Agent” means Union Bank of California, N.A. or Bank of America, N.A. in its capacity as Documentation Agent for Banks hereunder or any successor thereto, and “Documentation Agents” means Union Bank of California, N.A. and Bank of America, N.A., collectively, in their capacities as Documentation Agents for Banks hereunder.

     “Loan Papers” means this Agreement, the First Amendment, the Second Amendment, the Notes, each Facility Guaranty which may now or hereafter be executed, each Parent Pledge Agreement which may now or hereafter be executed, each Subsidiary Pledge Agreement which may now or hereafter be executed, the Existing Mortgages (as amended by the Amendments to Mortgages), all Mortgages now or at any time hereafter delivered pursuant to Section 6.1, the Amendments to Mortgages, and all other certificates, documents or instruments delivered in connection with this Agreement, as the foregoing may be amended from time to time.

     “Obligations” means all present and future indebtedness, obligations and liabilities, and all renewals and extensions thereof, or any part thereof, of each Credit Party to Administrative Agent or to any Bank or any Affiliate of any Bank arising pursuant to (a) the Loan Papers, (b) pursuant to any Hedge Agreement or Hedge Transaction entered into with any Bank or any Affiliate of any Bank and (c) the Bond Documents and (d) each and any of the following bank services provided by any Bank or any Affiliate of any Bank to a Credit Party: (i) commercial credit cards, (ii) stored value cards, (iii) treasury management services (including, without limitation, controlled disbursement, automated clearinghouse transactions, return items, overdrafts and interstate depository network services), and all interest accrued on any of the indebtedness, obligations and liabilities arising pursuant to clauses (a), (b), (c) and/or (d) above in this definition, and costs, expenses, and attorneys’ fees incurred in the enforcement or collection of any of the indebtedness, obligations and liabilities arising pursuant to clauses (a), (b), (c) and/or (d) above in this definition, regardless of

5

whether such indebtedness, obligations and liabilities are direct, indirect, fixed, contingent, liquidated, unliquidated, joint, several or joint and several.

     “Permitted Investments” means (a) readily marketable direct obligations of the United States of America (or investments in mutual funds or similar funds which invest solely in such obligations), (b) demand or time deposit accounts, certificates of deposit and money market deposits with maturities of one year or less of any commercial bank operating in the United States having capital and surplus in excess of $500,000,000, (c) commercial paper of a domestic issuer if at the time of purchase such paper is rated in one of the two highest ratings categories of Standard and Poor’s Corporation or Moody’s Investors Service, (d) money market funds that invest substantially all of their assets in securities of the types described in clauses (a) through (c) above, (e) Investments by any Credit Party in a Subsidiary of Parent that has provided a Facility Guaranty and the Equity of which has been pledged to Administrative Agent pursuant to a Parent Pledge Agreement or a Subsidiary Pledge Agreement, and (f) other Investments; provided, that, the aggregate amount of all other Investments made pursuant to this clause (f) outstanding at any time shall not exceed $10,000,000 (measured on a cost basis).

     “Permitted Subordinate Debt” means, collectively, (i) Debt of Borrower resulting from a single issue of Borrower’s 7.5% Senior Subordinated Notes Due 2013 in an aggregate outstanding principal balance of not greater than $225,000,000, and which Debt has been assumed by Parent as a co-obligor with Borrower pursuant to that certain First Supplemental Indenture, dated as of December 29, 2003, (ii) Debt of Parent resulting from the issue of Parent’s 7.5% Senior Subordinated Notes Due 2015 in an aggregate outstanding principal amount of not greater than $300,000,000 and (iii) either (A) subordinate unsecured Debt of up to $600,000,000 with an interest rate no greater than 10.0% and a maturity date that is no less than 7 years from the date such Debt is incurred or (B) subordinate unsecured Debt of up to $600,000,000 with an interest rate no greater than 9.0%, a maturity date that is no less than 5 years from the date such Debt is incurred and which is convertible into Equity of Parent; provided that in each case such Debt issued pursuant to this clause (iii) is issued on or prior to April 1, 2009.

     “Syndication Agent” means Wells Fargo Bank, N.A. or Fortis Capital Corp., in its capacity as Syndication Agent for Banks hereunder or any successor thereto, and “Syndication Agents” means Wells Fargo Bank, N.A. and Fortis Capital Corp.,

6

collectively, in their capacities as Syndication Agents for Banks hereunder.

     1.4 Amendment to Definition of Additional Permitted Revenue Bond Transaction. Clause (b) of the definition of “Additional Permitted Revenue Bond Transaction” contained in Section 2.1 of the Credit Agreement shall be amended and restated to read in full as follows:

(b) such transaction is on substantially similar terms, and pursuant to substantially similar Additional Permitted Revenue Bond Documents, as the transaction evidenced by the 2005 Bond Offering and the Bond Documents executed and delivered in connection therewith, which terms shall provide that any obligation of Bond Purchaser to purchase Additional Permitted Revenue Bonds shall be limited to the amount of Borrowings that are then available under and in accordance with the terms of this Agreement;

     1.5 Amendment to Letter of Credit Sublimit Provision. Clause (b)(i)(B) of Section 3.1 of the Credit Agreement is hereby amended to delete the reference to “ten percent (10%)” set forth therein and to insert a reference to “five percent (5%)” in lieu thereof.

     1.6 Amendment to Mandatory Prepayments Provision. Section 3.6 of the Credit Agreement is hereby deleted and replaced in its entirety with the following:

     Section 3.6 Mandatory Prepayments. Upon the occurrence of any Borrowing Base Deficiency, Borrower shall make the mandatory prepayments of the Revolving Loan required by Section 5.4 hereof. Additionally, if at any time the Outstanding Credit is in excess of the Total Commitment (as used in this Section 3.6, a “deficiency”), Borrower shall immediately make a principal payment on the Revolving Loan sufficient to cause the principal balance of the Revolving Loan then outstanding to be equal to or less than the Total Commitment then in effect. If a deficiency cannot be eliminated pursuant to this Section 3.6 by prepayment of the Revolving Loan (as a result of outstanding Letter of Credit Exposure), Borrower shall also deposit cash with Administrative Agent, to be held by Administrative Agent to secure outstanding Letter of Credit Exposure in the manner contemplated by Section 3.1(b). In addition to the foregoing, in the event and on each occasion that any Net Proceeds are received by or on behalf of any Credit Party in respect of any Prepayment Event, the Borrower shall, immediately after such Net Proceeds are received by any Credit Party, prepay the Obligations in an aggregate amount equal to 100% of such Net Proceeds; provided, that so long as the Borrower intends that the Net Proceeds from such Prepayment Event (or a portion thereof), are to be applied

7

within 180 days after such Prepayment Event, to acquire Additional Exchange Properties to be used in the business of the Borrower, and no Event of Default has occurred and is continuing, then such immediate prepayment shall be limited to the outstanding balance of the Conroe Loan, provided, further, that to the extent any of such remaining Net Proceeds have not been so applied by the end of such 180 day period, a prepayment shall be required at such time in an amount equal to such Net Proceeds that have not been so applied. There shall be no corresponding reduction in the Borrowing Base or in the Total Commitment as a result of a prepayment of the type described in the immediately preceding sentence.

     1.7 Amendment to Asset Dispositions Provision. Section 10.5 of the Credit Agreement is hereby deleted and replaced in its entirety with the following:

     Section 10.5 Asset Dispositions. Parent and Borrower will not, nor will Parent and/or Borrower permit any other Credit Party to, sell, lease, transfer, abandon or otherwise dispose of any asset other than (a) the sale in the ordinary course of business of Hydrocarbons produced from Borrower’s Mineral Interests, (b) the sale, lease, transfer, abandonment, exchange or other disposition of other assets, provided, that the aggregate value (which, in the case of assets consisting of Mineral Interests, shall be the Recognized Value of such Mineral Interests and in the case of any exchange, shall be the net value or net Recognized Value realized or resulting from such exchange) of all assets sold, leased, transferred or disposed of pursuant to this clause (b) in any period between Scheduled Redeterminations shall not exceed five percent (5%) of the Borrowing Base then in effect (for purposes of this clause (b) the Closing Date will be deemed to be a Scheduled Redetermination), (c) the sale, lease, transfer, abandonment or disposition of Unproved Reserves, (d) the sale of volumetric production payments of carbon dioxide pursuant to the express terms of the Genesis Transaction Documents and (e) the sale, assignment, lease, license, transfer, exchange or other disposition by any Credit Party of all or substantially all of its right, title and interest in the Barnett Shale Assets; provided, that, with respect to any disposition of the Barnett Shale Assets, Administrative Agent shall have received certified copies of any and all documents related to a like-kind exchange or reverse like-kind exchange involving the Barnett Shale Assets under Section 1031 of the Code. In no event will Parent, Borrower or any other Credit Party sell, transfer or dispose of any Equity in any Restricted Subsidiary nor will any Credit Party (other than Parent) issue or sell any Equity or any option, warrant or other right to acquire such Equity or security convertible into such Equity to any Person other than

8

the Credit Party which is the direct parent of such issuer on the Closing Date.

     1.8 Amendment to Agent Provision. Section 13.16 of the Credit Agreement is hereby deleted and replaced in its entirety with the following:

     Section 13.16 Agents. None of the Banks identified in this Agreement as a “Documentation Agent”, a “Syndication Agent” and/or a “Senior Managing Agent shall have any right, power, obligation, liability, responsibility or duty under this Agreement other than those applicable to all Banks as such. Without limiting the foregoing, none of such Documentation Agents, Syndication Agents or Senior Managing Agent shall have or be deemed to have a fiduciary relationship with any Bank. Each Bank hereby makes the same acknowledgments with respect to such Documentation Agents, Syndication Agents and Senior Managing Agent as it makes with respect to Administrative Agent in Section 13.11.

     1.9 Amendment to Expenses Provision. Clause (a) of Section 15.3 of the Credit Agreement is hereby amended by deleting the reference therein to “(other than any Documentation Agent or Syndication Agent)” and inserting “(other than any Documentation Agent, Syndication Agent or Senior Managing Agent)” in lieu thereof.

     1.10 Amendment to Amendments and Waiver Provision. Section 15.5 of the Credit Agreement is hereby amended by adding the following language at the beginning of such Section:

“Subject to the provisions of Section 15.10(f),”.

     In addition, the word “Any” immediately following such added language is hereby deleted and replaced with “any”.

     1.11 Replacement of Schedule 2.1. Schedule 2.1 to the Credit Agreement shall be replaced in its entirety with Schedule 2.1 to this Second Amendment and Schedule 2.1 hereto shall be deemed to be attached as Schedule 2.1 to the Credit Agreement.

     1.12 Borrowing Base. Effective as of the Effective Date, the Borrowing Base shall be reaffirmed at $1,000,000,000. Notwithstanding anything to the contrary contained in the Credit Agreement, the Borrowing Base shall remain at $1,000,000,000 until the Scheduled Redetermination scheduled for April 1, 2009, unless there is a Special Redetermination prior to such time. There shall be no Scheduled Redetermination of the Borrowing Base on or about October 1, 2008. Borrower and Banks agree that the Redetermination provided for in this Section 1.8 shall not be construed or deemed to be a Special Determination for the purposes of Section 5.3 of the Credit Agreement.

     1.13 Joinder. Each New Bank hereby joins in, becomes a party to, and agrees to comply with and be bound by the terms and conditions of the Credit Agreement as a Bank thereunder and under each and every other Loan Paper to which any Bank is required to be

9

bound by the Credit Agreement, to the same extent as if such New Bank were an original signatory thereto. Each New Bank hereby appoints and authorizes each Agent to take such action as agent on its behalf and to exercise such powers and discretion under the Credit Agreement as are delegated to each such Agent by the terms thereof, together with such powers and discretion as are reasonably incidental thereto.

Section 2. Eurodollar Loans. Notwithstanding anything to the contrary set forth in the Credit Agreement, Borrower agrees that, during the period from the Effective Date through and including the date that is thirty (30) days following the Effective Date, all Borrowings made during such 30-day period shall be Base Rate Borrowings and the Banks shall be under no obligation to make additional Eurodollar Loans, to Continue Eurodollar Loans or Convert Revolving Loans of any other Type into Eurodollar Loans. Borrower shall, during such 30-day period, on the last day(s) of the then current Interest Period(s) for the outstanding Eurodollar Loans, either prepay such Eurodollar Loans or Convert such Eurodollar Loans into another Type of Revolving Loan in accordance with the terms of the Credit Agreement.

Section 3. Consent and Waiver. In reliance on the representations, warranties, covenants and agreements contained in this Second Amendment, and subject to the satisfaction of the conditions precedent set forth in Sections 3 and 5 hereof, Required Banks consent to Borrower’s consummation of the Conroe Transactions, and waive compliance by Borrower and Parent with each provision of the Credit Agreement and the other Loan Papers including, without limitation, Section 10.8 of the Credit Agreement, to the extent, but only to the extent, that the Conroe Transactions (or any term contained in the documents governing and evidencing the Conroe Transactions) violate such provisions or result in a Default or Event of Default under the Credit Agreement or the other Loan Papers.

Section 4. Conditions Precedent to Amendment, Consent and Waiver. The amendments contained in Section 1 hereof and the Consent and Waiver contained in Section 3 hereof are subject to the satisfaction of each of the following conditions precedent:

     4.1 Counterparts. The Administrative Agent shall have received counterparts hereof duly executed by the Borrower, Parent, Required Banks, each New Bank and each Bank whose Commitment is increasing hereunder (or, in the case of any party as to which an executed counterpart shall not have been received, telegraphic, telex, or other written confirmation from such party of execution of a counterpart hereof by such party).

     4.2 Fees. Borrower shall have paid to Administrative Agent any and all reasonable fees payable to Administrative Agent or the New Banks pursuant to or in connection with this Second Amendment in consideration for the agreements set forth herein.

     4.3 Notes. Each Bank that is a New Bank or whose Commitment is increasing hereunder shall have received a duly completed and executed Note, payable to the order of such Bank.

     4.4 Legal Opinion. An opinion of Baker & Hostetler LLP, special counsel for the Credit Parties, dated the Effective Date, favorably opining as to the enforceability of this Second

10

Amendment and covering such other matters relating to the Credit Parties and the Loan Papers as the Administrative Agent shall reasonably request.

     4.5 Organizational Documents and Certificates. The Administrative Agent shall have received such documents and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, existence and good standing in its jurisdiction of organization of each of the Credit Parties, the authorization of the execution of this Second Amendment and any other legal matters relating to the Borrower, the other Credit Parties, the Credit Agreement or this Second Amendment, all in form and substance reasonably satisfactory to the Administrative Agent and its counsel.

     4.6 Break Funding Payments. If, on the Effective Date, any Eurodollar Loans are outstanding and if the Effective Date is not the last day of the Interest Period(s) in respect of such Eurodollar Loans, the Borrower shall have paid any compensation required under Section 14.5 of the Credit Agreement.

     4.7 No Material Adverse Effect. There shall not have occurred since December 31, 2007 any events that, individually or in the aggregate, have had a Material Adverse Effect.

     4.8 No Default. No Default or Event of Default shall have occurred which is continuing.

     4.9 Other Documents. Administrative Agent shall have been provided with such documents, instruments and agreements, and Parent and Borrower shall have taken such actions, in each case as Administrative Agent may reasonably require in connection with this Second Amendment and the transactions contemplated hereby.

Section 5. Conditions Precedent to Consent and Waiver. The consent and waiver contained in Section 3 hereof are subject to Administrative Agent having received, prior to or contemporaneously with the closing of the Conroe Transactions, from Borrower (a) a security agreement duly executed by the Borrower, in form and substance reasonably satisfactory to Administrative Agent, pursuant to which Borrower collaterally assigns and grants a security interest in the Denbury Conroe Note to Administrative Agent, for its benefit and on behalf the Banks and their Affiliates for whom Obligations may be owed from time to time, (b) the original Denbury Conroe Note, duly endorsed by Borrower in favor of the Administrative Agent, (c) a true and complete copy of the fully-executed Conroe Purchase Agreement, together with any disclosure schedules delivered pursuant thereto, and (d) true and complete copies of the Exchange Accommodation Titleholder documents relating to the Conroe Transactions.

Section 6. Representations and Warranties. To induce Banks and Administrative Agent to enter into this Second Amendment, Parent and Borrower hereby jointly and severally represent and warrant to Banks and Administrative Agent as follows:

     6.1 Reaffirm Existing Representations and Warranties. Each representation and warranty of Parent and Borrower contained in the Credit Agreement and the other Loan Papers is true and correct in all material respects on the date hereof and will be true and correct in all material respects after giving effect to the amendments set forth in Section 1 hereof.

11

     6.2 Due Authorization; No Conflict. The execution, delivery and performance by Parent and Borrower of this Second Amendment are within Parent’s and Borrower’s corporate or organizational powers, have been duly authorized by all necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not violate or constitute a default under any provision of applicable law or any Material Agreement binding upon Parent, Borrower or their Subsidiaries or result in the creation or imposition of any Lien upon any of the assets of Parent, Borrower or their Subsidiaries except Permitted Encumbrances.

     6.3 Validity and Enforceability. This Second Amendment constitutes the valid and binding obligation of Parent and Borrower enforceable in accordance with its terms, except as (i) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor’s rights generally, and (ii) the availability of equitable remedies may be limited by equitable principles of general application.

Section 7. Representations and Warranties of New Banks. Each New Bank (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Second Amendment, to consummate the transactions contemplated hereby and to become a Bank under the Credit Agreement, (ii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Bank thereunder, (iii) it has received a copy of the Credit Agreement, together with copies of the most recent financial statements delivered pursuant to Section 9.1 thereof, as applicable, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Second Amendment and to become a Bank on the basis of which it has made such analysis and decision independently and without reliance on the Administrative Agent or any other Bank, and (iv) attached hereto is any U.S. Internal Revenue Service or other documentation required to be delivered by it pursuant to Section 14.6 of the Credit Agreement, duly completed and executed by the New Bank; and (b) agrees that (i) it will, independently and without reliance on the Administrative Agent or any other Bank, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Papers, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Papers are required to be performed by it as a Bank.

Section 8. Miscellaneous.

     8.1 Reaffirmation of Loan Papers. Any and all of the terms and provisions of the Credit Agreement and the Loan Papers shall, except as amended and modified hereby, remain in full force and effect. The amendments contemplated hereby shall not limit or impair any Liens securing the Obligations, each of which are hereby ratified, affirmed and extended to secure the Obligations as they may be increased pursuant hereto.

     8.2 Parties in Interest. All of the terms and provisions of this Second Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns.

     8.3 Legal Expenses. Borrower hereby agrees to pay on demand all reasonable fees and expenses of counsel to Administrative Agent incurred by Administrative Agent in

12

connection with the preparation, negotiation and execution of this Second Amendment and all related documents.

     8.4 Counterparts. This Second Amendment may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this Second Amendment until Parent, Borrower, Required Banks, each New Bank and each Bank whose Commitment is increasing hereunder have executed a counterpart. Facsimiles shall be effective as originals.

     8.5 Complete Agreement. THIS SECOND AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG THE PARTIES.

     8.6 Headings. The headings, captions and arrangements used in this Second Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Second Amendment, nor affect the meaning thereof.

     IN WITNESS WHEREOF, the parties hereto have caused this Second Amendment to be duly executed by their respective authorized officers on the date and year first above written.

[Signature Pages to Follow]

13

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

PARENT: DENBURY RESOURCES INC., a Delaware corporation
By:	/s/ Phil Rykhoek
	Phil Rykhoek,
	Senior Vice President and Chief Financial Officer
BORROWER: DENBURY ONSHORE, LLC, a Delaware limited liability company
By:	/s/ Phil Rykhoek
	Phil Rykhoek,
	Senior Vice President and Chief Financial Officer

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

     Each of the undersigned (i) consent and agree to this Second Amendment, and (ii) agree that the Loan Papers to which it is a party shall remain in full force and effect and shall continue to be the legal, valid and binding obligation of such Person, enforceable against it in accordance with its terms.

DENBURY MARINE, L.L.C., a Louisiana limited liability company
By:	/s/ Phil Rykhoek
	Phil Rykhoek,
	Senior Vice President and Chief Financial Officer
DENBURY OPERATING COMPANY, a Delaware corporation
By:	/s/ Phil Rykhoek
	Phil Rykhoek,
	Senior Vice President and Chief Financial Officer
TUSCALOOSA ROYALTY FUND LLC, a Mississippi limited liability company
By:	/s/ Phil Rykhoek
	Phil Rykhoek,
	Senior Vice President and Chief Financial Officer

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

DENBURY GATHERING & MARKETING, INC., a Delaware corporation
By:	/s/ Phil Rykhoek
	Phil Rykhoek,
	Senior Vice President and Chief Financial Officer

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

ADMINISTRATIVE AGENT/BANK: JPMORGAN CHASE BANK, N.A., as Administrative Agent and a Bank
By:	/s/ Brian Orlando
	Brian Orlando
	Vice President

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
FORTIS CAPITAL CORP.
By:	/s/ David Montgomery
Name:	David Montgomery
Title:	Director
By:	/s/ Darrell Holley
Name:	Darrell Holley
Title:	Managing Director

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:

CALYON NEW YORK BRANCH

By:

Name:

Title:

By:

Name:

Title:

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
COMERICA BANK
By:	/s/ Rebecca L. Wilson
Name:	Rebecca L. Wilson
Title:	Assistant Vice President

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
UNION BANK OF CALIFORNIA, N.A.
By:	/s/ Timothy Brendel
Name:	Timothy Brendel
Title:	Assistant Vice President
By:	/s/ Jarrod Bourgeois
Name:	Jarrod Bourgeois
Title:	Vice President

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
BANK OF AMERICA, N.A.
By:	/s/ Stephen J. Hoffman
Name:	Stephen J. Hoffman
Title:	Managing Director

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:

BANK OF SCOTLAND

By:

Name:

Title:

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
COMPASS BANK
By:	/s/ Greg Determann
Name:	Greg Determann
Title:	Vice President

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
WELLS FARGO BANK, N.A.
By:	/s/ Tom K. Martin
Name:	Tom K. Martin
Title:	Vice President

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
THE BANK OF NOVA SCOTIA
By:	/s/ David G. Mills
Name:	David G. Mills
Title:	Director

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
KEYBANK NATIONAL ASSOCIATION
By:	/s/ Todd Coker
Name:	Todd Coker
Title:	Assistant Vice President

[Signature Page]

SIGNATURE PAGE TO
SECOND AMENDMENT TO SIXTH AMENDED
AND RESTATED CREDIT AGREEMENT

BANKS:
U.S. BANK NATIONAL ASSOCIATION
By:	/s/ Mark E. Thompson
Name:	Mark E. Thompson
Title:	Senior Vice President

[Signature Page]

SCHEDULE 2.1

FINANCIAL INSTITUTIONS

	Commitment		Commitment
Banks	Amount		Percentage
JPMorgan Chase Bank, N.A.	$	100,000,000.00		13.333333	%
Fortis Capital Corp.	$	100,000,000.00		13.333333	%
Bank of America, N.A.	$	100,000,000.00		13.333333	%
Wells Fargo Bank, N.A.	$	100,000,000.00		13.333333	%
Union Bank of California, N.A.	$	75,000,000.00		10.000000	%
Comerica Bank	$	50,000,000.00		6.666667	%
Keybank National Association	$	50,000,000.00		6.666667	%
U.S. Bank National Association	$	40,000,000.00		5.333333	%
Calyon New York Branch	$	35,000,000.00		4.666667	%
Bank of Scotland	$	35,000,000.00		4.666667	%
Compass Bank	$	35,000,000.00		4.666667	%
The Bank of Nova Scotia	$	30,000,000.00		4.000000	%
Totals:	$	750,000,000.00		100.000000	%

SCHEDULE 2.1

FINANCIAL INSTITUTIONS

Banks	Domestic Lending Office	Eurodollar Lending Office	Address for Notice
JPMorgan Chase Bank, NA	10 S. Dearborn 19th Floor	10 S. Dearborn 19th Floor	2200 Ross Avenue, 3rd Floor
	Mail Code — IL1-0010	Mail Code — IL1-0010	Mail Code: TX1-2911
	Chicago, Illinois 60603	Chicago, Illinois 60603	Dallas, Texas 75201
	Attn : Cely T. Navarro	Attn : Cely T. Navarro	Attn: Wm. Mark Cranmer
	Tel. No. (312) 385-7058	Tel. No. (312) 385-7058	Tel. No. (214) 965-3225
	Fax No. (312) 385-7107	Fax No. (312) 385-7107	Fax No. (214) 965-3280
Fortis Capital Corp.	Three Stamford Plaza	Three Stamford Plaza	15455 North Dallas Parkway
	301 Tressa Blvd.	301 Tressa Blvd.	Suite 1400
	Stamford, Connecticut 06901	Stamford, Connecticut 06901	Addison, Texas 75001
Bank of America, N.A.	901 Main Street, 67th Floor	901 Main Street, 67th Floor	901 Main Street, 67th Floor
	Dallas, Texas 75202	Dallas, Texas 75202	Dallas, Texas 75202
Wells Fargo Bank, N.A.	1740 Broadway	1740 Broadway	1445 Ross Avenue, Suite 2360
	MAC# C7300-034	MAC# C7300-034	MAC# T5303-233
	Denver, Colorado 80274	Denver, Colorado 80274	Dallas, Texas 75202
Union Bank of California, N.A.	1980 Saturn Street, V03-251	1980 Saturn Street, V03-251	500 North Akard, Suite 4200
	Monterey Park, California 91755	Monterey Park, California 91755	Dallas, Texas 75201
Comerica Bank	39200 West 6 Mile Road	39200 West 6 Mile Road	Comerica Bank Tower
	Lavonia, Michigan 48152	Lavonia, Michigan 48152	1717 Main Street, 4th Floor, MC6593
			Dallas, Texas 75201
Keybank National Association
U.S. Bank National Association
Calyon New York Branch	1301 Avenue of the Americas	1301 Avenue of the Americas	1000 Louisiana, Suite 5360
	New York, New York 10019	New York, New York 10019	Houston, Texas 77002
Bank of Scotland	565 Fifth Avenue, 5th Floor	565 Fifth Avenue, 5th Floor	565 Fifth Avenue, 5th Floor
	New York, New York 10017	New York, New York 10017	New York, New York 10017
Compass Bank	24 Greenway Plaza, Suite 1400A	24 Greenway Plaza, Suite 1400A	24 Greenway Plaza, Suite 1400A Houston, Texas 77046
	Houston, Texas 77046	Houston, Texas 77046
The Bank of Nova Scotia

Administrative Agent — Address:
2200 Ross Avenue, 3^rd Floor
Mail Code: TX1-2911
Dallas, Texas 75201
Tel No. (214) 965-3225
Fax No. (214) 965-3280

EX-10.(B)

Exhibit 10 B

Option Agreement

By and Between

TEXCAL ENERGY SOUTH TEXAS, L.P.

(“Optionor”)

and

DENBURY ONSHORE, LLC

(“Optionee”)

dated

November 1, 2006

TABLE OF CONTENTS

			Page
ARTICLE 1		DEFINITIONS		1
ARTICLE 2		OPTION TO PURCHASE		13
	2.1	Option to Purchase		13
	2.2	Term of Option		14
	2.3	Initial Term Installments		14
	2.4	Exercise of Option to Purchase		14
	2.5	Payment for Assets		14
	2.6	Closing		16
	2.7	Development Plan and Capital Expenditure Commitment		16
ARTICLE 3		OPERATIONS		17
	3.1	Operations of Hastings Field Prior to Exercise of Option		17
	3.2	Operations After Option Exercise		18
	3.3	Simultaneous Use of Surface		18
ARTICLE 4		OPTIONOR’S REPRESENTATIONS AND WARRANTIES		19
ARTICLE 5		OPTIONEE’S REPRESENTATIONS AND WARRANTIES		21
ARTICLE 6		ACCESS TO INFORMATION AND INSPECTIONS		22
	6.1	Title Files		22
	6.2	Other Files		22
	6.3	Confidentiality Agreement		23
	6.4	Inspections		23
	6.5	No Warranty or Representation on Optionor’s Information		24
	6.6	Amendments to Exhibits		24
ARTICLE 7		ENVIRONMENTAL MATTERS AND ADJUSTMENTS		24
	7.1	Investigation		24
	7.2	Waiver of Defects		25
	7.3	Remedy		25
	7.4	Default Basket		25
	7.5	Closing		26
ARTICLE 8		TITLE DEFECTS AND ADJUSTMENTS		26
	8.1	Existing Title; Definitions		26

-i-

			Page
	8.2	Notice of Title Defects		29
	8.3	Title Defect Adjustment		30
	8.4	Environmental Defect and Title Defect Values		31
	8.5	Title Warranty		32
ARTICLE 9		PREFERENTIAL PURCHASE RIGHTS AND CONSENTS OF THIRD PARTIES		33
	9.1	Actions and Consents		33
ARTICLE 10		COVENANTS OF OPTIONOR AND OPTIONEE		34
	10.1	Covenants of Optionor Pending Closing		34
	10.2	Limitations on Optionor’s Covenants Pending Closing		35
	10.3	Covenents of Optionee Following Exercise of Option		36
	10.4	Hastings Field Call on CO2		36
	10.5	Ownership of CO2		36
	10.6	Environmental Liabilities Related to Events and Activities Occuring Prior to October 1, 2004		36
ARTICLE 11		CLOSING CONDITIONS		37
	11.1	Optionor’s Closing Conditions		37
	11.2	Optionee’s Closing Conditions		37
ARTICLE 12		CLOSING		38
	12.1	Closing		38
	12.2	Optionor’s Closing Obligations		38
	12.3	Optionee’s Closing Obligations		39
	12.4	Joint Closing Obligations		39
	12.5	Final Settlement/Purchase Price Adjustments		39
ARTICLE 13		LIMITATIONS ON WARRANTIES AND REMEDIES		41
ARTICLE 14		CASUALTY LOSS AND CONDEMNATION		41
ARTICLE 15		DEFAULT AND REMEDIES		42
	15.1	Optionor’s Remedies		42
	15.2	Optionee’s Remedies		42
	15.3	Effect of Termination		42
ARTICLE 16		ASSUMPTION AND INDEMNITY		42
	16.1	Assumed Obligations; Pre-Closing Liabilities		42
	16.2	Optionee’s Indemnity		43

ii

			Page
	16.3	Optionor’s Indemnity		43
	16.4	Negligence		44
	16.5	Broker or Finder’s Fee		44
	16.6	Threshold and Maximum Amounts		44
	16.7	Claim Procedures		44
ARTICLE 17		GAS IMBALANCES		45
ARTICLE 18		PREFERENTIAL RIGHT TO PURCHASE AND AREA OF MUTUAL INTEREST PROVISION		46
	18.1	Preferential Right to Purchase		46
	18.2	Area of Mutual Interest Provision		47
ARTICLE 19		MISCELLANEOUS		49
	19.1	Receivables and other Excluded Funds		49
	19.2	Public Announcements		49
	19.3	Filing and Recording of Assignments, etc		50
	19.4	Further Assurances and Records		50
	19.5	Notices		51
	19.6	Incidental Expenses		52
	19.7	Waiver		52
	19.8	Binding Effect; Assignment		53
	19.9	Taxes		53
	19.10	Audits		54
	19.11	Governing Law		54
	19.12	Mediation and Arbitration		54
	19.13	Entire Agreement		54
	19.14	Severability		54
	19.15	Exhibits		55
	19.16	Survival		55
	19.17	Subsequent Adjustments		55
	19.18	Counterparts		55
	19.19	Subrogation		55
	19.20	Suspended Monies		56
	19.21	Optionee as Operator		56

iii

EXHIBITS

Exhibit A-1	West Hastings Unit Leases
Exhibit A-2	East Hastings Leases
Exhibit A-3	Mineral Deeds, Royalty Deeds in West Hastings Unit
Exhibit A-4	Mineral Deeds, Royalty Deeds in East Hastings Field
Exhibit A-5	Surface Leases and Surface Deeds in West Hastings Unit
Exhibit A-6	Surface Leases and Surface Deeds in East Hastings Field
Exhibit A-7	Easements and Rights-of-Way in West Hastings Unit
Exhibit A-8	Easements and Rights-of-Way in East Hastings Field
Exhibit B-1	West Hastings Unit Wells
Exhibit B-2	East Hastings Field Wells
Exhibit C	Lease Ownership; Ownership and Unit Participation of Tracts in West Hastings Unit
Exhibit D-1	West Hastings Unit and East Hastings Field Map
Exhibit E	West Hastings Unit Operating Agreement
Exhibit F-1	Contracts and Agreements for West Hastings Unit
Exhibit F-2	Contracts and Agreements for East Hastings Field
Exhibit G	Option Exercise Notice
Exhibit H	Claims and Suits
Exhibit I	Assignment and Conveyance
Exhibit J	Assignment of Volumetric Production Payment
Exhibit K	Waivers, Consents, Rights of First Refusal and Preferential Rights to Purchase
Exhibit L	Gas Imbalances
Exhibit M	Non-foreign Affidavit

iv

Exhibit N	Reporting and Accounting Memorandum
Exhibit O	Area of Mutual Interest Plat
Exhibit O-1	Area of Mutual Interest Lands
Exhibit P	Dispute Resolution Procedure
Exhibit Q	Joint Operating Agreement

v

OPTION AGREEMENT

          This Option Agreement (“Agreement”), dated as of November 1, 2006, is by and between TexCal Energy South Texas, L.P. whose address is 1021 Main Street, Suite 2500, Houston, Texas 77002 (“Optionor”), and Denbury Onshore, LLC, whose address is 5100 Tennyson Parkway, Suite 1200, Plano, Texas 75024 (“Optionee”). Optionor and Optionee are sometimes together referred to herein as “Parties”.

R E C I T A L S

          WHEREAS, Optionor owns certain oil and gas leasehold interests and related assets more fully described on the exhibits hereto; and

          WHEREAS, Optionor desires to grant, and Optionee desires to acquire, the right and option to purchase these interests and related assets on the terms and conditions hereinafter provided;

          NOW, THEREFORE, in consideration of the mutual covenants and agreements hereinafter set forth, Optionor and Optionee hereby agree as follows:

ARTICLE 1. — DEFINITIONS

     1.1. “Acquiring Party” has the meaning specified in Section 18.2(b).

     1.2. “Agreement” shall mean this Option Agreement between Optionor and Optionee.

     1.3. “Agreement Effective Time” shall mean 7:00 a.m., Central Standard Time, on November 1, 2006.

     1.4. “Area of Mutual Interest” has the meaning specified in Section 18.2(a)

     1.5. “Asset Operating Expense” has the meaning specified in Section 2.5(b)(i)(3).

     1.6. “Asset Payout Amount” has the meaning specified in Section 1.26(d)(4).

     1.7. “Assets” shall mean the following described assets and properties (except to the extent constituting Excluded Assets):

     (a) the Leases;

     (b) the Personal Property and Incidental Rights;

     (c) the Inventory Hydrocarbons;

1

     (d) the West Hastings Unit; and

     (e) the East Hastings Field.

     1.8. “Assumed Obligations” shall mean with respect to the Assets:

     (a) all Environmental Obligations or Liabilities (i) related to, or arising from, events first occurring after the Exercise Effective Time, and (ii) related to, or arising from, events first occurring or in existence prior to October 1, 2004, to the extent and as set out in Section 10.6;

     (b) all obligations with respect to gas production, sales or, subject to Article 17, processing imbalances with third parties;

     (c) all liabilities, duties, and obligations that arise out of the ownership, operation or use of the Assets after the Exercise Effective Time, other than Environmental Obligations or Liabilities, including, but not limited to, all liabilities, duties, and obligations, express or implied, imposed upon Optionor herein under the provisions of the Leases and any and all assignments, subleases, farmout agreements, assignments of overriding royalty, joint operating agreements, easements, rights-of-way, and all other contracts, agreements and instruments affecting the Leases, or the premises covered thereby, whether recorded or unrecorded, and under all applicable laws, rules, regulations, orders and ordinances, excluding the claims and suits set forth in Exhibit “H” and any claims or suits identified in the Option Exercise Notice which relate to liabilities incurred after the Agreement Effective Time and prior to Closing.

     1.9. “Capital Costs” has the meaning specified in the definition of Excluded Assets.

     1.10. “Cash Payment” has the meaning specified in Section 2.5.

     1.11. “Casualty Loss” has the meaning specified in Article 14.

     1.12. “Claims” has the meaning specified in Sections 16.2.

     1.13. “Closing” has the meaning specified in Section 12.1.

     1.14. “Closing Date” has the meaning specified in Section 12.1

     1.15. “Conditions Precedent” has the meaning specified in Section 2.1.

     1.16. “Consents” has the meaning specified in Section 9.1(b)

     1.17. “Cure Period” has the meaning specified in Section 8.3(a)

     1.18. “D&M” has the meaning specified in Section 2.5(b)

     1.19. “D&M Report” has the meaning specified in Section 2.5(b)

2

     1.20. “Defensible Title”, subject to and except for the Permitted Encumbrances has the meaning specified in Section 8.1(a).

     1.21. “Designated Interest” shall mean: (i) as to the West Hastings Unit, a working interest of 89.33682% and a net revenue interest of 78.94105%; (ii) as to the East Hastings Field, a working interest of 100% and a net revenue interest of 87.5%; (iii) as to a Lease in the West Hastings Unit, the working interest and net revenue interest set forth for such Lease in Exhibit “C”; (iv) as to a Lease in the East Hastings Field, the working interest and net revenue interest set forth for such Lease in Exhibit “C”; as to a well in the West Hastings Unit, the working interest and net revenue interest set forth for such well in Exhibit “B-1”; as to a well in the East Hastings Field, the working interest and net revenue interest set forth for such well in Exhibit “B-2”; and, as to any other Asset, the ownership interest of Optionor in such Asset to be conveyed to Optionee, less and except the Optionor’s reserved overriding royalty interest as set forth in Section 1.27(a). If following the Agreement Effective Time and prior to the Option Exercise Date Optionor acquires additional interests in the Hastings Field, the Designated Interests shall be adjusted to reflect such acquisitions(s). The Designated Interests for all of the above Assets are referred to collectively as the “Designated Interests.”

     1.22. “Development Plan” has the meaning set forth in Section 2.7.

     1.23. “Environmental Defect Notice Date” has the meaning set forth in Section 7.1.

     1.24. “Environmental or Title Defect Value” has the meaning set forth in Section 8.4.

     1.25. “East Hastings Field” shall refer to those lands falling within the geographic outline depicted on the plat in Exhibit “D-1”.

     1.26. “Environmental Defect” shall mean: (i) a condition or activity with respect to an Asset that is in material violation, or reasonably likely to materially violate, any federal, state or local statute, or any rule, order, ruling or regulation entered, issued or made by any court, administrative agency, or other governmental body or entity, federal, state, or local, or any arbitrator (“Environmental Law”), or surface or mineral lease obligation relating to natural resources, conservation, the environment, or the emission, release, storage, treatment, disposal, transportation, handling or management of industrial or solid waste, hazardous waste, hazardous or toxic substances, chemicals or pollutants, petroleum, including crude oil, natural gas, natural gas liquids, or liquefied natural gas, and any wastes associated with the exploration and production of oil and gas (“Regulated Substances”); or (ii) the presence of Regulated Substances in the soil, groundwater, or surface water in, on, at or under an Asset in any manner or quantity which is required to be remediated by Environmental Law or by any applicable action or guidance levels or other standards published by any governmental agency with jurisdiction over the Assets, or by a surface or mineral lease obligation. Optionee and Optionor agree that for a condition to be in violation of any statute or regulation it

3

shall not be necessary that Optionor shall be under notice of violation from a federal or state regulatory agency or lessor.

          The Parties agree and acknowledge that Optionee will be provided an opportunity to examine the Assets for potential naturally occurring radioactive materials (“NORM”), and any potential obligations with respect to NORM and that the presence of NORM on any of the Assets, except with respect to inactive wells, facilities, pipelines and other equipment, may not be raised by Optionee as the subject of an Environmental Defect.

     1.27. “Environmental Law” shall be as defined in Section 1.26 above.

     1.28. “Environmental Obligations or Liabilities” shall mean all liabilities, obligations, expenses (including, without limitation, all attorneys’ fees), fines, penalties, costs, claims, suits or damages (including natural resource damages) of any nature, associated with the Assets, and attributable to or resulting from: (i) pollution or contamination of soil, groundwater or air, on, in or under the Assets or lands in the vicinity thereof, and any other contamination of or adverse effect upon the environment, (ii) underground injection activities and waste disposal, (iii) clean-up responses, remedial, control or compliance costs, including the required cleanup or remediation of spills, pits, lakes, ponds, or lagoons, including any subsurface or surface pollution caused by such spills, pits, lakes, ponds, or lagoons, (iv) noncompliance with applicable land use, permitting, surface disturbance, licensing or notification requirements, including those in a surface or mineral lease, whether an express or implied obligation, (v) all obligations, whether pursuant to an Environmental Law or a surface or mineral lease obligation, whether express or implied, for plugging, replugging and abandoning any wells, the restoration of any well sites, tank battery sites and gas plant sites, and any other surface locations or sites, the proper removal, disposal and abandonment of any wastes or fixtures, and the proper capping and burying of all flow lines, which are included in the Assets; (vi) violation of any federal, state or local Environmental Law or land use law, or surface or mineral lease obligation, whether an express or implied obligation, and (vii) any other violation which could qualify as an Environmental Defect. Notwithstanding anything to the contrary set forth in, or implied by, this Section 1.28, “Environmental Obligations or Liabilities” does not include (i) personal injury or wrongful death occurring prior to the Exercise Effective Time or (ii) offsite waste disposal occurring prior to the Exercise Effective Time.

     1.29. “Excluded Assets” shall mean the following:

     (a) an overriding royalty interest from the Exercise Effective Time in production from the Assets equal to an undivided two percent of eight-eighths (2% of 8/8ths), which overriding royalty interest shall be reserved by Optionor. Said reserved overriding royalty interest shall be free of (i) any and all costs and expenses associated with the exploration, production or operation of wells producing from the Assets, and (ii) post production costs associated with removing CO2 from the production stream, and shall be paid in the same manner as provided for with respect to lessors. In the event Optionor exercises its option to receive the Reversionary Interest set forth in Section 1.29 (d)

4

below, then Optionor’s Reversionary Interest will bear its proportionate share of the reserved overriding royalty interest.

     (b) all interests in the surface estate in Hastings Field Lands, including but not limited to those described in Exhibits “A-5” and “A-6”;

     (c) all of Optionor’s leasehold, fee mineral and royalty interests in the Hastings Field, as such interests relate to horizons above the top of, and below the base of, the Frio Zone.

     (d) a reversionary working interest of an undivided twenty-five percent (25%) in and to the Assets assigned hereunder, (the “Reversionary Interest”), at such time as the Optionee has achieved Payout. “Payout” shall mean that point in time when Optionee has received from Net Revenues from the Assets an amount equal to (i) one hundred percent (100%) of the sum of Operating Costs plus the Asset Payout Amount plus (ii) one hundred thirty percent (130%) of all Capital Costs expended to conduct enhanced recovery operations on the Assets. It being the intent of the Parties that the Optionor shall convey to Optionee at Closing the Designated Interest (less Optionor’s reserved overriding royalty interest) as to the Assets, subject to the Optionor’s Reversionary Interests. Optionor’s Reversionary Interests as set forth above will be proportionately adjusted to correspond with Optionee’s actual working interest and/or net revenue interest, respectively, acquired by virtue of this Agreement. Subject to Optionor’s post Payout election as provided in Section 1.26(d)(11) below, Optionor’s Reversionary Interests shall automatically revert to the Optionor once Payout has been achieved, without any further action on the part of the Optionor. Optionor’s Reversionary Interests will be effective on the first day of the month next succeeding the point in time in which Payout has occurred. Within thirty (30) days after Payout has occurred, and subject to Optionor’s right to reject reversion, Optionee shall provide Optionor with an Assignment of the Optionor’s Reversionary Interests, which will be free and clear of all liens and encumbrances of any kind and shall be substantially in the form of the Assignment and Conveyance attached hereto as Exhibit “I”.

Calculation of Payout and Optionor’s Reversionary Interests shall be subject to the following additional terms and provisions:

     (1) As used herein, “Net Revenues” shall mean with respect to the Assets, gross revenues from the Designated Interest share of production from the Assets from and after the Exercise Effective Time less any applicable federal, state and local taxes (including excise, production, severance, sales, and ad valorem taxes, but excluding any income based taxes) and less payments from gross revenues attributable to Optionor’s reserved overriding royalty interest, and any other overriding royalty interests, production payments, net profit interest and similar interests or burdens of record against the Assets existing as of the Agreement Effective Time and paid after the Exercise Effective Time.

5

     (2) As used herein, “Operating Costs” shall mean with respect to the Assets from and after the Exercise Effective Time, the Designated Interest share of (i) operating costs and expenses (including administrative overhead charges) for the operation of wells, facilities, equipment and flowlines located on and/or used in conjunction with the Assets, actually incurred and expended by Optionee and/or the Operator and charged to the joint account by Optionee and/or the Operator, as set forth in the Accounting Procedure of the West Hastings Unit Operating Agreement or the applicable operating agreement for any East Hastings Field wells (in the event there is no applicable operating agreement, the Accounting Procedure of the West Hastings Unit Operating Agreement shall be utilized) and (ii) CO2 Costs.

     (3) As used herein, “Capital Costs” shall mean with respect to the Assets, the Designated Interest share of all capital costs actually incurred and expended by the Operator for enhanced oil recovery operations and charged to the joint account by Optionee and/or the Operator from and after the Exercise Effective Date, including for the construction of facilities, field development, conversion of wells for injection purposes, drilling, completion, reworking, recompletion of wells, construction of flowlines located on and/or used in conjunction with such Assets, and such other costs as are incurred under the Development Plan and credited towards the Required Cumulative Capital Expenditure Amounts provided in Section 2.7(a) below.

     (4) As used herein, “Asset Payout Amount” shall mean the sum of the predicted “annual future net revenue” (as such terms are currently used by D&M in the reserve report prepared for Optionor dated July 31, 2006) for the first four years following the Exercise Effective Time, as shown in the D&M Report used to determine the Purchase Price for the Assets.

     (5) As used herein, “CO2 Costs” shall mean the direct cost of acquiring (commodity cost) and delivering (transportation cost) CO2 to the Assets.

     (i) transportation costs (before and after Payout) shall be (x) the actual costs on a per mcf basis charged by unaffiliated third party transporters, or (y) in the event Optionee owns the pipeline transporting CO2 to the Assets, a per mcf fee not to exceed the amount necessary to amortize the actual cost of constructing and operating that portion of the line on which the CO2 is transported to the Assets, based on a capacity throughput of 400 MMcf/d over a twenty (20) year period, at a discount rate of six hundred fifty basis points over the one year LIBOR (if the one year LIBOR is five and one-half percent (5.5%) the discount rate used to amortize the pipeline would be 12%), but in no event shall the discount rate be less than 12%.

     (ii) commodity costs (before and after Payout) shall be the lower of (x) the average direct cost of CO2 in Optionee’s or third party’s pipeline from which CO2 is acquired for the Assets and (y) the lowest price

6

charged for CO2 by Optionee in sales to third party users or consumers in Texas. In no event shall the average cost per mcf of CO2 delivered to the Assets exceed one percent (1%) of the average NYMEX oil closing price per barrel during the month of delivery; provided the foregoing cap on CO2 prices shall never be less than $.30 per mcf. A “mcf” of CO2 shall be 1000 cubic feet of CO2 at standard conditions. Optionee shall deliver CO2 to the Assets at a pipeline pressure of not less than 1100 psi.

     (iii) Any CO2 charged to the Assets and used by Optionee for any purpose other than with respect to the development of the Assets shall be credited as Net Revenues at the same cost that the CO2 is charged as provided above.

     (6) Costs associated with building, owning, operating and maintaining CO2 pipelines used by Optionee to deliver CO2 to the Hastings Field shall not be considered Capital Costs or Operating Costs for purposes of determining Payout. Nor shall such costs be considered in computing Required Cumulative Capital Expenditure Amounts. Nothwithstanding the foregoing, actual transportation costs incurred in transporting CO2 to the Hastings Field, as set forth in Section 1.29(d)(5)(i), shall be considered for purposes of determining Payout.

     (7) Optionor’s Reversionary Interests in the Assets, after it reverts, shall be subject to the terms and provisions of the West Hastings Unit Operating Agreement and/or any other applicable agreements. After such Reversionary Interests revert to Optionor, Optionor shall be liable for and shall assume and pay its proportionate working interest share of all subsequent costs associated with its working interest attributable to the reverted and reassigned interests, including capital costs.

     (8) If for any reason Optionor desires not to accept the Reversionary Interests provided for in this Section 1.29 (d), and the obligations and liabilities associated with such Reversionary Interests, Optionor may decline to accept such Interests by notifying Optionee in writing on or before thirty (30) days after Optionor is notified, in writing, of the effective date of reversion. After receipt of such a notice, Optionor’s right to the Reversionary Interests will terminate effective as of the date of the reversion.

     (9) Prior to Payout, Optionee shall provide to Optionor (i) on a monthly basis operating reports covering revenues, operating expenses, capital expenditures, production and injection volumes and product prices received; and (ii) a quarterly statement (with all supporting documentation) identifying the status of Payout; and (iii) Optionee shall further provide Optionor with quarterly reports including historical and prospective technical information relating to the Assets including, but not limited to injection and production data on a field and well basis, well logs, cores, tests and any other data necessary for Optionor to perform its own technical analysis; and (iv) the right to request an annual technical presentation to be presented to Optionor by the appropriate technical

7

staff of Optionee. Optionor shall have the right to conduct an annual audit of the accounts and records of Optionee (at a mutually convenient time during Assignor’s normal business hours and in accordance with the Council of Petroleum Accountants Society guidelines and practices for audits by working interest owners) to verify the accounting for Payout. Such audits may be performed by Optionor directly or through an independent accounting firm of its choice, but in each case at the Optionor’s sole cost and expense. Notwithstanding the above, all Payout accounting by Optionee during any calendar year shall conclusively be presumed true and correct after twenty four (24) months following the end of any such calendar year, unless within the said twenty four (24) month period, Optionor takes written exception thereto and makes claim on Optionee for adjustments.

     (e) (i) all trade credits, accounts receivable, notes receivable and other receivables attributable to Optionor’s interest in the Assets with respect to any period of time prior to the Exercise Effective Time; (ii) all deposits, cash, checks in process of collection, cash equivalents and funds attributable to Optionor’s interest in the Assets with respect to any period of time prior to the Exercise Effective Time; and (iii) all proceeds, benefits, income or revenues accruing with respect to the Subject Acreage prior to the Exercise Effective Time;

     (f) all corporate, financial, and tax records of Optionor; however, Optionee shall be entitled to receive copies of any tax records which directly relate to any Assumed Obligations, or which are necessary for Optionee’s ownership, administration, or operation of the Assets;

     (g) all claims and causes of action of Optionor arising from acts, omissions or events, or damage to or destruction of the Assets, occurring prior to the Exercise Effective Time; provided, however, Optionor shall transfer to Optionee all claims and causes of action of Optionor against prior owners of the Assets or third parties for Environmental Obligations or Liabilities that are not Retained Environmental Obligations or Liabilities;

     (h) except as otherwise provided in Section 14 all rights, titles, claims and interests of Optionor relating to the Assets prior to the Exercise Effective Time (i) under any policy or agreement of insurance or indemnity; (ii) under any bond; or (iii) to any insurance or condemnation proceeds or awards;

     (i) all Hydrocarbons produced from or attributable to the Assets with respect to all periods prior to the Exercise Effective Time, together with all proceeds from or of such Hydrocarbons, except the Inventory Hydrocarbons and the unsold inventory of gas plant products, if any, attributable to the Leases as of the Exercise Effective Time;

     (j) claims of Optionor for refund of or loss carry forwards with respect to production, windfall profit, severance, ad valorem or any other taxes attributable to any period prior to the Exercise Effective Time, or income or franchise taxes;

8

     (k) all amounts due or payable to Optionor as adjustments or refunds under any contracts or agreements (including take-or-pay claims) affecting the Assets with respect to any period prior to the Exercise Effective Time;

     (l) all amounts due or payable to Optionor as adjustments to insurance premiums related to the Assets with respect to any period prior to the Exercise Effective Time;

     (m) all proceeds, benefits, income or revenues accruing (and any security or other deposits made) with respect to the Assets, and all accounts receivable attributable to the Assets, prior to the Exercise Effective Time; and

     (n) all of Optionor’s intellectual property, including, but not limited to, proprietary computer software, patents, trade secrets, copyrights, names, marks and logos.

     (o) all depths above the top and below the base of the Frio Zone.

     1.30. “Exercise Effective Time” has the meaning specified” shall be defined in Section 2.4.

     1.31. “Final Settlement” has the meaning specified in Section 12.5

     1.32. “ Final Settlement Statement” has the meaning specified in Section 12.5.

     1.33. “Frio Zone” means the stratigraphic interval or its correlative equivalent between the depths of 5,390 feet and 6,840 feet in the Amoco Production Company L.F. McKibben A-6 located on the McKibben “A” Lease of the HT&B Survey 29, Brazoria County, Texas as defined on the Dual Induction-Electric-Lateralog-Sonic Logs run on November 6, 15, 26, and 28, 1977.

     1.34. “Hastings Field” shall refer, collectively, to the East Hastings Field and the West Hastings Unit.

     1.35. “Hydrocarbons” shall mean crude oil, natural gas (including CO₂), casinghead gas, condensate, sulphur, natural gas liquids and other liquid or gaseous hydrocarbons, and shall also refer to all other minerals of every kind and character which may be covered by or included in the Leases and Assets.

     1.36. “Indemnified Party” has the meaning set forth in Section 16.7.

     1.37. “Indemnifying Party” has the meaning set forth in Section 16.7.

     1.38. “Initial Option Payment” has the meaning specified in Section 2.3 (a)

     1.39. “Inventory Hydrocarbons” shall mean all merchantable oil and condensate (for oil or liquids in storage tanks, being only that oil or liquids physically above the top of the inlet connection into such tanks) produced from or attributable to

9

the Leases prior to the Exercise Effective Time which have not been sold by Optionor and are in storage at the Exercise Effective Time.

     1.40. “Leases” shall mean, except to the extent constituting Excluded Assets, any and all interests owned by Optionor, including but without limitation those set forth on Exhibits “A-1”, “A-2”, “A-3” and “A-4”, or which Optionor is entitled to receive by reason of any participation, joint venture, farmin, farmout, joint operating agreement, unitization agreement, or other agreement, in and to the oil, gas and/or mineral leases, permits, licenses, concessions, leasehold estates, royalty interests, overriding royalty interests, net revenue interests, executory interests, net profit interests, working interests, reversionary interests, mineral interests, and any other interests of Optionor in Hydrocarbons, in the West Hastings Unit, in the West Hastings Unit Lands, and in East Hastings Field, it being the intent hereof that the leases, properties and interests and the legal descriptions and depth limitations set forth on Exhibits “A-1” through “A-4”, inclusive, or in instruments described in Exhibits “A-1” through “A-4”, inclusive, if any, are for information only and the term “Leases” includes all of Optionor’s right, title and interest in the above described Hydrocarbon interests in the West Hastings Unit, in the West Hastings Unit Lands, and in the East Hastings Field, other than the Excluded Assets, including but not limited to those described on Exhibits “A-1” through “A-4”, inclusive, or in instruments described in Exhibits “A-1” through “A-4”, inclusive, even though such interests may be incorrectly described in Exhibits “A-1” through “A-4”, inclusive, or omitted from Exhibits “A-1” through “A-4”, inclusive.

     1.41. “mcf” has the meaning specified in the definition of Excluded Assets.

     1.42. “Net Proved Reserves” has the meaning specified in Section 2.5(b)(i)(1)

     1.43. “Net Revenues” has the meaning specified in the definition of Excluded Assets.

     1.44. “NORM” has the meaning set forth in the definition of Environmental Defects.

     1.45. “Oil and Gas Interest” has the meaning specified in Section 18.2(g).

     1.46. “Oil and Gas Interests” has the meaning specified in Section 18.2(b) and 18.2(h).

     1.47. “Operating Costs” has the meaning specified in the definition of Excluded Assets.

     1.48. “Option Exercise Date” has the meaning specified in Section 2.4

     1.49. “Option Exercise Notice” has the meaning given in Section 2.4 .

     1.50. “Option to Purchase” has the meaning specified in Section 2.1.

     1.51. “Option Year” has the meaning specified in Section 2.2.

10

     1.52. “Optionee” has the meaning specified in the Preamble.

     1.53. “Optionee’s Credits” has the meaning specified in Section 12.5(b).

     1.54. “Optionor” has the meaning specified in the Preamble.

     1.55. “Optionor’s Credits” has the meaning specified in Section 12.5(a).

     1.56. “Participating Party” has the meaning specified in Section 18.2(f).

     1.57. “Parties” has the meaning specified in the Preamble.

     1.58. “Payout” shall be as defined in the definition of Excluded Assets.

     1.59. “Permitted Encumbrances” shall mean specified in Section 8.1(c).

     1.60. “Personal Property and Incidental Rights” shall mean all right, title and interest of Optionor in and to or derived from the following insofar as the same do not constitute Excluded Assets and are attributable to, appurtenant to, incidental to, or used for the operation of the Leases:

     (a) all easements, rights-of-way, surface leases, permits, licenses, servitudes or other interests relating to the use of the surface, including but not limited to those described in Exhibits “A-5,” “A-6,” “A-7,” and “A-8”, or in instruments described in Exhibits “A-5,” “A-6,” “A-7,” and “A-8”;

     (b) all wells, including but not limited to those listed in Exhibits “B-1” and “B-2” attached hereto, whether or not such wells are active or inactive, along with all equipment and other personal property, inventory, spare parts, tools, fixtures, pipelines, dehydration facilities, platforms, tank batteries, appurtenances, and improvements situated upon the Leases as of the Exercise Effective Time and used or held for use in connection with the development or operation of the Leases or the production, treatment, storage, compression, processing or transportation of Hydrocarbons from or in the wells or Leases;

     (c) all unit agreements, orders and decisions of state and federal regulatory authorities establishing units, joint operating agreements, enhanced recovery and injection agreements, farmout agreements and farmin agreements, options, drilling agreements, exploration agreements, assignments of operating rights, working interests, subleases and rights above or below certain footage depths or geological formations, to the extent same is attributable to the Assets, as of the Exercise Effective Time, including but not limited to those described on Exhibits “F-1” and “F-2”;

     (d) all contracts, agreements, and title instruments to the extent attributable to and affecting the Assets in existence at Closing, including all Hydrocarbon sales, purchase, gathering, transportation, treating, marketing, exchange, processing, disposal and fractionating contracts, joint operating agreements, including but not limited to those described on Exhibits “F-1” and “F-2”; and

11

     (e) copies of all lease files, land files, well files, production records, division order files (including paysheets and supporting files), abstracts, title opinions, and contract files, insofar as the same are directly related to the Leases; including, without limitation, all geological, information and data, to the extent that such data is not subject to any third party restrictions, but excluding Optionor’s proprietary interpretations of same, subject to the provisions of Section 6.1.

     1.61. “Proved Reserves” shall mean the reserves attributable to the interest being evaluated based on the definition of “proved oil and gas reserves” as set forth in Rule 4-10 of Regulation S-X of the Securities and Exchange Act of 1934, as amended; provided that Hydrocarbon prices and operating costs set forth in section 2.5 shall be used in such determination.

     1.62. “Preferential Purchase Rights” has the meaning specified in Section 9.1(b).

     1.63. “Purchase Price” has the meaning specified in Section 2.5.

     1.64. “Receiving Party” has the meaning specified in Section 18.1(a).

     1.65. “Regulated Substances” has the meaning specified in the definition of Environmental Defects.

     1.66. “Required Cumulative Capital Expenditure Amounts” has the meaning specified in Section 2.7(b).

     1.67. “Retained Environmental Obligations or Liabilities” shall mean, any Environmental Obligations or Liabilities of any nature (i) related to the Excluded Assets, and (ii) related to, or arising from, events first occurring or in existence prior to October 1, 2004, to the extent and as set out in Section 10.6.

     Notwithstanding anything herein to the contrary, Retained Environmental Obligations or Liabilities shall not include any Environmental Obligations or Liabilities that (a) relate to NORM, or (b) relate to the plugging and abandonment of the wells in the Hastings Field existing at the Exercise Effective Time and any related surface restoration of these well sites, or (c) resulted from or relate to an activity or a condition on or regarding the Assets first occurring after the Exercise Effective Time .

     1.68. “Retained Obligations” shall mean all liabilities, duties, and obligations that arise out of the ownership, operation or use of the Assets prior to the Exercise Effective Time, other than Environmental Obligations or Liabilities but including, without limitation, all liabilities, duties, and obligations, express or implied, imposed upon Optionor herein under the provisions of the Leases and any and all assignments, subleases, farmout agreements, assignments of overriding royalty, joint operating agreements, easements, rights-of-way, and all other contracts, agreements and instruments affecting the Leases, or the premises covered thereby, whether recorded or unrecorded, and under all applicable laws, rules, regulations, orders and ordinances, except for those specifically included in the definition of “Assumed Obligations.”

12

     1.69. “Reversionary Interest” has the meaning specified in the definition of Excluded Assets.

     1.69. “Residual Asset Reserve Value” has the meaning specified in Section 2.5(b)(ii)(3).

     1.70. “Selling Party” has the meaning specified in Section 18.1(a).

     1.71. “Shortage Payment” has the meaning specified in Section 2.7(b).

     1.72. “Third Party Interests” has the meaning specified in Section 9.1(c).

     1.73. “Title Defect” has the meaning specified in Section 8.1(b).

     1.74. “Title Defect Notice Date” has the meaning specified in Section 8.2.

     1.75. “Volumetric Production Payment” has the meaning specified in Section 2.5.

     1.76. “West Hastings Unit” shall be as described in and governed by Unit Agreement, West Hastings Unit, Brazoria and Galveston Counties, Texas, dated July 24, 1984, recorded in Volume 218, Page 637 of the Official Records of Brazoria County, TX and recorded as Instrument #8550106 of the Official Public Records of Galveston County, TX, as amended, and as depicted on the plat in Exhibit “D-1”. Those lands located within the aerial boundaries of the West Hastings Unit are referred to as the “West Hastings Unit Lands.” Exhibit “D-1” also depicts the unit tracts within the West Hastings Unit. The ownership of these unit tracts and the participation factors for these tracts in the Unit are set forth in Exhibit “C”.

     1.77. “West Hastings Unit Lands” has the meaning specified in the definition of West Hastings Unit.

     1.78. “West Hastings Unit Operating Agreement” shall mean that certain Unit Operating Agreement, West Hastings Unit, Brazoria and Galveston Counties, Texas unit operating agreement dated December 20, 1984, covering the West Hastings Unit, as may be amended, and which is attached hereto as Exhibit “E.”

ARTICLE 2. — OPTION TO PURCHASE

     2.1. Option to Purchase. Subject to the terms and conditions of this Agreement and the satisfaction of the Conditions Precedent on or before December 1, 2006, Optionor does hereby grant and convey unto Optionee the right and option to purchase the Assets according to the terms and provisions set forth below (the “Option to Purchase”). As used herein, the term “Conditions Precedent” mean (a) with respect to Optionor, the receipt by Optionor of the written consent and approval of the lenders under Optionor’s revolving credit facility to the grant of this Option to Purchase and the transactions contemplated hereby, on terms satisfactory to Optionor and (b) with respect to Optionee, confirmation by Optionee that there are no material Title Defects

13

and Environmental Defects associated with the Assets. If the Conditions Precedent have not been satisfied or waived by December 1, 2006 this Agreement shall automatically terminate and neither party shall have any further obligation hereunder.

     Each Party shall notify the other in writing on or before November 30, 2006 whether or not the Conditions(s) Precedent for that party have been satisfied.

     2.2. Term of Option. The initial term of the Option to Purchase shall commence on the Agreement Effective Time and end October 31, 2009. The initial option payment, subject to the Conditions Precedent, shall be paid by Optionee on or before December 1, 2006. Optionee may extend the term of the Option to Purchase beyond October 31, 2009 on a year by year basis (i.e., through the anniversary date, October 31, of the following year), by, on or before each anniversary date, paying Optionor the sum of thirty million dollars ($30,000,000.00). The maximum term of the Option to Purchase shall be ten (10) years (i.e., ending October 31, 2016). Each year the Option to Purchase is in effect is hereinafter referred to as an “Option Year”.

     2.3. Initial Term Installments. The consideration for the initial term of the Option to Purchase shall be fifty million dollars ($50,000,000) paid by Optionee to Optionor by wire transfer in the following installments:

     (a) Thirty-seven and one-half million dollars ($37,500,000.00) on or before December 1, 2006;

     (b) Seven and one-half million dollars ($7,500,000.00) on or before November 1, 2007; and

     (c) Five million dollars ($5,000,000.00) on or before November 1, 2008.

     2.4. Exercise of Option to Purchase. During the term of the Option to Purchase, Optionee may exercise its Option to Purchase by giving notice of its exercise of said Option to Purchase (“Option Exercise Notice”) as provided herein. The Option Exercise Notice shall be made utilizing the form of Option Exercise Notice attached hereto as Exhibit “G” and shall be given on or before September 1 of any year during the term of this Option and shall be deemed exercised as of November 1 of such year (the “Option Exercise Date”). Without Optionor’s written consent, no Option Exercise Notice may be given prior to September 1, 2008. The effective date for the purchase of the Assets shall be 7:00 a.m., Central Standard Time, on January 1 following such Option Exercise Date (“Exercise Effective Time”). Optionee’s right to utilize the Asset shall be effective as of the Exercise Effective Time.

     2.5. Payment for Assets. The consideration due Optionor by Optionee for the purchase of the Assets (the “Purchase Price”) shall be either (i) a cash payment (“Cash Payment”), or (ii) a volumetric production payment (“Volumetric Production Payment”), to be determined as set forth below.

     (a) Optionor and Optionee shall have until the end of the month of November following an Option Exercise Date to negotiate and agree upon, based upon the

14

remaining amount and value of Net Proved Reserves attributable to the Assets, the Cash Payment amount to be paid by Optionee or the terms of the Volumetric Production Payment to be conveyed to Optionor, with respect to the Assets.

     (b) In the event Optionor and Optionee are unable to agree as provided under Section 2.5(a), above, then, on or before December 1 of such year, either Party may request that DeGolyer and MacNaughton (“D&M”) furnish the Parties with a report (the “D&M Report”) setting forth the following:

     (i) A Cash Payment amount equal to the present value of Net Proved Reserves, determined as follows:

     (1) D&M’s estimate of Net Proved Reserves for the Assets as of the end of the year in which the option is exercised (as utilized herein, “Net Proved Reserves” shall refer to Proved Reserves, net to the Designated Interest, i.e., the applicable net revenue interest, and after further deducting Optionor’s retained overriding royalty interest);

     (2) Pricing based upon a five (5) year forward strip as determined on the last trading day of the oil futures contracts on the NYMEX for the year in which the option is exercised, with prices for year six (6) and beyond based on the average NYMEX price for the fifth year of the strip;

     (3) Operating expenses for the calculation of the Cash Payment shall be based upon a review and average of Optionor’s operating expenses attributable to the Assets for twelve (12) months prior to the Exercise Effective Time on a dollar per BOE basis (“Asset Operating Expense”); and

     (4) A net present value discount rate of ten (10%) percent.

     (ii) The following Volumetric Production Payment terms:

     (1) Net Proved Reserve volume schedule for the Assets for the ten (10) years following the Exercise Effective Time;

     (2) The Asset Operating Expense; and

     (3) The Residual Asset Reserve Value for the Proved Reserves attributable to time periods after said ten (10) year period, calculated in the same manner as provided under Section 2.5(b)(i), above, and paid in a lump sum.

Both Parties may furnish D&M with any data and information they feel pertinent to the determination. D&M shall deliver the D&M Report to both Parties no later than January 15 of the calendar year following the Option Exercise Date. D&M’s determinations on the above shall be final and nonappealable. In the event D&M is not in existence at the time the Option Exercise Notice is given, the successor company to D&M shall be utilized, and should no successor company exist, then the Parties shall agree on an

15

independent reserve analysis company to make the above determinations in lieu of D&M.

     (c) Optionor shall have fifteen (15) days after receipt of the D&M Report to notify Optionee of its election whether to receive a Cash Payment or a Volumetric Production Payment. In the event Optionor fails to elect within said time period, Optionor shall be deemed to have elected to receive a Cash Payment.

     2.6. Closing. The closing of the purchase of the Assets shall occur at Optionor’s offices on January 31 of the calendar year following the Option Exercise Date (or the next business day, if such January 31 falls on a weekend or legal holiday) or such other time and place as may be agreed upon by the Parties. At such Closing, (i) Optionor shall execute an Assignment and Conveyance in the form substantially the same as the form attached as Exhibit “I”, and (ii) depending upon Optionor’s election, Optionee shall either pay the Cash Payment or execute an Assignment of Volumetric Production Payment in substantially the same form as the form attached as Exhibit “J”.

     2.7. Development Plan and Capital Expenditure Commitment.

     (a) In the event Optionee exercises its option to purchase the Assets, contemporaneous with Optionee’s option exercise, Optionee shall (i) submit to Optionor a development plan for the CO2 flood of the West Hastings Unit (the “Development Plan”), which plan shall include various milestones including completion of a pipeline connecting the Jackson Dome Field in Mississippi to the Hastings Field via Donaldsonville, Louisiana, or other pipeline or alternative delivery system that would result in a lower CO2 cost to the Hastings Field, a framework for spending the Required Cumulative Capital Expenditure Amounts, and the commencement of CO2 injection in the West Hastings Unit and (ii) commit to spend one hundred seventy-eight million six hundred seventy four thousand dollars ($178,674,000.00) of cumulative capital expenditures (the “Required Cumulative Capital Expenditure Amounts”) as outlined in the Development Plan for field development and facilities for enhanced production operations in the West Hastings Unit. Optionee shall spend the Required Cumulative Capital Expenditures Amounts on or before the Commitment Dates set forth below:

“Commitment Date”	“Required Cumulative Capital
By end of Calendar Year	Expenditure Amount”
1	$	26,801,000
2	$	71,469,000
3	$	107,204,000
4	$	142,939,000
5	$	178,674,000

Year 1 shall begin with the Exercise Effective Time. If the Optionee spends in excess of one hundred seventy-eight million six hundred seventy four thousand dollars ($178,674,000.00) prior to the end of Year 5, the development obligation has been fulfilled.

16

     (b) In the event Optionee fails to spend the Required Cumulative Capital Expenditure Amount by the Commitment Dates set forth in (a) above, Optionee shall pay Optionor a cash payment equal to ten percent, (10.0%) of the difference between (i) the Required Cumulative Capital Expenditure Amount for the applicable Commitment Date and (ii) the cumulative capital expenditures actually expended by Optionee from the Closing Date through such applicable Commitment Date (hereinafter referred to as the “Shortage Payment”). Said Shortage Payment shall be paid by Optionee to Optionor within thirty (30) days after each Commitment Date.

     (c) If Optionee is not injecting at least an average of 50 mmcf/day of CO2 (total of purchased plus recycled) in the West Hastings Unit (“Minimum Injection Rate”), which gas shall be delivered to the Hastings Field via the Donaldsonville to Hastings pipeline or other pipeline or alternative delivery system that would result in a lower CO2 cost to the Hastings Field, for the 90 day period preceding the third anniversary of the Exercise Effective Time, Optionee shall, within 30 days of such third anniversary, either (i) relinquish its rights to initiate (or continue) tertiary operations and reassign to Optionor all Assets previously assigned to Optionee, for the value of such Assets at that time based on the methodology outlined in Section 2.5, except the NPV discount rate described in Section 2.5(b)(i)(4) shall be twenty percent (20%) rather than ten percent (10%), or (ii) begin making additional Shortage Payments to Optionor in an amount equal to twenty million dollars ($20,000,000.00) less Shortage Payments paid during that year pursuant to Section 2.7(b) for the first year, and thirty million dollars ($30,000,000.00) less Shortage Payments paid during that year pursuant to Section 2.7(b) per year thereafter until the CO2 injection in the Hasting Field equals or exceeds the Minimum Injection Rate. If Optionee elects to relinquish its rights as set forth herein and Optionor accepts such relinquishment, Optionee shall have no further rights or obligations with respect to the Assets. Notwithstanding the relinquishment option described in this Section 2.7(c), Optionor shall have the option to reject such relinquishment, in which case Optionee shall retain the Assets and the Shortage Payment shall be deemed waived for that year and the Minimum Injection Rate requirement will be deferred until the next anniversary of the Exercise Effective Time.

ARTICLE 3. — OPERATIONS

     3.1. Operations of Hastings Field Prior to Option Exercise. Prior to the Exercise Effective Time Optionor agrees (i) to act as a reasonable prudent operator, (ii) during the term the Option to Purchase is in effect, not to undertake any tertiary operations, including, but not limited to CO2 flooding, fire flooding, polymer flooding, miscible or non-miscible gas flooding other than CO2, high pressure air injection, steam flooding or microbial injection, and (iii) during the term the Option to Purchase is in effect, to notify Optionee in writing at least sixty (60) days prior to the lapse of any Leases which Optionor does not intend to maintain. As to any Leases under “(iii)” above, Optionee shall have the right and option within ten (10) days after receipt of said notice to elect to obtain Optionor’s interest in any such Leases at no cost to Optionor so that Optionee may attempt to maintain any such Leases. Any costs expended by

17

Optionee to maintain any such Leases shall be included in the costs for purposes of calculating Payout and not be subject to the provisions of Section 18.2.

     3.2. Operations After Option Exercise

     (a) In the event Optionee exercises its Option to Purchase, Optionor shall use its reasonable efforts to have Optionee appointed as Operator of West Hastings Unit, both under the West Hastings Unit Operating Agreement and with the appropriate regulatory or administrative agencies. In the event Optionor is not able to secure the formal appointment of Optionee as Operator for the West Hastings Unit, then Optionor and Optionee shall cooperate and enter into such contractual relationship as is necessary or shall otherwise allow Optionee to conduct its Development Plan and conduct all other operations Optionee could otherwise conduct as Operator in the Hastings Field.

     (b) In the event the Optionee exercises its Option to Purchase the Assets, the Parties shall execute a Joint Operating Agreement covering the East Hastings Field and any lands located outside the West Hasting Unit. The Joint Operating Agreement shall be in substantially the same form as set forth in Exhibit “Q.”

     (c) In no event shall the Optionor in any manner be liable for or incur any costs or expenses associated with the CO2 operations of the Optionee until such time as Optionor has accepted its Reversionary Interest.

     3.3. Simultaneous Use of Surface-Option to Purchase.

     (a) In the event Optionee exercises its Option to Purchase, Optionee shall have (i) the right to use all easements and surface rights of Optionor in the Hastings Field acquired from third parties or resulting from its ownership of the Leases, and (ii) the right to use Optionor’s surface and surface estate rights in lands in which Optionor owns all of the surface fee estate or an undivided interest in the surface fee estate (“Optionor’s Surface Estate Lands”), so long as (i) Optionee’s use is reasonably necessary for its operations and activities with respect to the Assets and (ii) Optionee’s use does not conflict with Optionor activities existing as of the Exercise Effective Time. After Optionee’s exercise of its Option to Purchase, Optionor shall be entitled to new uses of all surface rights and interests in the Hastings Field, so long as such new use does not conflict with current or reasonably anticipated future use by Optionee. For the purposes of this Section 3.3, surface or surface estate rights shall also mean and include all rights appurtenant to the surface estate, including, but not limited to, rights to drill water wells, salt water disposal wells and injection wells.

     (b) Subject to the provision of subsection (a) above, after Optionee’s exercise of its Option to Purchase, Optionee shall be entitled to such easements, rights-of-way, and other uses of the surface of Optionor’s Surface Estate Lands in conjunction with Optionee’s operations and activities related to the operation of the Assets as Optionee, acting as a reasonably prudent operator, deems necessary and appropriate. Optionee shall pay Optionor for the following, and only the following, usages of Optionor’s Surface Estate Lands (all other usages being without cost to Optionee), and

18

in the amounts stated: (i) new roads-$1.25 per linear rod; (ii) drill site locations, including areas for drill site pad, pits, and other equipment-$1500.00 per acre.

     (c) Subject to the prior usage restrictions in subsection (a) above, after Optionee’s exercise of its Option to Purchase and for a period of five (5) years after the applicable initial Exercise Effective Date, Optionee shall also have the right to purchase from Optionor up to twenty (20) acres of surface estate, selected by Optionee, out of Optionor’s Surface Estate Lands, to be used for a central plant facility, for a purchase price of $1,500.00 per acre.

     (d) Optionor and Optionee agree to execute any instruments or other documents as may be reasonably requested in order to vest in Optionee the rights and interests provided for in this Section 3.3.

ARTICLE 4. — OPTIONOR’S REPRESENTATIONS AND WARRANTIES

          Optionor represents and warrants to Optionee as of the date hereof, that:

     (a) Optionor is a limited partnership duly organized, validly existing, and in good standing under the laws of the State of Texas, and is duly qualified to carry on its business in Texas;

     (b) Optionor has all requisite power and authority to carry on its business as presently conducted, to enter into this Agreement and the other documents and agreements contemplated hereby, and to perform its obligations under this Agreement and the other documents and agreements contemplated hereby. Effective as of the date hereof the consummation of the transactions contemplated by this Agreement do not and will not violate, nor be in conflict with, any provision of its governing documents or any agreement or instrument to which it is a party or by which it is bound (except as set forth hereinbelow and in any provision contained in agreements customary in the oil and gas industry relating to (1) the Preferential Purchase Rights (defined below) as to all or any portion of the Assets; (2) required consents to transfer and related provisions; (3) maintenance of uniform interest provisions; and (4) any other third-party approvals or consents contemplated herein), or any judgment, decree, order, statute, rule, or regulation applicable to Optionor;

     (c) This Agreement, and all documents and instruments required hereunder to be executed and delivered by Optionor constitute legal, valid and binding obligations of Optionor in accordance with its respective terms, subject to applicable bankruptcy and other similar laws of general application with respect to creditors;

     (d) There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by, or to the actual knowledge of Optionor threatened against Optionor;

     (e) The execution, delivery and performance of this Agreement, and the transaction contemplated hereunder have been duly and validly authorized by all requisite authorizing action, corporate, partnership or otherwise, on the part of Optionor.

19

     (f) Optionor has not incurred any obligation or liability, contingent or otherwise, for brokers’ or finders’ fees in connection with this Agreement or the transaction provided herein;

     (g) Other than as set forth in Exhibit “H”, to the best of Optionor’s knowledge, there are no claims, investigations, demands, actions, suits, or administrative, legal or arbitration proceedings (including condemnation, expropriation, or forfeiture proceedings) pending, or to the best of Optionor’s knowledge, threatened, against Optionor or any of its affiliates, or any Asset: (i) seeking to prevent the consummation of the transactions contemplated hereby, or (ii) which, individually or in the aggregate, would materially and adversely affect the Assets.

     (h) Optionor has not intentionally or willfully misrepresented or omitted any material information requested by Optionee in writing about the Assets;

     (i) Subject to satisfaction of the Condition Precedent, the granting of the Option to Purchase and the transfer of the Assets to Optionee contemplated hereby does not violate any covenants or restrictions imposed on Optionor by any bank or other financial institution in connection with a mortgage or other instrument, and will not result in the creation or imposition of a lien on any portion of the Assets;

     (j) Except as disclosed by Optionor in writing, if Optionor is the operator of an Asset, to the best of Optionor’s knowledge, it is in material compliance with all laws, rules, regulations and orders pertaining to such Assets, including Environmental Laws;

     (k) Except as disclosed by Optionor in writing, if Optionor is the operator of an Asset, to the best of Optionor’s knowledge, it has all governmental permits necessary for the operation of the Asset and is not in material default under any permit, license or agreement relating to the operation and maintenance of the Assets;

     (l) Except as set forth on Exhibit “K”, there are no waivers, consents to assign, approvals or similar rights owned by third parties and required in connection with granting of the Option to Purchase or the conveyance of the Assets from Optionor to Optionee;

     (m) Except as set forth on Exhibit “K”, , there are no rights of first refusal, preferential rights, preemptive rights or contracts, or other commitments or understandings of a similar nature to which Optionor is a party or to which the Assets are subject;

     (n) No Hydrocarbons produced or to be produced from the Leases are subject to any oil or gas sales contracts other than those identified on Exhibits “F-1” and “F-2” and, no third party has any call upon, option to purchase, dedication rights or similar rights with respect to the Hydrocarbons produced to be produced from Optionor’s interest in the Leases;

     (o) Other than as set forth in Exhibit “H”, to the best of Optionor’s knowledge there are no claims, investigations, demands, actions, suits, or administrative, legal or

20

arbitration proceedings (including condemnation, expropriation, or forfeiture proceedings) pending, or to the best of Optionor’s knowledge threatened, against Optionor or any of its affiliates seeking to prevent the consummation of the transactions contemplated hereby; and

     (p) Except as set forth on Exhibit “L”, there are no oil or gas production imbalances with respect to the Leases;

     The above representations and warranties by Optionor shall be continuing in nature during the term of this Agreement or as otherwise provided, and Optionor shall notify Optionee of any material change with respect thereto.

ARTICLE 5. — OPTIONEE’S REPRESENTATIONS AND WARRANTIES

          Optionee represents and warrants to Optionor as of the date hereof that:

     (a) Optionee is a limited liability company duly organized, validly existing, and in good standing under the laws of the state of Delaware, and is duly qualified to carry on its business in Texas;

     (b) Optionee has all requisite power and authority to carry on its business as presently conducted, to enter into this Agreement and the other documents and agreements contemplated hereby, and to perform its obligations under this Agreement and the other documents and agreements contemplated hereby. This Agreement and the consummation of the transactions contemplated by this Agreement do not and will not violate, nor be in conflict with, any provision of Optionee’s articles of incorporation, partnership agreement(s), by-laws or governing documents or any agreement or instrument to which it is a party or by which it is bound, or any judgment, decree, order, statute, rule, or regulation applicable to Optionee;

     (c) the execution, delivery and performance of this Agreement and the transactions contemplated hereunder have been duly and validly authorized by all requisite authorizing action, corporate, partnership or otherwise, on the part of Optionee;

     (d) this Agreement, and all documents and instruments required hereunder to be executed and delivered by Optionee at Closing, constitute legal, valid and binding obligations of Optionee in accordance with their respective terms, subject to applicable bankruptcy and other similar laws of general application with respect to creditors;

     (e) there are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by, or to the actual knowledge of Optionee threatened against Optionee;

     (f) Optionee has not incurred any obligation or liability, contingent or otherwise, for brokers’ or finders’ fees in connection with this Agreement or the transaction provided herein;

21

     (g) Optionee is an experienced and knowledgeable investor and operator in the oil and gas business. Prior to entering into this Agreement, Optionee was advised by and has relied solely on its own expertise and legal, tax, reservoir engineering, accounting, and other professional counsel concerning this Agreement, the Assets and the value thereof;

     (h) Other than as set forth in Exhibit “H”, to the best of Optionee’s knowledge, there are no claims, investigations, demands, actions, suits, or administrative, legal or arbitration proceedings (including condemnation, expropriation, or forfeiture proceedings) pending, or to the best of Optionee’s knowledge, threatened, against Optionee or any of its affiliates, or any Asset: seeking to prevent the consummation of the transactions contemplated hereby.

     (i) Optionee has the financial resources to close the transaction contemplated by this Agreement, whether by third party financing or otherwise; and

     (j) Optionee acknowledges the existence of the claims and suits described in Exhibit “H” and that these claims and suits are Permitted Encumbrances as set forth in Section 8.1(c). Optionee further acknowledges that Optionee has, or by Closing will have, legal counsel of its choice fully review those claims and suits identified on Exhibit “H”.

The above representations and warranties by Optionee shall be continuing in nature during the term of this Agreement or as otherwise provided, and Optionee shall notify Optionor of any material change with respect thereof.

ARTICLE 6. — ACCESS TO INFORMATION AND INSPECTIONS

     6.1. Title Files.

          Promptly after the execution of this Agreement and during the term of this Agreement, Optionor shall permit Optionee and its representatives at reasonable times during normal business hours to examine, in Optionor’s offices at their actual location, all abstracts of title, title opinions, title files, ownership maps, lease files, assignments, division orders, payout statements, title curative, other title materials and agreements pertaining to the Assets by Optionee, within a reasonable period of time, insofar as the same may now or in the future be in existence and in the possession of Optionor. No warranty of any kind is made by Optionor as to the information so supplied, and Optionee agrees that any conclusions drawn therefrom are the result of its own independent review and judgment. Optionee shall be entitled to copies of all files related to the Assets other than files containing privileged communications or attorney work product.

     6.2. Other Files.

          Promptly after the execution of this Agreement and during the term of this Agreement, Optionor shall permit Optionee and its representatives at reasonable times during normal business hours to examine, in Optionor’s offices at their actual location,

22

all production, well, regulatory, engineering and geological information, accounting information, environmental information, inspections and reports, and other information, files, books, records, and data pertaining to the Assets as requested by Optionee, insofar as the same may now or in the future be in existence and in the possession of Optionor, excepting economic evaluations and Optionor’s proprietary interpretations of same, reserve reports and any such information that is subject to confidentiality agreements or to the attorney/client and work product privileges. No warranty of any kind is made by Optionor as to the information so supplied, and Optionee agrees that any conclusions drawn therefrom are the result of its own independent review and judgment. Optionee shall be entitled to copies of all files related to the Assets other than files containing privileged communications or attorney work product.

     6.3 Confidentiality Agreement.

          All information made available to Optionee pursuant to Article 6 shall be maintained confidential by Optionee until the Closing Date. The information protected by such confidentiality obligation does not include any information that (i) at the time of disclosure is generally available to and known by the public (other than as a result of a disclosure by Optionee), or which after such disclosure comes into the public domain through no fault of Optionee or its representatives, or (ii) is or was available to Optionee on a nonconfidential basis, or (iii) is already known to Optionee on a nonconfidential basis, as evidenced by Optionee’s written records, at the time of its disclosure by Optionor to Optionee. Optionee may disclose the information or portions thereof to those employees, agents or representatives of Optionee who need to know such information for the purpose of assisting Optionee in connection with its performance of this Agreement, including to D&M, or its successor or replacement, for the purposes of Section 2.5 of this Agreement. Further, in the event that Optionee is requested or required (by deposition, interrogatory, request for documents, subpoena, civil investigative demand or similar process) to disclose any of the information, Optionee shall provide Optionor with prompt written notice of such request or requirement, so that Optionor may seek such protective order or other appropriate remedy as it may desire. Optionee shall further take reasonable steps to ensure that Optionee’s employees, consultants and agents comply with the provisions of this Section 6.3. Notwithstanding the foregoing, nothing contained within this Section 6.3 shall preclude either the Optionor or Optionee from disclosing its internal reports, analyses, compilations, studies or evaluations based upon information that is generally known or available in the public domain.

     6.4. Inspections.

          Promptly after the execution of this Agreement and during the term of this Agreement, Optionor, subject to any necessary third-party operator approval, shall permit Optionee and its representatives at reasonable times and at their sole risk, cost and expense, to conduct reasonable inspections of the Assets for all purposes, including any Environmental Defects.

23

     6.5. No Warranty or Representation on Optionor’s Information.

          EXCEPT AS SET FORTH IN THIS AGREEMENT, OPTIONOR MAKES NO WARRANTY OR REPRESENTATION, EXPRESS OR IMPLIED, WITH RESPECT TO THE ACCURACY, COMPLETENESS, OR MATERIALITY OF THE INFORMATION, RECORDS, AND DATA NOW, HERETOFORE, OR HEREAFTER MADE AVAILABLE TO OPTIONEE IN CONNECTION WITH THE ASSETS OR THIS AGREEMENT, INCLUDING, WITHOUT LIMITATION, ANY DESCRIPTION OF THE ASSETS, QUALITY OR QUANTITY OF HYDROCARBON RESERVES, IF ANY, PRODUCTION RATES, RECOMPLETION OPPORTUNITIES, DECLINE RATES, GAS BALANCING INFORMATION, ALLOWABLES OR OTHER REGULATORY MATTERS, POTENTIAL FOR PRODUCTION OF HYDROCARBONS FROM THE ASSETS, OR ANY OTHER MATTERS CONTAINED IN OR OMITTED FROM ANY OTHER MATERIAL FURNISHED TO OPTIONEE BY OPTIONOR. ANY AND ALL SUCH DATA, INFORMATION AND MATERIAL FURNISHED BY OPTIONOR IS PROVIDED AS A CONVENIENCE ONLY AND ANY RELIANCE ON OR USE OF SAME IS AT OPTIONEE’S SOLE RISK.

     6.6. Amendments to Exhibits.

          Optionor and Optionee acknowledge that Optionee’s inspection of Optionor’s records and files, or further review by Optionor, prior to Closing may indicate that some or all of the Exhibits attached to this Agreement were not complete or entirely correct at the time of execution of this Agreement. Accordingly, Optionor and Optionee agree to revise and amend the Exhibits, as needed, so that they will be complete and accurate for any Closing and shall be given effect as if made on the Closing Date. It is understood, however, that such revisions or amendments shall not otherwise be taken into account in giving effect to any representations, rights, options, conditions, covenants and obligations of the Parties contained in this Agreement as originally executed and shall not be used to negate any representation or covenant previously made.

ARTICLE 7. — ENVIRONMENTAL MATTERS AND ADJUSTMENTS

     7.1. Investigation.

     Prior to December 1, 2006, Optionee shall have the right, at reasonable times during normal business hours, to conduct its investigation into the status of the physical and environmental condition of the Assets. Upon payment of the initial option payment described in Section 2.3(a), Optionee accepts the physical and environmental condition of the Assets existing as of the Agreement Effective Time. Subsequent to the execution of this Agreement, during the month of November following the Option Exercise Date, Optionee shall have the right, at reasonable times during normal business hours, to conduct further investigation into the status of the physical and environmental condition of the Assets. If, in the course of conducting such investigation, Optionee discovers that any Asset is subject to a material Environmental Defect not existing as of the Agreement Effective Time, Optionee may raise such Environmental Defect in the

24

manner set forth below. For purposes hereof, the term “material” shall mean that the Optionee’s good faith estimate, supported by documentation, of the cost of remediating any single Environmental Defect, or the net reduction in value of the Asset affected by such Defect, whichever is lesser, exceeds fifty thousand dollars ($50,000.00), the Parties agreeing that such amount will be a per Asset deductible rather than a threshold. No later than 5:00 p.m. Central Standard Time on December 1^st following the Option Exercise Date (the “Environmental Defect Notice Date”), Optionee shall notify Optionor in writing specifying such Environmental Defects, if any, the Assets affected thereby, and Optionee’s good faith estimate of the costs of remediating such Defects, or the net reduction in value of the Assets affected by such Defects, whichever is lesser, together with supporting documentation. Optionor may, but shall be under no obligation to, correct at its own cost and expense such Defects on or before the Closing Date, in which case there shall be no reduction to the Cash Payment, nor any payment by Optionor to Optionee. Prior to Closing, Optionee shall treat all information regarding any environmental conditions as confidential, whether material or not, and shall not make any contact with any governmental authority or third party regarding same without the prior written consent of Optionor unless required by law.

     7.2. Waiver of Defects.

     If Optionee fails to notify Optionor prior to or on the Environmental Defect Notice Date, of any Environmental Defects, all defects, whether known or unknown, will be deemed waived for purposes of adjustments pursuant to this Article 7, the Parties shall proceed with the Closing, Optionor shall be under no obligation to correct the defects, and Optionee shall assume the risks, liability and obligations associated with such defects, unless such defects constitute Retained Environmental Obligations or Liabilities of Optionor.

     7.3. Remedy.

     In the event any Environmental Defect, for which notice has been timely given as provided hereinabove, remains uncured as of the Closing, Optionor, at its sole option, shall, (i) agree to cure or remediate any Defect within a reasonable time after Closing and without any reduction or offset to any Cash Payment in a manner acceptable to both Parties, or (ii) reduce the Cash Payment by the amount of the Environmental Defect Value as determined pursuant to Section 8.4, and subject to application of the fifty thousand dollars ($50,000.00) deductible in Section 7.1; or (iii) if the Purchase Price does not consist of a Cash Payment (but rather a Volumetric Production Payment), pay Optionee at the Closing the amount of the Environmental Defect Value as determined pursuant to Section 8.4, and subject to application of the fifty thousand dollars ($50,000.00) deductible.

     7.4. Default Basket.

     The Parties agree that adjustments to the Purchase Price under this Article 7 and Article 8 shall only occur to the extent that the aggregate Environmental Defects and Title Defects, collectively, exceed two hundred fifty thousand dollars ($250,000.00)

25

(the “Aggregate Defect Basket”) after taking the applicable materiality deductible into account. For the avoidance of doubt and by way of example only, if there are a total of two (2) Environmental Defects of two hundred thousand dollars ($200,000.00) and one hundred fifty thousand dollars ($150,000.00) and two (2) Title Defects of seventy five thousand dollars ($75,000.00) and five thousand dollars ($5,000.00), the total adjustment would be twenty five thousand dollars ($25,000.00) [being one hundred fifty thousand dollars ($150,000.00) for Environmental Defect #1, plus one hundred thousand dollars ($100,000.00) for Environmental Defect #2, plus twenty five thousand dollars ($25,000.00) for Title Defect #1 and zero ($0) for Title Defect #2, minus two hundred fifty thousand dollars ($250,000.00) for the Aggregate Defect Basket].

     7.5. Closing.

     In the event any adjustment to the Cash Payment or payment by Optionor to Optionee is made due to an Environmental Defect raised by Optionee, the Parties shall proceed with the Closing, Optionor shall be under no obligation to correct the Defect, and the Defect shall become an Assumed Obligation of Optionee.

ARTICLE 8. — TITLE DEFECTS AND ADJUSTMENTS

     8.1. Existing Title; Definitions.

     Upon payment of the initial option payment as set forth in Section 2.3(a), Optionee accepts title to the Assets as it exists as of the Agreement Effective Time, subject to its right to examine issues related to defects to title arising or occuring during the time after the Agreement Effective Time until the Closing Date, as set forth below.

     For purposes hereof, the terms set forth below shall have the meanings assigned thereto.

     (a) “Defensible Title”, subject to and except for the Permitted Encumbrances means:

     (1) Such title held by Optionor and reflected by appropriate documentation properly filed in the official records of the jurisdiction in which the Lease or Leases are located that (a) as to the Leases, entitles Optionor and will entitle Optionee, after Closing, to own and receive and retain the Designated Interests (subject to the Excluded Assets) in such Leases, without suspension, reduction or termination, excluding Permitted Encumbrances; (b) as to wells, entitles Optionor and will entitle Optionee, after Closing, to own and receive and retain the Designated Interests (subject to the Excluded Assets) in such wells, without suspension, reduction or termination, excluding Permitted Encumbrances; (c) as to the West Hastings Unit and East Hastings Field, obligates Optionor, and will obligate Optionee after Closing, to bear 89.33682% of the costs and expenses relating to the maintenance, development and operation of such West Hastings Unit and 100% as to the East Hastings Field;

26

(d) as to the West Hastings Unit, reflects the ownership and unit participation of the tracts within the unit area as set forth in Exhibit “C”; (e) the Leases and wells are free and clear of any liens, claims or encumbrances of any kind or character as of the Closing, except Permitted Encumbrances; and (f) is not encumbered by any default by Optionor incurred after the Agreement Effective Time under a material provision of any Lease, Unit Operating Agreement, or other contract or agreement affecting the Leases;

     (2) As to personal property included in the Assets, title to such property is free and clear of any liens, claims or encumbrances of any kind or character as of Closing, except Permitted Encumbrances; and

     (3) As to all other Assets, (a) such Assets are free and clear of any liens, claims or encumbrances of any kind or character incurred after the Agreement Effective Time as of Closing except for Permitted Encumbrances; and (b) the Optionor is not in default under a material provision of any Lease, operating agreement, or other contract or agreement affecting such Assets.

     (b) “Title Defect” shall mean (i) any matter which causes Optionor to have less than Defensible Title to any of the Assets as of the Closing Date, or (ii) any matter that causes one or more of the following statements to be untrue as of the Closing Date, except for Permitted Encumbrances and matters in existence at, or occurring prior to, the Agreement Effective Time:

     (1) Optionor has not received written notice from any governmental authority or any other person (including employees) claiming any material violation of any law, rule, regulation, ordinance, order, decision or decree of any governmental authority with respect to the such Assets.

     (2) Optionor, or the Operator of an Asset, has complied in all material respects with the provisions and requirements of all orders, regulations and rules issued or promulgated by governmental authorities having jurisdiction with respect to such Assets and has filed for and obtained all material governmental certificates, permits and other authorizations necessary for Optionor’s current operation of such Assets other than permits, consents and authorizations required for the sale and transfer of such Assets to Optionee;

     (3) Optionor has not materially defaulted or materially violated any agreement to which Optionor is a party or any obligation to which Optionor is bound affecting or pertaining to such Assets other than as disclosed hereunder or on any exhibit attached hereto;

     (4) The Leases included within such Assets are in full force and effect; and

27

     (5) All taxes, rentals, royalties, operating costs and expenses, and other costs and expenses related to such Assets which are due from or are the responsibility of Optionor have been paid.

     (c) “Permitted Encumbrances” shall mean any of the following matters:

     (1) defects in the early chain of title consisting of failure to recite marital status or the omission of succession or heirship proceedings;

     (2) defects or irregularities arising out of uncancelled mortgages, judgments or liens, the inscriptions of which, on their face, have expired as a matter of law prior to the Effective Time, or prior unreleased oil and gas leases which, on their face, expired more than ten (10) years prior to the Agreement Effective Time and have not been maintained in force and effect by production or operations pursuant to the terms of such leases;

     (3) tax liens and operator’s liens for amounts not yet due and payable, or those that are being contested in good faith by Optionor in the ordinary course of business;

     (4) to the extent any of the following do not materially diminish the value of, or impair the conduct of operations on, any of the Assets and do not impair Optionor’s right to receive the revenues attributable thereto: (i) easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, pipelines, grazing, hunting, fishing, logging, canals, ditches, lakes, reservoirs or the like, (ii) easements for streets, alleys, highways, pipelines, telephone lines, power lines, railways and other similar rights-of-way, on, over or in respect of property owned or leased by Optionor or over which Optionor owns rights of way, easements, permits or licenses, and (iii) the terms and conditions of all leases, agreements, orders, instruments and documents pertaining to the Assets;

     (5) all lessors’ royalties, overriding royalties, net profits interests, carried interest, production payments, reversionary interests and other burdens on or deductions from the proceeds of production if the net cumulative effect of such burdens or deductions does not reduce the net revenue interest of Optionor in any well affected thereby to the extent that Optionor will not be able to deliver to Optionee at Closing, the Designated Interests in production (net revenue interests);

     (6) preferential rights to purchase and required third party consents to assignments and similar agreements with respect to which waivers or consents are obtained from the appropriate parties, or the appropriate time period for asserting the rights has expired without an exercise of the rights prior to the Closing Date;

28

     (7) all rights to consent by, required notices to, filings with, or other actions by governmental entities and tribal authorities in connection with the sale or conveyance of oil and gas leases or interests if they are customarily obtained subsequent to the sale or conveyance;

     (8) defects or irregularities of title arising out of events or transactions which have been barred by limitations or by acquisitive or liberative prescription;

     (9) any encumbrance or other matter having an aggregate adverse effect on the value of the Assets of less than fifty thousand dollars ($50,000), the Parties agreeing that such amount will be a per Asset deductible rather than a threshold;

     (10) rights reserved to or vested in any municipality or governmental, statutory or public authority to control or regulate any of the Assets in any manner, and all applicable laws, rules and orders of governmental authority; and

     (11) any encumbrance or other matter (whether or not constituting a Title Defect) expressly waived in writing by Optionee or listed on Exhibit “H”.

     (12) liens related to Optionor’s bank indebtedness which will be released at Closing.

     (13) any matters which would otherwise constitute Title Defects that existed as of the Agreement Effective Date.

     8.2. Notice of Title Defects.

     No later than 5:00 p.m. Central Standard Time on December 1^st following the Option Exercise Date (a “Title Defect Notice Date”), Optionee may provide Optionor written notice of any Title Defect along with a description of those matters which, in Optionee’s reasonable opinion, constitute Title Defects and setting forth in detail Optionee’s calculation of the value for each Title Defect determined pursuant to Section 8.4. Optionor may elect, at its sole cost and expense, but without obligation, to cure all or any portion of such Title Defects prior to Closing, in a manner acceptable to both Parties, in which case no reduction or offset in any Cash Payment, or payment by Optionor to Optionee, shall be made. Optionee’s failure to deliver to Optionor such notice on or before the Title Defect Notice Date shall be deemed a waiver by Optionee of all Title Defects with respect to the Assets, known or unknown, that Optionor does not have notice of from Optionee on such date. Any defect or deficiency concerning Optionor’s title to the Assets not asserted by Optionee in a Title Defect Notice on or prior to the Title Defect Notice Date shall be deemed waived by Optionee for purposes of any adjustment to the Cash Payment or payment by Optionor to Optionee, the Parties shall proceed with Closing, Optionor shall be under no obligation to correct the defects, and Optionee shall assume the risks, liability and obligations associated with

29

such defects. However, such waiver shall not effect or impair the warranties of Optionor set forth in Section 8.5 or the indemnity obligations of Optionor as set forth in Article 16.

     8.3. Title Defect Adjustment.

     (a) In the event any Title Defect, for which notice has been timely given as provided hereinabove, remains uncured as of Closing, Optionor shall have the opportunity to cure, until sixty (60) days after Closing (“Cure Period”), such Title Defect. In the alternative, Optionor may elect to (i) indemnify Optionee against any damages, claims or expenses that may arise out of such Title Defect, subject to the provisions of Section 8.3(c) below, with no reduction in the Cash Payment or payment to Optionee; or (ii) reduce the Cash Payment by an amount equal to the Title Defect Value as determined pursuant to Section 8.4, and subject to application of the fifty thousand dollars ($50,000.00) deductible described in Section 8.1(c) (9); or, (iii) if the Purchase Price does not consist of a Cash Payment (but rather a volumetric production payment), pay Optionee at Closing the amount of the Title Defect Value as determined pursuant to Section 8.4, and subject to application of the fifty thousand dollars ($50,000.00) deductible. Should Optionor elect alternative “(i)” (indemnity) or “(ii)” (price reduction) or “(iii)” (payment to Optionee) in this Section 8.3(a), those Assets affected by the Title Defect shall be transferred to Optionee at Closing.

     (b) If Optionor elects to attempt to cure a Title Defect after Closing, the Closing with respect to the portion of the Assets affected by such Title Defect will proceed along with all other Assets as provided in this Agreement. If Optionor fails or refuses to cure any Title Defect prior to the expiration of the Cure Period, Optionor shall notify Optionee in writing of such failure or refusal promptly upon the expiration of the Cure Period. In this event, Optionee shall within seven (7) days after receipt by Optionee of Notice from Optionor of such failure or refusal to cure any such Title Defect, pay Optionee an amount equal to the subject Title Defect Value. In the event that any such property is retained by Optionor and such property has been receiving revenue, without complaint, for a period in excess of two (2) years, then Optionee agrees (i) not to take any action to interfere with such revenue stream, and (ii) to the extent that Optionee becomes payor of such revenue, to pay Optionor such revenue upon receipt of an indemnity agreement from Optionor.

     (c) The following provisions shall apply to an election by Optionor under Section 8.3(a)(i) to indemnify Optionee with regard to such Title Defect:

     (1) Optionor’s indemnity shall be limited to a period of two (2) years from the Effective Time.

     (2) In no event shall Optionor’s indemnity exceed the amount of the Title Defect Value as determined under Section 8.4 hereof.

     (3) Optionor’s indemnity shall be freely transferable by Optionee to its successors and assigns of the Assets affected by such Title Defect, including

30

without limitation, any lender to Optionee and any purchaser of such Assets, whether directly from Optionee or through any foreclosure proceeding; and

     (4) If the Title Defect Value, as determined under Section 8.4 hereof, individually or in the aggregate, for one or more Title Defects to be covered by the Optionor’s indemnity exceeds two hundred fifty thousand dollars ($250,000.00) (after application of the appropriate deductible(s) provided for in Section 8.1(c)(9), Optionor shall have no right under the second sentence of Section 8.3(a)(iii) to indemnify Optionee with regard to such Title Defects without Optionee’s consent.

     (d) In the event any adjustment to the Cash Payment, or payment by Optionor to Optionee, is made due to a Title Defect raised by Optionee, the Parties shall proceed with Closing, Optionor shall be under no obligation to correct the Title Defect, and such Title Defect shall become an Assumed Obligation of Optionor.

     8.4. Environmental Defect and Title Defect Values.

     Upon timely delivery of notice of an Environmental or Title Defect, Optionee and Optionor shall use their best efforts to agree on the validity and value of the claim for the purpose of making any adjustment to the Purchase Price based on the provisions herein (“Environmental or Title Defect Value”). In determining the Value of an Environmental or Title Defect, it is the intent of the Parties to include, to the extent possible, only that portion of the lands, Leases and wells, or other Assets, whether an undivided interest, separate interest or otherwise, materially and adversely affected by the Defect. The following guidelines shall be followed by the Parties in establishing the Value of any Environmental or Title Defect for the purpose of adjusting a Cash Payment or establishing an amount to be paid by Optionor to Optionee for such a Defect if (a) the validity of the claim is agreed to by the Parties, (b) proper notice has been timely given, and (c) subject to (i) application of the appropriate deductibles as set forth in this Agreement for Environmental Defects and Title Defects:

     (a) If the Title Defect is based on a difference in net revenue interest or expense interest from the Designated Interests for the affected property, then the Title Defect Value shall be the amount of the reduction or increase as the case may be.

     (b) If the Environmental or Title Defect is liquidated in amount (for example, but not limited to, a lien, encumbrance, charge or penalty), then the Defect Value shall be the lesser of (1) the sum necessary to be paid to the obligee to remove the Defect from the property, or (2) the decrease in the fair market value of the Asset as a result of the Defect.

     (c) If the Environmental or Title Defect represents an obligation or burden upon the affected property for which the economic detriment is not liquidated but can be estimated with reasonable certainty as agreed to by the Parties, the Defect Value shall be the sum necessary to compensate Optionee at Closing for the adverse economic effect which the Environmental or Title Defect will have on the affected property. This

31

sum shall be the lesser of (1) the cost of remediating the Defect, or (2) the decrease in the fair market value of the Asset as a result of the Defect. The fair market value determination shall be made by the Parties in good faith taking into account all relevant factors, including, but not limited to, the following:

     (1) the value of the Leases, lands, wells and other Assets affected by the Environmental or Title Defect;

     (2) the productive status of the affected Asset (i.e., proved developed producing, etc.) and the present value of the future income expected to be produced therefrom;

     (3) if the Title Defect represents only a possibility of title failure, the probability that such failure will occur; and

     (4) the economic effect of the Environmental or Title Defect.

     (d) If the Value of the Environmental or Title Defect cannot be determined using the above guidelines, and if the Parties cannot otherwise agree on the amount of an adjustment to the Cash Payment or payment by Optionor to Optionee, or if the validity of the claim as to an Environmental or Title Defect cannot be agreed upon, then the Closing shall nevertheless include the Asset(s) affected thereby. If the validity of the claim is in dispute, there shall be no adjustment to the Cash Payment or a payment by Optionor to Optionee at Closing. If the value of the claim is in dispute, the Cash Payment or payment by Optionor to Optionee at Closing shall be adjusted by an amount being the average of Optionor’s and Optionee’s good faith estimates of the value thereof. In either case, Optionor and Optionee shall each have the right, exercisable within ninety (90) days after the Closing Date, to refer the disputed matter to mediation and arbitration in accordance with the dispute resolution procedures set forth in Exhibit “P.” After the expiration of said ninety (90) day period the right to refer the matter to mediation and arbitration shall terminate. Subject to the terms of Exhibit “P”, the decision of the arbitrator regarding any Environmental or Title Defect Dispute shall be final as between the Parties.

     8.5. Title Warranty.

     OPTIONOR SHALL CONVEY OPTIONOR’S INTERESTS IN AND TO THE ASSETS TO OPTIONEE AS PROVIDED IN THE FORM OF CONVEYANCE, ASSIGNMENT AND BILL OF SALE ATTACHED AS EXHIBIT “I” HERETO. THE CONVEYANCE, ASSIGNMENT AND BILL OF SALE SHALL BE MADE WITHOUT WARRANTY OF TITLE, EITHER EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, AND WITHOUT RECOURSE, EVEN AS TO THE RETURN OF THE PURCHASE PRICE OR OTHER CONSIDERATION (EXCEPT AS SPECIFICALLY PROVIDED HEREIN), EXCEPT THAT OPTIONOR SHALL WARRANT TITLE TO THE ASSETS AGAINST ALL CLAIMS, LIENS, BURDENS AND ENCUMBRANCES ARISING BY, THROUGH OR UNDER OPTIONOR, BUT NOT OTHERWISE AND NOT WITH RESPECT TO ANY IMPAIRMENT OR FAILURE OF TITLE RELATED TO ANY

32

LACK OF PRODUCTION IN PAYING QUANTITIES. THE CONVEYANCE, ASSIGNMENT AND BILL OF SALE SHALL BE MADE WITH FULL SUBSTITUTION AND SUBROGATION TO OPTIONEE IN AND TO ALL COVENANTS AND WARRANTIES BY OTHERS HERETOFORE GIVEN OR MADE TO OPTIONOR WITH RESPECT TO THE ASSETS.

     IMBALANCES WITH RESPECT TO OIL OR NATURAL GAS ARE GOVERNED BY ARTICLE 17 HEREOF. THE PARTIES AGREE THAT THE EXISTENCE OF ANY SUCH IMBALANCES SHALL NOT BE DEEMED A TITLE DEFECT.

ARTICLE 9. — PREFERENTIAL PURCHASE RIGHTS
AND CONSENTS OF THIRD PARTIES

     9.1. Actions and Consents.

     (a) Optionor and Optionee agree that each shall use all reasonable efforts to take or cause to be taken all such action as may be necessary to consummate and make effective the transaction provided in this Agreement and to assure that it will not be under any material corporate, legal, or contractual restriction that could prohibit or delay the timely consummation of such transaction.

     (b) Prior to the execution of this Agreement, Optionor and Optionee will satisfy themselves that the execution of this Agreement will not in and of itself trigger (i) any preferential rights to purchase, or any rights of first refusal to purchase, any of the Assets (“Preferential Purchase Rights”), or (ii) any rights of consent or approval to the Agreement or transactions contemplated by the Agreement (“Consents”). In the event that Optionor and Optionee determine before or after the execution of this Agreement that a Preferential Purchase Right or Consent is triggered by the execution of this Agreement, they will endeavor to obtain a waiver of such right, or such consent, as applicable, and failing which, will negotiate an agreed upon reduction or reimbursement of the initial installment of the consideration for the initial term of the Option to Purchase payable upon execution of this Agreement.

     (c) Promptly after the Option Exercise Date, Optionor shall notify all holders of Preferential Purchase Rights and Consents of such terms and conditions of this Agreement to which the holders of such rights are entitled. Optionor shall promptly notify Optionee if any Preferential Purchase Rights are exercised, any consents or approvals denied, or if the requisite period has elapsed without said rights having been exercised or consents or approvals having been received. If prior to Closing, any such Preferential Purchase Rights are timely and properly exercised, or Optionor is unable to obtain a necessary consent or approval prior to Closing, the interest or part thereof so affected shall be treated in the same manner as an uncured Title Defect. If any additional Preferential Purchase Rights are discovered after Closing, or if a third party Preferential Purchase Rights holder alleges improper notice, then Optionee agrees to cooperate with Optionor in giving effect to any such valid third party Preferential Purchase Rights. In the event any such valid third party preferential purchase rights are

33

validly exercised after Closing, Optionee’s sole remedy against Optionor shall be payment by Optionor to Optionee of the value of that portion of the Assets on which such rights are exercised and lost by Optionee to such third party determined in the same manner as a Title Defect Value.

     (d) With respect to any portion of the Assets for which a Preferential Purchase Right has not been asserted prior to Closing, or a consent or other approval to assign has not been granted and for which the time for election to exercise such Preferential Purchase Right or to grant such consent has not expired, the Closing with respect to the portion of the Assets subject to such outstanding obligations will nevertheless proceed along with the Closing of other Assets as provided in this Agreement. In the event that within ninety (90) days after Closing any such Preferential Purchase Right is not waived or consent or approval is not obtained or the time for election to purchase or to deliver a consent or approval does not pass (such that under the applicable documents, Optionor may not sell the affected third party interest to Optionee), then Optionee shall reassign same to Optionor and Optionor will promptly pay to Optionee the value of such third party interests.

ARTICLE 10. — COVENANTS OF OPTIONOR AND OPTIONEE

     10.1. Covenants of Optionor Pending Closing.

     (a) From and after the date of execution of this Agreement and until Closing, and subject to Section 10.2 and the constraints of applicable operating and other agreements, Optionor shall operate, manage, and administer the Assets as a reasonable and prudent operator and in a good and workmanlike manner consistent with its past practices, and shall carry on its business with respect to the Assets in substantially the same manner as before execution of this Agreement. Prior to Closing, Optionor shall use all commercially reasonable efforts to preserve in full force and effect all Leases, operating agreements, easements, rights-of-way, permits, licenses, and agreements which relate to the Assets in which Optionor owns an interest, and shall perform all material obligations of Optionor in or under all such agreements relating to the Assets; provided, however, Optionee’s sole remedy for Optionor’s breach of its obligations under this Section 11.1(a) shall be limited to the relative amount of the Purchase Price the parties agree should be allocated to that portion of the Assets affected by such breach, and if the parties cannot agree, the matter shall be submitted to mediation and arbitration procedures set forth in Exhibit “P” Optionor shall, except for emergency action taken in the face of serious risk to life, property, or the environment (1) submit to Optionee, for prior written approval, all proposed contracts, agreements or amendments to contracts relating to the Assets to the extent same could be binding upon Optionee’s exercise of its Option to Purchase; (2) submit to Optionee, for Optionee’s information, all AFE’s relating to the Assets in excess of One Hundred Thousand Dollars ($100,000.00); (3) consult with, inform, and advise Optionee regarding all material matters concerning the operation, management, and administration of the Assets; (4) notify Optionee of any written voting under any

34

operating, unit, joint venture, partnership or similar agreement relating to the Assets; and (5) not approve or elect to go nonconsent as to any proposed well or plug and abandon or agree to plug and abandon any well without Optionee’s prior written approval. On any matter requiring Optionee’s approval under this Section 11.1(a), Optionee shall respond within five (5) days to Optionor’s request for approval and failure of Optionee to respond to Optionor’s request for approval within such time shall release Optionor from the obligation to obtain Optionee’s approval before proceeding on such matter. With respect to emergency actions taken by Optionor in the face of serious risk to life, property, or the environment, without prior approval of Optionee pursuant to the provisions above, Optionor will advise Optionee of its actions as promptly as reasonably possible and consult with Optionee as to any further related actions.

     (b) From and after the date of execution of this Agreement until this Option terminates, Optionor may not enter into any agreement, or amend, supplement or change any existing agreement that would have a material adverse effect on Optionee’s option rights hereunder, without Optionee’s consent, which consent shall not be unreasonably withheld.

     (c) Optionor shall promptly notify Optionee of any suit, material lessor demand action, or other proceeding before any court, arbitrator, or governmental agency and any cause of action which pertains to the Assets or which reasonably would be expected to result in material impairment or loss of Optionor’s interest in any portion of the Assets or which might hinder or impede the operation of the Assets in any material respect.

     (d) Except for Permitted Encumbrances, Optionor shall not alienate, encumber, transfer, abandon or release any of the Assets during the term of this Agreement without the prior written consent of Optionee.

     (e) Subject to the terms and conditions of this Agreement, Optionor will use commercially reasonable efforts to cause (a) its respective representations and warranties set forth in this Agreement to be true and correct on and as of the Closing Date except to the extent such representations and warranties expressly relate to an earlier date, and (b) all of the conditions precedent to the obligations of the other Party (to the extent they are within the control of Optionor) to be satisfied on or prior to each Closing Date.

     10.2. Limitations on Optionor’s Covenants Pending Closing.

     To the extent Optionor is not the operator of any of the Assets, the obligations of Optionor in Section 10.1 concerning operations or activities which normally or pursuant to existing contracts are carried out or performed by the operator, shall be construed to require only that Optionor use all commercially reasonable efforts (without being obligated to incur any expense or institute any cause of action) to cause the operator of such Assets to take such actions or render such performance as would a reasonable prudent operator and within the constraints of the applicable operating agreements and other applicable agreements.

35

     10.3. Covenants of Optionee Following Exercise of Option.

     Optionee shall act as a reasonable prudent operator in delivering CO2 to the Assets in a timely manner and in sufficient quantities to efficiently conduct operations to enhance oil production, under the terms of this Agreement, including but not limited to, Sections 1.26(d)(2), 1.26(d)(3) and 1.26(d)(5).

     10.4. Hastings Field Call on CO2.

     The Assets shall have first call on the CO2 in Optionee’s pipeline proposed to be constructed from a point near Donaldsonville, Louisiana to the Hastings Field, up to a maximum of 200 MMcf/d for so long as the Hastings Field requires 200 MMcf/d of additional CO2 above then existing recycle volumes. The call on CO2 shall be based on 8 MMcf/d times the toal number of CO2 injectors until such time as the total number of injectors times 8 MMcf/d exceed 200 MMcf/d. Optionor agrees that the call on CO2 is based on the assumption that individual injection wells will inject on average 8 MMcf/d per well. If the actual average injection rate is lower than 8 MMcf/d, the 200 MMcf/d call on CO2 shall be adjusted downward based on the actual average injection rate divided by 8 MMcf/d. This call is on CO2 from whatever source in Optionee’s pipeline, but is not a call on any particular source of CO2.

     10.5. Ownership of CO2.

     All CO2 injected into the Hastings Field for which the working interest owners are charged shall be owned by the working interest owners proportionate to their ownership interest in the West Hastings Unit or the East Hastings Field, as the case may be.

     10.6. Environmental Liabilities Related to Events and Activities occurring prior to October 1, 2004.

          Notwithstanding anything to the contrary contained herein, Optionor and Optionee agree that from and after the Exercise Effective Date all Environmental Obligations and Liabilities related to, or arising from, events or conditions first occurring prior to October 1, 2004, shall be shared equally between Optionor and Optionee and their respective successors and assigns. The provisions of Section 16.6 and Section 16.7 shall apply to any claim for shared payment under this Section 10.6, except that Optionor and Optionee shall each have equal rights to participate in the defense of all Environmental Obligations and Liabilities subject to this Section 10.6 and no third-party claim in respect of such Environmental Obligations and Liabilities shall be compromised or settled without the prior written consent of both Optionor and Optionee, which consent shall not be unreasonably withheld or delayed.

36

ARTICLE 11. — CLOSING CONDITIONS

     11.1. Optionor’s Closing Conditions.

          The obligations of Optionor under this Agreement are subject, at the option of Optionor, to the satisfaction, at or prior to Closing, of the following conditions:

     (a) all representations and warranties of Optionee contained in this Agreement shall be true and accurate in all material respects at and as of Closing as if such representations and warranties were made at and as of Closing, and Optionee shall have performed, satisfied and complied in all material respects with all agreements and covenants required by this Agreement to be performed, satisfied and complied with by Optionee at or prior to Closing;

     (b) the execution, delivery, and performance of this Agreement and the transactions contemplated thereby have been duly and validly authorized by all necessary action, corporate, partnership or otherwise, on the part of Optionee, and an officer’s certificate of Optionee confirming the same;

     (c) all necessary consents of and filings with any state or federal governmental authority or agency relating to the consummation of the transactions contemplated by this Agreement shall have been obtained, accomplished or waived, except to the extent that such consents and filings are normally obtained, accomplished or waived after Closing; and

     (d) as of the Closing Date, no suit, action or other proceeding (excluding any such matter initiated by Optionor) shall be pending or threatened before any court or governmental agency seeking to restrain Optionor or prohibit the Closing or seeking damages against Optionor as a result of the consummation of this Agreement.

     11.2. Optionee’s Closing Conditions.

          The obligations of Optionee under this Agreement are subject, at the option of Optionee, to the satisfaction, at or prior to Closing, of the following conditions:

     (a) all representations and warranties of Optionor contained in this Agreement shall be true, accurate in all material respects at and as of Closing as if such representations and warranties were made at and as of Closing, and Optionor shall have performed, satisfied and complied in all material respects with all agreements and covenants required by this Agreement to be performed, satisfied and complied with by Optionor at or prior to Closing;

     (b) the execution, delivery, and performance of this Agreement and the transactions contemplated thereby have been duly and validly authorized by all necessary action, corporate, partnership or otherwise, on the part of Optionor, and an officer’s certificate of Optionor confirming the same;

37

     (c) all necessary consents of and filings with any state or federal governmental authority or agency relating to the consummation of the transactions contemplated by this Agreement shall have been obtained, accomplished or waived, except to the extent that such consents and filings are normally obtained, accomplished or waived after Closing; and

     (d) as of the Closing Date, no suit, action or other proceeding (excluding any such matter initiated by Optionee) shall be pending or threatened before any court or governmental agency seeking to restrain Optionee or prohibit the Closing or seeking damages against Optionee as a result of the consummation of this Agreement.

ARTICLE 12. — CLOSING

     12.1. Closing.

          The closing of the purchase of the Assets following the exercise of the option granted herein (the “Closing”) shall be held at the offices of Optionee on the date provided in Section 2.6 above, or at such earlier date or place as the Parties may agree in writing (herein called “Closing Date”). Time is of the essence and the Closing Date shall not be extended unless by written agreement of the Parties. On or before five (5) business days prior to Closing, Buyer and Seller shall use their best efforts to provide each other copies of all closing documents.

     12.2. Optionor’s Closing Obligations.

          At Closing Optionor shall deliver to Optionee the following:

     (a) the Assignment and Conveyance substantially in the form attached hereto as Exhibit “I” and such other documents as may be reasonably necessary to convey all of Optionor’s interest in the Assets to Optionee in accordance with the provisions hereof ;

     (b) a non-foreign affidavit executed by Optionor in the form attached as Exhibit “M”;

     (c) appropriate regulatory forms appointing Optionee as the operator for those Assets which Optionor operates;

     (d) copies of all third-party waivers, consents, approvals, permits and actions obtained;

     (e) subject to existing operating agreements and Optionor’s rights to continued use and access as set forth in Section 3.3, exclusive possession of the Assets;

     (f) letters-in-lieu of transfer orders in form acceptable to Optionor and Optionee;

38

     (g) a Reporting and Accounting Memorandum executed by Optionor in the form attached as Exhibit “N”; and

     (h) releases of all mortgages, liens and similar encumbrances burdening the Assets in form and substance reasonably satisfactory to Optionee.

     12.3. Optionee’s Closing Obligations.

          At Closing, (i) Optionor shall execute an Assignment and Conveyance, the form of which shall be substantially the same as the form attached hereto as Exhibit “I”, and (ii) depending upon Optionor’s election, Optionee shall either pay the Cash Payment or execute an Assignment of Volumetric Production Payment, the form of which shall be substantially the same as the form attached hereto as Exhibit “J”.

     12.4. Joint Closing Obligations.

          Both Parties at Closing shall execute a Settlement Statement evidencing any amount actually wire transferred or the Volumetric Production Payment assigned and all adjustments to the consideration taken into account at Closing. All events of the Closing shall each be deemed to have occurred simultaneously with the other, regardless of when actually occurring, and each shall be a condition precedent to the other.

     12.5. Final Settlement/Purchase Price Adjustments.

          Within one hundred twenty (120) days after Closing, Optionor shall provide to Optionee, for Optionee’s concurrence, an accounting (the “Final Settlement Statement”) of the actual amounts of Optionor’s and Optionee’s Credits for the adjustments set out in this Section 12.5. Optionee shall have the right for thirty (30) days after receipt of the Final Settlement Statement to audit and take exceptions to such adjustments. The Parties shall attempt to resolve any disagreements on a best efforts basis. Those credits agreed upon by Optionee and Optionor shall be netted and the final settlement shall be paid as directed in writing by the receiving party, on final adjustment by the party owing it (the “Final Settlement”).

          The Purchase Price shall be adjusted as follows:

     (a) The Purchase Price shall be adjusted upward by the following (“Optionor’s Credits”):

     (1) the value of (i) all Inventory Hydrocarbons attributable to the Assets, such value to be based upon the existing contract price for crude oil in effect as of the Effective Time, less severance taxes, transportation fees and other fees deducted by the purchaser of such oil, such oil to be measured at the Exercise Effective Time by the operators of the Assets; and (ii) the value of all of Optionor’s unsold inventory of gas plant products, if any, attributable to the Assets at the Effective Time valued in the same manner as if such products had been sold under the contract then in existence between Optionor and the

39

purchaser of such products or, if there is no such contract, valued in the same manner as if said products had been sold at the posted price in the field for said products;

     (2) the amount of all production expenses, operating expenses and all expenditures attributable to the operation of the Assets after the Exercise Effective Time and accrued by Optionor prior to Closing Date in accordance with generally accepted accounting principles and Section 11.1;

     (3) an amount equal to the sum of any upward adjustments provided elsewhere in this Agreement applicable to the Assets; and

     (4) any other amount agreed upon by Optionor and Optionee in writing prior to Closing.

     (b) The Purchase Price shall be adjusted downward by the following (“Optionee’s Credits”):

     (1) the total collected sales value of all Hydrocarbons sold by the Optionor after the Exercise Effective Time which are attributable to the Assets, and any other monies collected by the Optionor with respect to the ownership of the Assets after the Exercise Effective Time, but excepting interest income.

     (2) the amount of all unpaid ad valorem, property, production, excise, severance and similar taxes and assessments (but not including income taxes), which taxes and assessments become due and payable or accrue to the Assets prior to the Exercise Effective Time, which amount shall, where possible, be computed based upon the tax rate and values applicable to the tax period in question; otherwise, the amount of the adjustment under this paragraph shall be computed based upon such taxes assessed against the applicable portion of the Assets for the immediately preceding tax period just ended;

     (3) an amount equal to the sum of any downward adjustments provided elsewhere in this Agreement; and

     (4) any other amount agreed upon by Optionor and Optionee in writing prior to Closing.

     (c) Optionor shall prepare and deliver to Optionee, at least five business days prior to Closing, Optionor’s estimate of the adjusted Purchase Price to be paid at Closing, together with a preliminary statement setting forth Optionor’s estimate of the amount of each adjustment to the Purchase Price to be made pursuant to this Section 12.5. The Parties shall negotiate in good faith and attempt to agree on such estimated adjustments prior to Closing. In the event any estimated adjustment amounts are not agreed upon prior to Closing, the estimate of the adjusted Purchase Price for purposes of Closing shall be calculated based on Optionor’s and Optionee’s agreed upon estimated adjustments and Optionor’s good faith estimate of any disputed amounts (and

40

any such disputes shall be resolved by the Parties in connection with the resolution of the Final Settlement Statement).

     (d) In the event the Purchase Price is not a Cash Payment, but is in the form of a Volumetric Production Payment, any and all adjustments in the Purchase Price shall be made and payable in cash.

ARTICLE 13. — LIMITATIONS ON WARRANTIES AND REMEDIES

          THE EXPRESS REPRESENTATIONS AND WARRANTIES OF OPTIONOR CONTAINED IN THIS AGREEMENT ARE EXCLUSIVE AND ARE IN LIEU OF ALL OTHER REPRESENTATIONS AND WARRANTIES, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY WITH RESPECT TO THE QUALITY, QUANTITY OR VOLUME OF THE RESERVES, IF ANY, OF OIL, GAS OR OTHER HYDROCARBONS IN OR UNDER THE LEASES, OR THE ENVIRONMENTAL CONDITION OF THE ASSETS. THE ITEMS OF PERSONAL PROPERTY, EQUIPMENT, IMPROVEMENTS, FIXTURES AND APPURTENANCES CONVEYED AS PART OF THE ASSETS ARE SOLD HEREUNDER “AS IS, WHERE IS, AND WITH ALL FAULTS” AND NO WARRANTIES OR REPRESENTATIONS OF ANY KIND OR CHARACTER, EXPRESS OR IMPLIED, INCLUDING ANY WARRANTY OF QUALITY, MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONDITION, ARE GIVEN BY OR ON BEHALF OF OPTIONOR. IT IS UNDERSTOOD AND AGREED THAT PRIOR TO CLOSING OPTIONEE SHALL HAVE INSPECTED THE ASSETS FOR ALL PURPOSES AND HAS SATISFIED ITSELF AS TO THEIR PHYSICAL AND ENVIRONMENTAL CONDITION, BOTH SURFACE AND SUBSURFACE, AND THAT OPTIONEE ACCEPTS SAME IN ITS “AS IS, WHERE IS AND WITH ALL FAULTS” CONDITION. OPTIONEE HEREBY WAIVES ALL WARRANTIES, EXPRESS OR IMPLIED, INCLUDING, WITHOUT LIMITATION, ANY IMPLIED WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONDITION, OR CONFORMITY TO SAMPLES.

ARTICLE 14. — CASUALTY LOSS AND CONDEMNATION

          If, prior to Closing, all or any material portion of the Assets is destroyed by fire or other casualty or if any material portion of the Assets shall be taken by condemnation or under the right of eminent domain (all of which are herein called “Casualty Loss” and limited to property damage or taking only), Optionee and Optionor must agree prior to Closing either that (i) If the value of the Casualty Loss is in dispute, the Cash Payment or payment by Optionor to Optionee at Closing shall be adjusted by an amount equal to the average of Optionor’s and Optionee’s good faith estimates of the value of the Casualty Loss, or (ii) Optionee shall proceed with the purchase of such Assets, notwithstanding any such destruction or taking (without reduction of the Purchase Price)in which case Optionor shall pay, at Closing, to Optionee all sums paid to Optionor by third parties by reason of the destruction or taking of such Assets and

41

shall assign, transfer and set over unto Optionee all insurance proceeds received by Optionor as well as all of the right, title and interest of Optionor in and to any claims, causes of action, unpaid proceeds or other payments from third parties arising out of such destruction or taking. In either case, Optionor and Optionee shall each have the right, exercisable within ninety (90) days after the Closing Date, to refer the disputed matter to mediation and arbitration in accordance with the dispute resolution procedures set forth in Exhibit “P”. After the expiration of said ninety (90) day period the right to refer the matter to mediation and arbitration shall terminate. Prior to Closing, Optionor shall not voluntarily compromise, settle or adjust any amounts payable by reason of any Casualty Loss without first obtaining the written consent of Optionee, which consent shall not be unreasonably withheld.

ARTICLE 15. — DEFAULT AND REMEDIES

     15.1. Optionor’s Remedies.

          Upon failure of Optionee to timely make the payments described in Section 2.3, or to materially comply with other material terms contained in the Agreement, Optionor, at its sole discretion, and in addition to any other remedies it may have at law or equity, may (i) enforce specific performance, or (ii) terminate this Agreement and retain any and all previous payments made hereunder.

     15.2. Optionee’s Remedies.

          Upon failure of Optionor to materially comply with all material terms contained in this Agreement, Optionee, at its sole option and in addition to any other remedies it may have at law or equity, may (i) enforce specific performance, or (ii) terminate this Agreement.

     15.3. Effect of Termination.

          In the event of termination of this Agreement under this Article 15, the transaction shall not close and neither Optionee nor Optionor shall have any further obligations, remedies, liabilities, rights or duties to the other hereunder, except as expressly provided herein.

ARTICLE 16. — ASSUMPTION AND INDEMNITY

     16.1. Assumed Obligations; Pre-Closing Liabilities.

          Upon and after Closing, Optionee shall own the Assets, together with all the rights, duties, obligations, and liabilities accruing with respect thereto, including the Assumed Obligations and Optionee’s indemnity obligations hereunder. Optionee agrees to assume and pay, perform, fulfill and discharge all Assumed Obligations and Optionee’s indemnity obligations. Optionor agrees to retain and pay, perform, fulfill and discharge all Retained Obligations, and Optionor’s indemnity obligations.

42

     16.2. Optionee’s Indemnity.

          OPTIONEE AGREES TO INDEMNIFY, DEFEND AND HOLD OPTIONOR AND OPTIONOR’S EMPLOYEES, OFFICERS AND DIRECTORS HARMLESS FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, LOSSES, DAMAGES, PUNITIVE DAMAGES, COSTS, EXPENSES, CAUSES OF ACTION OR JUDGMENTS OF ANY KIND OR CHARACTER INCLUDING, WITHOUT LIMITATION, ANY INTEREST, PENALTY, REASONABLE ATTORNEYS’ FEES AND OTHER COSTS AND EXPENSES INCURRED IN CONNECTION THEREWITH OR THE DEFENSE THEREOF (COLLECTIVELY THE “CLAIMS”), WITH RESPECT TO ALL LIABILITIES AND OBLIGATIONS OR ALLEGED OR THREATENED LIABILITIES AND OBLIGATIONS CAUSED BY, RELATED TO, ATTRIBUTABLE TO, OR ARISING OUT OF THE ASSUMED OBLIGATIONS.

          IN ADDITION TO THE FOREGOING, OPTIONEE AGREES TO INDEMNIFY, DEFEND AND HOLD OPTIONOR AND OPTIONOR’S EMPLOYEES, OFFICERS AND DIRECTORS HARMLESS FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, LOSSES, DAMAGES, PUNITIVE DAMAGES, COSTS, EXPENSES, CAUSES OF ACTION OR JUDGMENTS OF ANY KIND OR CHARACTER INCLUDING, WITHOUT LIMITATION, ANY INTEREST, PENALTY, REASONABLE ATTORNEYS’ FEES AND OTHER COSTS AND EXPENSES INCURRED IN CONNECTION THEREWITH OR THE DEFENSE THEREOF (COLLECTIVELY THE “CLAIMS”), WITH RESPECT TO ALL LIABILITIES AND OBLIGATIONS OR ALLEGED OR THREATENED LIABILITIES AND OBLIGATIONS CAUSED BY, RELATED TO, ATTRIBUTABLE TO, OR ARISING OUT OF OPTIONEE’S OPERATIONS AS TO THE ASSETS AS OF THE EXERCISE EFFECTIVE TIME.

     16.3 Optionor’s Indemnity.

          OPTIONOR AGREES TO INDEMNIFY, DEFEND AND HOLD OPTIONEE AND OPTIONEE’S EMPLOYEES, OFFICERS AND DIRECTORS HARMLESS FROM AND AGAINST ANY AND ALL CLAIMS WITH RESPECT TO ALL LIABILITIES AND OBLIGATIONS OR ALLEGED OR THREATENED LIABILITIES AND OBLIGATIONS CAUSED BY, RELATED TO, ATTRIBUTABLE TO, OR ARISING OUT OF (A) THE RETAINED OBLIGATIONS and (B) TO THE EXTENT NOT ACCOUNTED FOR IN THE CALCULATION OF THE PURCHASE PRICE PURSUANT TO SECTION 2.5, ENVIRONMENTAL OBLIGATIONS AND LIABILITIES THAT FIRST AROSE FROM OR OUT OF EVENTS OR CONDITIONS FIRST OCCURRING BETWEEN OCTOBER 1, 2004 AND THE EXERCISE EFFECTIVE DATE.

          IN ADDITION TO THE FOREGOING, OPTIONOR AGREES TO INDEMNIFY, DEFEND AND HOLD OPTIONEE AND OPTIONEE’S EMPLOYEES, OFFICERS AND DIRECTORS HARMLESS FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, LOSSES, DAMAGES, PUNITIVE DAMAGES, COSTS, EXPENSES, CAUSES OF ACTION OR JUDGMENTS OF ANY KIND OR CHARACTER INCLUDING, WITHOUT LIMITATION, ANY INTEREST, PENALTY, REASONABLE ATTORNEYS’ FEES AND OTHER COSTS AND EXPENSES INCURRED IN

43

CONNECTION THEREWITH OR THE DEFENSE THEREOF (COLLECTIVELY THE “CLAIMS”), WITH RESPECT TO ALL LIABILITIES AND OBLIGATIONS OR ALLEGED OR THREATENED LIABILITIES AND OBLIGATIONS (IN EITHER CASE, OTHER THAN ENVIRONMENTAL OBLIGATIONS AND LIABILITIES ASSUMED BY OPTIONEE PURSUANT TO SECTION 10.6) CAUSED BY, RELATED TO, ATTRIBUTABLE TO, OR ARISING OUT OF OPTIONOR’S OPERATIONS AS TO THE ASSETS PRIOR TO THE EXERCISE EFFECTIVE TIME.

     16.4. Negligence.

          THE INDEMNIFICATION, RELEASE AND ASSUMPTION PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE SOLELY OR IN PART FROM THE ACTIVE, PASSIVE, COMPARATIVE, OR CONCURRENT NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF THE PARTIES HERETO.

     16.5 Broker or Finder’s Fee.

          Each party hereby agrees to indemnify and hold the other harmless from and against any claim for a brokerage or finder’s fee or commission in connection with this Agreement or the transactions contemplated by this Agreement to the extent such claim arises from or is attributable to the actions of such indemnifying party, including, without limitation, any and all losses, damages, punitive damages, attorneys’ fees, costs and expenses of any kind or character arising out of or incurred in connection with any such claim or defending against the same.

     16.6 Threshold and Maximum Amounts.

          No claim may be made against an Indemnifying Party pursuant to this Article 16 unless, and only to the extent that, the aggregate amount of all Claims exceeds $100,000. The maximum aggregate liability of an Indemnifying Party under this Article 16 shall be an amount equal to the Purchase Price.

     16.7 Claim Procedures.

          Each Person entitled to indemnification under this Article 16 (the “Indemnified Party”) shall give written notice setting forth in reasonable detail the basis of any Claim to the Party required to provide indemnification (the “Indemnifying Party”) promptly, but not later than fifteen (15) days, after such Indemnified Party becomes aware of a Claim or receives written notice of any Claim asserted by any person who is not a Party (or a successor to a Party) to this Agreement (a “Third-Party Claim”) that is or may give rise to an indemnification claim; provided that the failure of the Indemnified Party to give notice as provided in this Section 16.7 shall not relieve any Indemnifying Party of its obligations under Section 16.7, except to the extent that such failure prejudices the rights of any such Indemnifying Party. The Indemnifying Party may elect to assume the defense of any Third-Party Claim or any litigation resulting therefrom; provided that counsel for the Indemnifying Party, who shall in such case conduct the

44

defense of such claim, shall be approved by the Indemnified Party (whose approval shall not unreasonably be withheld), and the Indemnified Party may participate in such defense at the Indemnified Party’s expense, and may retain counsel of its choice at its own expense; provided further that the Indemnified Party shall have the right to employ, at the Indemnifying Party’s expense, one firm of counsel of its choice, to represent the Indemnified Party if, in the Indemnified Party’s reasonable judgment, there exists a conflict of interest between the Indemnified Party and the Indemnifying Party, or if the Indemnifying Party (1) elects not to defend, compromise or settle a Third-Party Claim, (2) fails to notify the Indemnified Party within ten (10) Business Days of its election to defend after receipt of written notice of such Third-Party Claim, or (3) having timely elected to defend a Third-Party Claim, fails adequately to prosecute or pursue such defense, then in each case the Indemnified Party may defend such Third-Party Claim on behalf of and for the account and risk of the Indemnifying Party. The Indemnifying Party, in the defense of any Third-Party Claim, shall not, except with the prior written approval of the Indemnified Party, consent to entry of any judgment or entry into any settlement that does not include as an unconditional term thereof the giving by the claimant or plaintiff to the Indemnified Party of a release from all liability with respect thereto. The Indemnified Party shall not settle or compromise any such claim without the prior written approval of the Indemnifying Party, which approval shall not be unreasonably withheld. The Indemnified Party shall make its employees available and furnish such information regarding itself or the Claim in question as the Indemnifying Party may reasonably request in writing and as shall reasonably be required in connection with the defense of a Third-Party Claim.

ARTICLE 17. — GAS IMBALANCES

          Optionor and Optionee will use their best efforts to update (to the Exercise Effective Time) the gas imbalance volume amounts listed on Exhibit “L.” If, prior to the Final Settlement Date, either party hereto notifies the other party hereto that the volumes set forth in Exhibit “L” are incorrect, then Optionee or Optionor will pay the other at the Final Settlement, as appropriate, an amount equal to the NYMEX price at the end of the month in which the variance occurs, per net mmbtu variance from the net imbalance shown on Exhibit “L.” Subject to such adjustment on the Final Settlement Date, as of the Closing Optionee agrees to assume any liability and obligation for gas production imbalances (whether over or under) attributable to the Assets. Except as set forth in this Article 17, in assuming this liability at Closing, Optionee shall not be obligated to make any additional payment over the Purchase Price to Optionor, and Optionor shall not be obligated to refund any of said price to reimburse Optionee for any over-balances existing at the time of sale.

45

ARTICLE 18. — PREFERENTIAL RIGHT TO PURCHASE
AND AREA OF MUTUAL INTEREST PROVISION

     18.1 Preferential Right to Purchase.

     This Agreement is also made expressly subject to a preferential right to Purchase, the terms and conditions of which are as follows:

     (a) In the event Optionor or Optionee receives a bona fide offer from a third party to purchase all or a part of the interests of Optionor (reserved overriding royalty interest, Volumetric Production Payment (if any) or reversionary working interest, before or after reversion) or Optionee (the “Selling Party”) in the West Hastings Unit, the West Hastings Unit Lands or the Hastings Field lands, or other jointly owned lands within the Area of Mutual Interest (including interests hereafter owned or acquired), and once the Selling Party and a proposed transferee have fully negotiated the principal terms and conditions of a transfer (which principal terms shall include all material terms and conditions necessary for a purchaser to make an informed decision including, but not necessarily limited to, price, timing, scope, character and description of the interests to be transferred, agreed indemnities, reservations and exclusions), Selling Party shall disclose such principal terms and conditions in detail to the other party to this Agreement (the “Receiving Party”) in a written notice. Receiving Party shall have the right to acquire the interest proposed to be transferred from the Selling Party on the same terms and conditions agreed to by the proposed transferee if, within ten (10) Days after receipt of Selling Party’s written notice, the Receiving Party delivers to the Selling Party a counter-notification that Receiving Party accepts the agreed upon terms and conditions of the transfer without reservations or conditions. If the Receiving Party does not deliver such counter-notification, the transfer to the proposed transferee may be made, subject to the provisions of this Agreement, under terms and conditions no more favorable to the transferee than those set forth in the notice to Receiving Party, provided that the transfer shall be concluded within one hundred eighty (180) days from the date of Optionee’s receipt of Selling Party’s written notice. In the event the proposed sale of the interest to a third party is timely consummated, the preferential right to purchase shall no longer attach to the interest transferred to the third party. In the event the proposed sale of the interest to the third party is not consummated, then the preferential right to purchase such interest shall be reinstated as to any future offers to purchase the interest.

     (b) In the event Selling Party’s proposed transfer of part or all of its interest in the West Hastings Unit, the West Hastings Unit Lands or the Hastings Field lands, or other jointly owned lands within the Area of Mutual Interest, involves consideration other than cash or involves other properties included in a wider asset sale transaction (package deal), then the interest to be assigned by Selling Party (or part thereof) shall be allocated a reasonable and justifiable cash value in the notification to Receiving Party. Receiving Party may satisfy the requirements of this Article 18.1 by agreeing to pay such cash value in lieu of the consideration payable in the third-party offer.

46

     (c) The preferential right to purchase shall be applicable to any transfer of all or a portion of either Parties’ interest in the West Hastings Unit, the West Hastings Unit Lands or the Hastings Field lands, or other jointly owned lands within the Area of Mutual Interest, including the transfer of the reserved overriding royalty interest and/or the Reversionary Interest, whether directly or indirectly by assignment, merger, consolidation, or sale of stock, or other conveyance, other than such transfers that are made to (i) an affiliate, subsidiary, or parent company existing as of the date of this Agreement or (ii) a new affiliated entity created after the date of this Agreement for the express purpose of forming a master limited partnership, which master limited partnership is controlled by the new affiliate, Venoco, Inc. or Denbury Resources Inc. for a minimum of twelve (12) months following the transfer.

     (d) A sale or merger involving Optionor’s parent, Venoco, Inc., or the sale of all or substantially all of Venoco’s assets through merger, business combination or other transaction, including transactions involving Optionor are hereby expressly excluded from the terms of this Article 18. Likewise, a sale or merger involving Optionee’s parent, Denbury Resources Inc., or the sale of all or substantially all of Denbury Resources Inc.’s assets through merger, business combination or other transaction, including transactions involving Optionee are hereby expressly excluded from the terms of this Article 18.

     18.2. Area of Mutual Interest Provision.

     (a) The Parties hereby agree to the establishment of an Area of Mutual Interest which shall encompass all of those lands within the area outlined in blue on the plat attached hereto as Exhibit “O”, and which are more fully described on Exhibit “O-1” hereto, which area shall hereinafter sometimes be referred to as an “Area of Mutual Interest”.

     If, after the Agreement Effective Time, either party to this Agreement (“Acquiring Party”) acquires either an oil and gas lease or mineral interest (or any interest therein), royalty interest, or an option to acquire an oil and gas lease, or any other oil and/or gas interest covering lands lying within the Area of Mutual Interest, including oil, gas and mineral leases acquired pursuant to the exercise of any options (all of the foregoing hereinafter sometimes being referred to as “Oil and Gas Interests”), or if the Acquiring Party enters into any type of agreement by which an Oil and Gas Interest may be acquired or otherwise earned by conducting drilling, seismic, or other operations on the lands lying within the Area of Mutual Interest, then the Acquiring Party shall promptly notify the other party of such acquisition or such agreement. If either party to this Agreement acquires an Oil and Gas Interest covering lands within the geographical confines of the Area of Mutual Interest, the other party shall have the right to participate in any such acquisition of such Oil and Gas Interest as set forth below. If, after the Effective Time of this Agreement, additional parties acquire an interest from the original Parties in the Area of Mutual Interest, in the event not all parties elect to participate in an acquisition, then any such non-participating party’s interests shall be offered in writing to the other participating parties in the proportions that their ownership interests in the Area of Mutual Interest at the time of the acquisition bear to the total of the

47

ownership interests of all participating parties in the acquisition. In the event any acquired Oil and Gas Interest includes lands within and outside the Area of Mutual Interest, the entire Oil and Gas Interest shall be included within the AMI.

     (b) The notification provided for in Paragraph (b) above shall contain all available title information and copies of leases, agreements by which the Oil and Gas Interest may be acquired, and all other pertinent instruments and information regarding the proposed acquisition. It shall also describe in detail the cost and expense of such acquisition and any other obligation that may be incurred pursuant thereto.

     (c) If the acquisition requires drilling, seismic, or other operations on the lands lying within the Area of Mutual Interest, the election of a party to participate in such operations shall constitute an election to participate in the agreement governing such operations, to the extent necessary to acquire the interest. No party shall be required to make such an election more than sixty (60) days or less than thirty (30) days prior to the commencement of initial operations.

     (d) To receive an assignment of its proportionate share of the Oil and Gas Interest acquired as a result of conducting drilling, seismic, or other operations on the Area of Mutual Interest, a Participating Party must have:

     (1) Participated in all operations necessary for the acquisition of the Oil and Gas Interest, and also must have paid all costs and expenses incurred in connection therewith;

     (2) Participated in any previous drilling, seismic, or other operations that were necessary or were a condition precedent to the operations resulting in the acquisition of the Oil and Gas Interest; and

     (3) Participated in accordance with the terms, provisions, covenants, and conditions of the agreements governing the acquisition of an Oil and Gas Interest.

     (e) If drilling, seismic, or other operations are not required to acquire the Oil and Gas Interest, the party entitled to receive notice set forth in Section 18.2(b) shall have thirty (30) days from receipt of written notice thereof in which to elect to participate in such acquisition as set forth hereinbelow and in Section 18.2(h). Failure to give written notice to the Acquiring Party of its election, as specified herein, shall constitute an election not to participate. If a party elects to participate in such acquisition as set forth herein, such party (“Participating Party”) shall reimburse the Acquiring Party for its proportionate share of the costs thereof within fifteen (15) days of receipt of an invoice from the Acquiring Party setting forth in detail the cost and expense of such acquisition. The Acquiring Party shall, within thirty (30) days after receipt of payment from a Participating Party, assign to the Participating Party the Participating Party’s proportionate interest in the acquisition, subject to any applicable burdens on such Participating Party’s interest in the acquisition.

48

     (f) All Participating Parties shall be entitled to participate in any acquisition within the Area of Mutual Interest on a ground floor basis and subject to no additional burdens placed on an acquisition by the Acquiring Party. For purposes of this Agreement the Optionor’s interest in the Area of Mutual Interest shall be twenty-five percent (25%) and Optionee’s interest seventy-five percent (75%).

     (g) In the event the Parties acquire any Oil and Gas Interest within the Area of Mutual Interest prior to the Exercise Effective Time, then any Oil and Gas Interest acquired by the Optionor shall be included in the Designated Interests to be acquired by the Optionee and shall be valued and conveyed in accordance with the terms of this Agreement. Additionally, should the Optionee acquire any Oil and Gas Interest in the Area of Mutual Interest and elect not to exercise its Option to Purchase the Assets, Optionee shall give Optionor the right to acquire any such acquired Oil and Gas Interest at its offered cost as set forth hereinabove.

     (h) For purposes of this Section 18.2, the term “Oil and Gas Interest” shall also include surface rights or interests (including easements, rights-of-way, and surface ownership) in lands lying within the Area of Mutual Interest, and options to acquire such surface rights or interests, and any surface rights or interests acquired pursuant to the exercise of any options. Notwithstanding the foregoing, Optionor and Optionee specifically exclude from this Area of Mutual Interest any surface rights or interests (including easements, rights-of-way, and surface ownership) acquired by Optionee for the sole purpose of constructing and operating a CO2 pipeline to deliver CO2 to the Hastings Field.

     (i) The terms of this Section 18.2. shall remain in full force and effect covering the lands lying within the Area of Mutual Interest for a period of ten (10) years commencing from the Agreement Effective Time, unless extended for an additional period or terminated earlier by written agreement of the Parties.

ARTICLE 19. — MISCELLANEOUS

     19.1. Receivables and other Excluded Funds.

          Optionee shall be under no obligation to collect on behalf of Optionor any receivables or other funds included in the Excluded Assets and described in Section 1.29(e) above. With respect to receivables, Optionee shall be free to treat the interests of any party with a delinquent receivable in any manner deemed appropriate by Optionee.

     19.2. Public Announcements.

          Each Party hereto may publicly disclose information with respect to the transaction contemplated by this Agreement (i) to any state or federal governmental authority or agency to the extent required by applicable law or by any applicable rules, regulations or orders of any governmental authority or agency having jurisdiction; or (ii) as may be necessary to comply with disclosure requirements of the Securities and

49

Exchange Commission and the New York Stock Exchange or other recognized exchange and any other applicable securities laws.

     19.3. Filing and Recording of Assignments, etc.

          Optionee shall be solely responsible for all filings and the prompt recording of assignments and other documents related to the Assets and for all fees connected therewith, including the fees charged by any regulatory authority in connection with the change of operator, and Optionee shall furnish certified copies of all such filed and/or recorded documents to Optionor within ten (10) days of Optionee’s receipt of the recorded instruments. Optionor shall not be responsible for any loss to Optionee because of Optionee’s failure to file or record documents correctly or promptly. Optionee shall not be responsible for any loss to Optionor because of Optionor’s failure to record this document correctly or promptly. Optionee shall promptly file all appropriate forms, declarations or bonds with federal and state agencies relative to its assumption of operations and Optionor shall cooperate with Optionee in connection with such filings.

     19.4. Further Assurances and Records.

     (a) Each of the Parties will execute, acknowledge and deliver to the other such further instruments, and take such other action, as may be reasonably requested in order to more effectively assure to said party all of the respective properties, rights, titles, interests, estates, and privileges intended to be assigned, delivered or inuring to the benefit of such party in consummation of the transactions contemplated hereby. Without limiting the foregoing, in the event Exhibits “A-1” through “A-4”, inclusive, incorrectly or insufficiently describes or references or omits the description of a property or interest intended to be conveyed hereby as described in Sections 1.34 (Leases) or 1.54 (Personal Property) above, Optionor agrees to, within twenty (20) days of Optionor’s receipt of Optionee’s written request, together with supporting documentation satisfactory to Optionor, correct such Exhibit and/or execute an amended assignment or other appropriate instruments necessary to transfer the property or interest intended to be conveyed hereby to Optionee.

     (b) Optionee agrees to maintain the files and records of Optionor that are acquired pursuant to this Agreement for seven (7) years after the Closing. Optionee shall provide Optionor and its representatives reasonable access to and the right to copy such files and records for the purposes of (i) preparing and delivering any accounting provided for under this Agreement and adjusting, prorating and settling the charges and credits provided for in this Agreement; (ii) complying with any law, rule or regulation affecting Optionor’s interest in the Assets prior to the Closing Date; (iii) preparing any audit of the books and records of any third party relating to Optionor’s interest in the Assets prior to the Closing Date, or responding to any audit prepared by such third parties; (iv) preparing tax returns; (v) responding to or disputing any tax audit; or (vi) asserting, defending or otherwise dealing with any claim or dispute under this Agreement or as to the Assets.

50

     (c) Optionor agrees that within thirty (30) days after Closing or within thirty (30) days after operations are actually transferred of record with the Texas Railroad Commission, whichever is later, it will remove or cause to be removed its signs and the names and marks used by Optionor and all variations and derivatives thereof and logos relating thereto from the Assets and will not thereafter make any use whatsoever of such names, marks and logos.

     (d) Optionor agrees to continue to use all reasonable efforts, but without any obligation to incur any cost or expense in connection therewith, and to cooperate with Optionee’s efforts to obtain for Optionee (i) access to files, records and data relating to the Assets in the possession of third parties; and (ii) access to wells constituting a part of the Assets operated by third parties for purposes of inspecting same.

     (e) Optionee shall comply with all current and subsequently amended applicable laws, ordinances, rules, and regulations applicable to the Assets and shall promptly obtain and maintain all permits required by governmental authorities in connection with the Assets.

     19.5. Notices.

          Except as otherwise expressly provided herein, all communications required or permitted under this Agreement shall be in writing and may be given by personal delivery, facsimile, US mail (postage prepaid), or commercial delivery service, and any communication hereunder shall be deemed to have been duly given and received when actually delivered to the address of the Parties to be notified as set forth below and addressed as follows:

     If to Optionor, as follows:

	TexCal Energy South Texas L.P.
	c/o Venoco, Inc.
	370 17th Street
	Suite 2950
	Denver, Colorado 80202
	Attention:	William Schneider President
	Telephone: Facsimile:	(303) 626-8318 (303) 626-8315
with copies to:
	TexCal Energy South Texas L.P.
	1020 Main Street, Suite 2500
	Houston, Texas 77002
	Attention:	Jeffrey T. Janik
		Senior Vice President
	Telephone:	(713) 533-4000
	Facsimile:	(713) 533-4060

51

and
	Venoco, Inc.
	6267 Carpinteria Ave.
	Carpinteria, CA 93013
	Attention:	General Counsel
	Telephone:	(805) 745-2253
	Facsimile:	(805) 745-1816
If to Optionee, as follows:
	Denbury Onshore, LLC
	5100 Tennyson Parkway
	Suite 1200
	Plano, Texas 75024
	Attention:	Ray Dubuisson
		Vice President-Land
	Telephone:	(972)-673-2044
	Facsimile:	(972)-673-2299

Provided, however, that any notice required or permitted under this Agreement will be effective if given verbally within the time provided, so long as such verbal notice is followed by written notice thereof in the manner provided herein within twenty-four (24) hours following the end of such time period. Any party may, by written notice so delivered to the other, change the address to which delivery shall thereafter be made.

     19.6. Incidental Expenses.

          Optionee shall bear and pay (i) all state or local government sales, transfer, gross proceeds, or similar taxes incident to or caused by the transfer of any of the Assets to Optionee, (ii) all documentary, transfer and other state and local government taxes incident to the transfer of any of the Assets to Optionee; and (iii) all filing, recording or registration fees for any assignment or conveyance delivered hereunder. Each party shall bear its own respective expenses incurred in connection with the negotiation and closing of this transaction, including it own consultants’ fees, attorneys’ fees, accountants’ fees, and other similar costs and expenses.

     19.7. Waiver.

          Any of the terms, provisions, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by the party waiving compliance. Except as otherwise expressly provided in this Agreement, the failure of any party at any time or times to require performance of any provision hereof shall in no manner affect such party’s right to enforce the same. No waiver by any party of any condition, or of the breach of any term, provision, covenant, representation or warranty contained in this Agreement, whether by conduct or otherwise, in any one or

52

more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of the breach of any other term, provision, covenant, representation or warranty.

     19.8. Binding Effect; Assignment.

          All the terms, provisions, covenants, obligations, indemnities, representations, warranties and conditions of this Agreement shall be covenants running with the land and shall inure to the benefit of, and be binding upon, and shall be enforceable by, the parties hereto and their respective successors and assigns. The rights of Optionee under this Agreement to acquire the Assets are personal and this Agreement may not be assigned or transferred by Optionee to any other party, firm, corporation or other entity, without the prior, express and written consent of Optionor, and such consent may be withheld for any reason, including convenience. Any attempt to assign this Agreement by Optionee over the objection or without the express written consent of the Optionor shall be absolutely void. Optionor may condition its consent to assign this Agreement on Optionee providing Optionor with an appropriate guarantee of its assignee’s performance. Any subsequent transfer of this Agreement or of all or any part of the Assets shall be made expressly subject to the terms and provisions of this Agreement.

     19.9. Taxes.

     (a) Optionor and Optionee agree that this transaction may be subject to the reporting requirement of Section 1060 of the Internal Revenue Code of 1986, as amended, and that, therefore, IRS Form 8594, Asset Acquisition Statement, will be filed for this transaction. The Parties will confer and cooperate in the preparation and filing of their respective forms to reflect a consistent reporting of the agreed upon allocation.

     (b) Optionor shall be responsible for all state, local and federal property, ad valorem, excise, and severance taxes attributable to or arising from the ownership or operation of the Assets prior to the Exercise Effective Time. Optionee shall be responsible for all property and severance taxes attributable to or arising from the ownership or operation of the Assets after the Exercise Effective Time. Any party which pays such taxes for the other party shall be entitled to prompt reimbursement upon evidence of such payment. Each party shall be responsible for its own federal and state income taxes, if any, as may result from this transaction.

     (c) If this transaction is determined to result in state sales or transfer taxes, Optionee shall be solely responsible for any and all such taxes due on the Assets acquired by Optionee by virtue of this transaction. If Optionee is assessed such taxes, Optionee shall promptly remit same to the taxing authority. If Optionor is assessed such taxes, Optionee shall reimburse Optionor for any such taxes paid by Optionor to the taxing authority.

53

     19.10. Audits.

          It is expressly understood and agreed that Optionor retains its right to receive its proportionate share of the proceeds from any audits relating to activities prior to the Exercise Effective Time, and Optionor shall likewise pay its share of any costs attributable to the period prior to the Effective Time resulting from any such audits.

     19.11. Governing Law.

          THIS AGREEMENT SHALL BE GOVERNED, CONSTRUED AND ENFORCED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS OTHERWISE APPLICABLE TO SUCH DETERMINATIONS.

     19.12. Mediation and Arbitration.

          The Parties stipulate and agree that any and all claims and/or controversies arising between Optionor and Optionee which relate to and arise out of this Agreement shall be resolved in accordance with the mediation and arbitration procedures set forth in Exhibit “P.” The prevailing party in any legal proceeding or arbitration may be entitled to recover all arbitration costs and reasonable attorneys’ fees from the non-prevailing party, as determined by the arbitrators in accordance with the procedures set forth in Exhibit “P.”

     19.13. Entire Agreement.

          This Agreement, including the Exhibits attached hereto, embodies the entire agreement between the Parties and replaces and supersedes all prior agreements, arrangements and understandings related to the subject matter hereof, whether written or oral. No other agreement, statement, or promise made by any party, or to any employee, officer or agent of any party, which is not contained in this Agreement, shall be binding or valid. This Agreement may be supplemented, altered, amended, modified or revoked by a writing only, signed by the Parties hereto. The headings herein are for convenience only and shall have no significance in the interpretation hereof. The Parties stipulate and agree that this Agreement shall be deemed and considered for all purposes, as prepared through the joint efforts of the Parties, and shall not be construed against one party or the other as a result of the preparation, submittal or other event of negotiation, drafting or execution thereof. It is understood and agreed that there shall be no third-party beneficiary of this Agreement, and that the provisions hereof do not impart enforceable rights in anyone who is not a direct, initial party hereto.

     19.14. Severability.

          If any provision of this Agreement is found by a court of competent jurisdiction to be invalid or unenforceable, that provision will be deemed modified to the extent necessary to make it valid and enforceable, and if it cannot be so modified, it

54

shall be deemed deleted and the remainder of the Agreement shall continue and remain in full force and effect.

     19.15. Exhibits.

          All Exhibits attached to this Agreement, and the terms of those Exhibits which are referred to in this Agreement, are made a part hereof and incorporated herein by reference.

     19.16. Survival.

          Unless otherwise specifically provided in this Agreement, all of the representations, warranties, indemnities, covenants and agreements of or by the Parties hereto shall survive the execution and delivery of the each Conveyance, Assignment and Bill of Sale. Additionally, those provisions set forth in Section 6.3 shall survive the execution and delivery of the Conveyance, Assignment and Bill of Sale, and shall be deemed as between the Parties, there successors and assigns to be covenants running with the land.

     19.17. Subsequent Adjustments.

          Regardless of the date set for the Final Settlement, Optionee and Optionor agree that their intent is to allow for the earliest practical forwarding of revenue and reimbursement of expenses between them, and Optionor and Optionee recognize that either may receive funds or pay expenses after the Final Settlement Date which are properly the property or obligation of the other. Therefore, upon receipt of net proceeds or payment of net expenses due to or payable by the other party hereto, whichever occurs first, Optionor or Optionee, as the case may be, shall submit a statement to the other party hereto showing the relevant items of income and expense with supporting documentation. Payment of any net amount due by Optionor or Optionee, as the case may be, on the basis thereof shall be made within ten (10) days of receipt of the statement.

     19.18. Counterparts.

          This Agreement may be executed in any number of counterparts, and each and every counterpart shall be deemed for all purposes one (1) agreement.

     19.19. Subrogation.

          To the fullest extent allowed by law and the applicable agreements with third parties, Optionor grants Optionee a right of subrogation in all claims or rights Optionor may have against third parties to the extent they relate to the Assumed Obligations.

55

     19.20. Suspended Monies.

          At Closing, Optionor shall deliver to Optionee the monies held in suspense by Optionor for the account of third parties, or relate to a title dispute or question as to ownership, along with any documentation in Optionor’s possession or available to Optionor in support of such suspended funds. Any additional monies of this nature received by Optionor after Closing shall be remitted to Optionee within one hundred twenty (120) days after the Closing hereof. At Closing, Optionee shall assume the obligation for the payment of these monies.

     19.21. Optionee as Operator.

After the Closing Date, Optionee shall operate, manage, and administer the Assets as a reasonable prudent operator and in a good and workmanlike manner in accordance with the West Hastings Unit Operating Agreement. The Parties acknowledge that changes and amendments to the West Hastings Unit Operating Agreement may become necessary and required by both Parties and will be negotiated as needed. These changes and amendments may be in the form of changes and amendments to the existing West Hastings Unit Operating Agreement, a new unit operating agreement, or a side letter agreement.

          IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first above written.

TEXCAL ENERGY SOUTH TEXAS, L.P.      By: TEXCAL ENERGY (GP) LLC.
By:	/s/ William Schneider
	William Schneider
	President

DENBURY ONSHORE, LLC
By:	/s/ H. Raymond Dubuisson
	H. Raymond Dubuisson
	Vice President-Land

56

EX-10.(C)

Exhibit 10 C

FIRST AMENDMENT TO OPTION AGREEMENT

          This First Amendment to Option Agreement (“First Amendment”), dated as of August 29, 2008, is by and between TexCal Energy South Texas, L.P. whose address is 1021 Main Street, Suite 2500, Houston, Texas 77002 (“Optionor”), and Denbury Onshore, LLC, whose address is 5100 Tennyson Parkway, Suite 1200, Plano, Texas 75024 (“Optionee”). Optionor and Optionee are sometimes together referred to herein as “Parties”.

     WHEREAS, Optionor and Optionee entered into that certain Option Agreement dated November 1, 2006 (the “Option Agreement”) pursuant to which Optionor granted Optionee an Option to Purchase certain Assets, as defined in the Option Agreement;

     WHEREAS, Optionee has advised Optionor that it will elect to exercise the Option to Purchase subject to the agreement of Optionor to amend the Option Agreement as requested by Optionee; and

     WHEREAS, Optionor is agreeable to the amendments proposed by Optionee as set forth herein;

     NOW, THEREFORE, in consideration of the mutual agreements, provisions and covenants contained herein and other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Parties, intending to be legally bound, hereby agree as follows:

     Section 1. Defined Terms. Capitalized terms used but not otherwise defined herein shall have the meanings assigned such terms in the Option Agreement.

     Section 2. Option Exercise.

     Optionee hereby exercises its Option to Purchase the Assets, and accordingly, pursuant to the provisions of Section 2.4 of the Option Agreement, hereby delivers to Optionor the attached Option Exercise Notice in the form of Exhibit “G” to the Option Agreement. The Exercise Effective Time shall be 7:00 a.m. Central Standard Time on January 1, 2009.

     Section 3. Amendments. The Option Agreement is hereby amended as follows:

          (a) Section 2.7 is amended and restated to read in its entirety as follows:

          2.7 Development Plan and Capital Expenditure Commitment.

     (a) In the event Optionee exercises its option to purchase the Assets, Optionee shall (i) prior to June 30, 2009, submit to Optionor a development plan for the CO2 flood of the West Hastings Unit (the “Development Plan”), which plan

1

shall include various milestones including completion of a pipeline connecting the Jackson Dome Field in Mississippi to the Hastings Field via Donaldsonville, Louisiana, or other pipeline or alternative delivery system that would result in a lower CO2 cost to the Hastings Field, a framework for spending the Required Cumulative Capital Expenditure Amounts, and the commencement of CO2 injection in the West Hastings Unit and (ii) commit to spend one hundred seventy-eight million six hundred seventy four thousand dollars ($178,674,000.00) of cumulative capital expenditures (the “Required Cumulative Capital Expenditure Amounts”) as outlined in the Development Plan for field development and facilities for enhanced production operations in the West Hastings Unit. Optionee shall spend the Required Cumulative Capital Expenditures Amounts on or before the Commitment Dates set forth below:

“Commitment Date”	“Required Cumulative Capital
By end of Calendar Year	Expenditure Amount”
2010	$	26,801,000
2011	$	71,469,000
2012	$	107,204,000
2013	$	142,939,000
2014	$	178,674,000

     If the Optionee spends in excess of one hundred seventy-eight million six hundred seventy four thousand dollars ($178,674,000.00) prior to the end of 2014, the development obligation has been fulfilled.

     (b) In the event Optionee fails to spend the Required Cumulative Capital Expenditure Amount by the Commitment Dates set forth in (a) above, Optionee shall pay Optionor a cash payment equal to ten percent, (10.0%) of the difference between (i) the Required Cumulative Capital Expenditure Amount for the applicable Commitment Date and (ii) the cumulative capital expenditures actually expended by Optionee from the Exercise Effective Time through such applicable Commitment Date (hereinafter referred to as the “Shortage Payment”). Said Shortage Payment shall be paid by Optionee to Optionor within thirty (30) days after each Commitment Date.

     (c) If Optionee is not injecting at least an average of 50 mmcf/day of CO2 (total of purchased plus recycled) in the West Hastings Unit (“Minimum Injection Rate”), which gas shall be delivered to the Hastings Field via the Donaldsonville to Hastings pipeline or other pipeline or alternative delivery system that would result in a lower CO2 cost to the Hastings Field, for the 90 day period preceding January 1, 2013, Optionee shall, within 30 days of such date, either (i)

2

relinquish its rights to initiate (or continue) tertiary operations and reassign to Optionor all Assets previously assigned to Optionee, for the value of such Assets at that time based on the methodology outlined in Section 2.5, except the NPV discount rate described in Section 2.5(b)(i)(4) shall be twenty percent (20%) rather than ten percent (10%), or (ii) begin making additional Shortage Payments to Optionor in an amount equal to twenty million dollars ($20,000,000.00) less Shortage Payments paid pursuant to Section 2.7(b) for the calendar year ending December 31, 2012, and thirty million dollars ($30,000,000.00) less Shortage Payments paid pursuant to Section 2.7(b) for each subsequent calendar year until the CO2 injection in the Hasting Field equals or exceeds the Minimum Injection Rate. If Optionee elects to relinquish its rights as set forth herein and Optionor accepts such relinquishment, Optionee shall have no further rights or obligations with respect to the Assets. Notwithstanding the relinquishment option described in this Section 2.7(c), Optionor shall have the option to reject such relinquishment, in which case Optionee shall retain the Assets and the Shortage Payment shall be deemed waived for that year and the Minimum Injection Rate requirement will be deferred until the next anniversary of the Exercise Effective Time.

     Section 4. Amendment and Ratification.

     Upon the execution hereof, this First Amendment shall be deemed to be an amendment to the Option Agreement, and the Option Agreement, as modified hereby, is hereby ratified, approved and confirmed to be in full force and effect in each and every respect.

(signatures on following page)

3

     IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first above written.

TEXCAL ENERGY SOUTH TEXAS, L.P.      By: TEXCAL ENERGY (GP) LLC.
By:	/s/ Timothy M. Marquez
	Timothy M. Marquez
	Chief Executive Officer

DENBURY ONSHORE, LLC
By:	/s/ H. Raymond Dubuisson
	H. Raymond Dubuisson
	Vice President-Land

4

EX-31.(A)

Exhibit 31(a)

CERTIFICATION UNDER SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Gareth Roberts, certify that:

1.	I have reviewed this quarterly report on Form 10-Q 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.

November 7, 2008	/s/ Gareth Roberts
	Gareth Roberts
	President and Chief Executive Officer

EX-31.(B)

Exhibit 31(b)

CERTIFICATION UNDER SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Phil Rykhoek, certify that:

1.	I have reviewed this quarterly report on Form 10-Q 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.

November 7, 2008	/s/ Phil Rykhoek
	Phil Rykhoek
	Sr. Vice President and Chief Financial Officer

EX-32

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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (the “Report”) of Denbury Resources Inc. (“Denbury”) as filed with the Securities and Exchange Commission on November 7, 2008, 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:  November 7, 2008	/s/ Gareth Roberts
	Gareth Roberts
	President and Chief Executive Officer
Dated:  November 7, 2008	/s/ Phil Rykhoek
	Phil Rykhoek
	Sr. Vice President and Chief Financial Officer