Denbury (DNRWW) 8-K Other Events

Exhibit 99.4

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, 2009

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission File Number:001-16295

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	75-2759650
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

(817) 877-9955

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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.                                                                                                                  Yesþ       Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).                                                                                                        Yeso       Noo

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.

Large accelerated filerþ Accelerated filero Non-accelerated filero
(Do not check if a smaller reporting company) Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).                   Yeso       Noþ

Number of shares of common stock, $0.01 par value, outstanding as of October 27, 2009   55,541,823

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands, except share and par value amounts)

	September 30,			December 31,
	2009			2008
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	6,683		$	2,039
Accounts receivable, net of allowance for doubtful accounts of $434 and $381, respectively		104,980			117,995
Current portion of long-term receivables		8,325			11,070
Inventory		24,593			24,798
Derivatives		51,974			349,344
Income taxes		9,801			29,445
Other		7,310			6,239
Total current assets		213,666			540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		4,146,881			3,538,459
Unproved properties		104,931			124,339
Accumulated depletion, depreciation, and amortization		(985,349	)		(771,564	)
		3,266,463			2,891,234
Other property and equipment		28,598			25,192
Accumulated depreciation		(16,100	)		(12,753	)
		12,498			12,439
Goodwill		60,606			60,606
Derivatives		47,694			38,497
Long-term receivables, net of allowance for doubtful accounts of $13,725 and $7,643, respectively		53,454			60,915
Other		59,433			28,574
Total assets	$	3,713,814		$	3,633,195
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	10,412		$	10,017
Accrued liabilities:
Lease operating		18,115			19,108
Development capital		48,266			79,435
Interest		21,839			11,808
Production, ad valorem, and severance taxes		34,475			25,133
Compensation		9,434			16,216
Derivatives		37,238			63,476
Oil and natural gas revenues payable		16,658			10,821
Deferred taxes		63,968			105,768
Other		15,202			10,470
Total current liabilities		275,607			352,252
Derivatives		39,370			8,922
Future abandonment cost, net of current portion		51,664			48,058
Deferred taxes		431,075			416,915
Long-term debt		1,243,496			1,319,811
Other		3,837			3,989
Total liabilities		2,045,049			2,149,947
Commitments and contingencies (see Note 15)
Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 144,000,000 shares authorized, 54,621,701 and 51,551,937 issued and outstanding, respectively		546			516
Additional paid-in capital		666,386			525,763
Treasury stock, at cost, none and 4,753 shares, respectively		—			(101	)
Retained earnings		728,299			789,698
Accumulated other comprehensive loss		(1,184	)		(1,748	)
Total EAC stockholders’ equity		1,394,047			1,314,128
Noncontrolling interest		274,718			169,120
Total equity		1,668,765			1,483,248
Total liabilities and equity	$	3,713,814		$	3,633,195

The accompanying notes are an integral part of these consolidated financial statements.

1

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
Revenues:
Oil	$	152,949		$	268,543		$	374,915		$	776,001
Natural gas		32,168			66,772			86,908			182,973
Marketing		887			2,163			2,008			8,740
Total revenues		186,004			337,478			463,831			967,714
Expenses:
Production:
Lease operating		38,141			48,966			122,817			130,013
Production, ad valorem, and severance taxes		19,222			33,350			48,074			95,845
Depletion, depreciation, and amortization		72,627			58,545			217,361			159,114
Impairment of long-lived assets		—			26,292			—			26,292
Exploration		16,668			13,381			43,801			30,462
General and administrative		13,270			15,303			40,743			36,549
Marketing		358			1,855			1,612			9,362
Derivative fair value loss (gain)		(13,256	)		(239,435	)		(741	)		82,093
Other operating		8,241			4,073			29,419			9,805
Total expenses		155,271			(37,670	)		503,086			579,535
Operating income (loss)		30,733			375,148			(39,255	)		388,179
Other income (expenses):
Interest		(21,920	)		(18,124	)		(57,009	)		(54,669	)
Other		600			1,553			1,811			3,090
Total other expenses		(21,320	)		(16,571	)		(55,198	)		(51,579	)
Income (loss) before income taxes		9,413			358,577			(94,453	)		336,600
Income tax benefit (provision)		(11,189	)		(121,184	)		25,254			(118,595	)
Consolidated net income (loss)		(1,776	)		237,393			(69,199	)		218,005
Less: net loss (income) attributable to noncontrolling interest		(3,223	)		(31,086	)		9,669			(16,198	)
Net income (loss) attributable to EAC stockholders	$	(4,999	)	$	206,307		$	(59,530	)	$	201,807
Net income (loss) per common share:
Basic	$	(0.10	)	$	3.88		$	(1.15	)	$	3.78
Diluted	$	(0.10	)	$	3.77		$	(1.15	)	$	3.67
Weighted average common shares outstanding:
Basic		52,349			52,258			51,964			52,466
Diluted		52,349			52,979			51,964			53,134

The accompanying notes are an integral part of these consolidated financial statements.

2

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF EQUITY AND COMPREHENSIVE LOSS
(in thousands)
(unaudited)

	EAC Stockholders
	Issued																		Accumulated
	Shares of						Additional			Shares of									Other
	Common				Common		Paid-in			Treasury			Treasury			Retained			Comprehensive			Noncontrolling			Total
	Stock				Stock		Capital			Stock			Stock			Earnings			Loss			Interest			Equity
Balance at December 31, 2008		51,557			$	516	$	525,763			(5	)	$	(101	)	$	789,698		$	(1,748	)	$	169,120		$	1,483,248
Exercise of stock options and vesting of restricted stock		430				3		37			—			—			—			—			—			40
Net proceeds from issuance of common stock		2,750				27		100,663			—			—			—			—			—			100,690
Purchase of treasury stock		—				—		—			(111	)		(2,961	)		—			—			—			(2,961	)
Cancellation of treasury stock		(116	)			—		(1,193	)		116			3,062			(1,869	)		—			—			—
Non-cash equity-based compensation		—				—		11,308			—			—			—			—			117			11,425
ENP cash distributions to noncontrolling interest		—		��		—		—			—			—			—			—			(24,629	)		(24,629	)
Net proceeds from ENP issuance of common units		—				—		—			—			—			—			—			169,945			169,945
Adjustment to reflect gain on ENP issuance of common units		—				—		29,691			—			—			—			—			(29,691	)		—
Other		—				—		117			—			—			—			—			—			117
Components of comprehensive loss:
Consolidated net loss		—				—		—			—			—			(59,530	)		—			(9,669	)		(69,199	)
Change in deferred hedge loss on interest rate swaps, net of tax of $256		—				—		—			—			—			—			564			(475	)		89
Total comprehensive loss																										(69,110	)
Balance at September 30, 2009		54,621			$	546	$	666,386			—		$	—		$	728,299		$	(1,184	)	$	274,718		$	1,668,765

The accompanying notes are an integral part of these consolidated financial statements.

3

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

	Nine months ended
	September 30,
	2009			2008
Cash flows from operating activities:
Consolidated net income (loss)	$	(69,199	)	$	218,005
Adjustments to reconcile consolidated net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		217,361			159,114
Impairment of long-lived assets		—			26,292
Non-cash exploration expense		42,374			27,699
Deferred taxes		(25,903	)		109,653
Non-cash equity-based compensation expense		9,761			9,963
Non-cash derivative loss		105,757			38,203
Loss (gain) on disposition of assets		26			(691	)
Other		17,992			7,349
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		37,719			(31,135	)
Current derivatives		256,261			(12,196	)
Other current assets		12,565			(30,745	)
Long-term derivatives		—			(7,028	)
Other assets		(413	)		(2,094	)
Accounts payable		5,511			(2,476	)
Other current liabilities		24,563			20,581
Other noncurrent liabilities		(1,222	)		(1,507	)
Net cash provided by operating activities		633,153			528,987
Cash flows from investing activities:
Proceeds from disposition of assets		5,205			1,230
Purchases of other property and equipment		(3,576	)		(2,416	)
Acquisition of oil and natural gas properties		(423,959	)		(116,767	)
Development of oil and natural gas properties		(293,443	)		(384,864	)
Net collections from (advances to) working interest partners		5,457			(33,277	)
Net cash used in investing activities		(710,316	)		(536,094	)
Cash flows from financing activities:
Repurchase and retirement of common stock		—			(50,000	)
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		(2,921	)		799
Proceeds from long-term debt, net of issuance costs		590,090			1,070,238
Payments on long-term debt		(676,000	)		(974,500	)
Proceeds from EAC issuance of common stock, net of offering costs		100,690			—
ENP cash distributions to noncontrolling interest		(24,629	)		(19,525	)
Proceeds from ENP issuance of common units, net of offering costs		170,149			—
Payments of deferred commodity derivative contract premiums		(70,456	)		(30,822	)
Change in cash overdrafts		(5,116	)		13,040
Net cash provided by financing activities		81,807			9,230
Increase in cash and cash equivalents		4,644			2,123
Cash and cash equivalents, beginning of period		2,039			1,704
Cash and cash equivalents, end of period	$	6,683		$	3,827

The accompanying notes are an integral part of these consolidated financial statements.

4

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Description of Business

     EAC is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, reengineering or expanding existing waterflood projects, and applying tertiary recovery techniques. EAC’s properties and oil and natural gas reserves are located in four core areas:

• the Cedar Creek Anticline (“CCA”) in the Williston Basin in Montana and North Dakota;

• the Permian Basin in West Texas and southeastern New Mexico;

• the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and

• the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Arkansas and Oklahoma, the North Louisiana Salt Basin, and the East Texas Basin.

Note 2. Basis of Presentation

     EAC’s consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, EAC’s financial position as of September 30, 2009, results of operations for the three and nine months ended September 30, 2009 and 2008, and cash flows for the nine months ended September 30, 2009 and 2008. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in EAC’s 2008 Annual Report on Form 10-K.

Noncontrolling Interest

     As of September 30, 2009 and December 31, 2008, EAC owned approximately 46 percent and 63 percent, respectively, of ENP’s common units. EAC also owns 100 percent of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and indirect wholly owned non-guarantor subsidiary of EAC, which is ENP’s general partner. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (ASC 810-20), the financial position, results of operations, and cash flows of ENP are fully consolidated with those of EAC.

     As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of September 30, 2009 and December 31, 2008 of approximately $274.7 million and $169.1 million, respectively, represents third-party partnership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Net income attributable to noncontrolling interest” for the three months ended September 30, 2009 of approximately $3.2 million, “Net loss attributable to noncontrolling interest” for the nine months ended September 30, 2009 of approximately $9.7 million, and “Net income attributable to noncontrolling interest” for the three and nine months ended September 30, 2008 of approximately $31.1 million and $16.2 million, respectively, represents the net income or loss of ENP attributable to third-party partners.

5

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table summarizes the effects of changes in EAC’s partnership interest in ENP on EAC’s equity for the periods indicated:

	Three months ended					Nine months ended
	September 30,					September 30,
	2009			2008		2009			2008
	(in thousands)
Net income (loss) attributable to EAC stockholders	$	(4,999	)	$	206,307	$	(59,530	)	$	201,807
Transfer from (to) noncontrolling interest:
Increase in EAC’s paid-in capital for ENP’s issuance of 283,700 common units in connection with acquisition of net profits interest in certain Crockett County properties		—			—		—			3,458
Increase in EAC’s paid-in capital for ENP’s issuance of 2,760,000 common units in public offering		—			—		9,312			—
Increase in EAC’s paid-in capital for ENP’s issuance of 9,430,000 common units in public offering		20,379			—		20,379			—
Net transfer from noncontrolling interest		20,379			—		29,691			3,458
Change from net income (loss) attributable to EAC stockholders and transfers from (to) noncontrolling interest	$	15,380		$	206,307	$	(29,839	)	$	205,265

Supplemental Disclosures of Non-cash Investing and Financing Activities

     The following table sets forth supplemental disclosures of non-cash investing and financing activities for the periods indicated:

	Nine months ended September 30,
	2009		2008
	(in thousands)
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts	$	44,907	$	53,387
ENP’s issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties		—		5,748

Allowance for Doubtful Accounts

     During the three and nine months ended September 30, 2009, EAC recorded an allowance for doubtful accounts of approximately $2.4 million and $7.1 million, respectively, primarily related to balances due from ExxonMobil Corporation (“ExxonMobil”) in connection with EAC’s joint development agreement, which are included in “Other operating expense” in the accompanying Consolidated Statements of Operations. The following table summarizes the changes in the allowance for doubtful accounts for the nine months ended September 30, 2009 (in thousands):

Allowance for doubtful accounts at January 1, 2009	$	8,024
Bad debt expense		7,116
Write off		(981	)
Allowance for doubtful accounts at September 30, 2009	$	14,159

     As of September 30, 2009, $0.4 million of EAC’s allowance for doubtful accounts was current and $13.7 million was long-term.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, certain amounts in the Consolidated Financial Statements have been either combined or classified in more detail.

6

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

FASB Launches Accounting Standards Codification

     In June 2009, the FASB issued SFAS No. 168,“The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”(“SFAS 168” or ASC 105-10). SFAS 168 (ASC 105-10) establishes the Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS 168 (ASC 105-10) was prospectively effective for financial statements issued for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of SFAS 168 (ASC 105-10) on July 1, 2009 did not impact EAC’s results of operations or financial condition.

     Following the Codification, the FASB will not issue new standards in the form of Statements, FASB Staff Positions (“FSP”), or EITF Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”), which will serve to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the changes to the Codification.

     The Codification did not change GAAP; however, it did change the way GAAP is organized and presented. As a result, these changes impact how companies, including EAC, reference GAAP in their financial statements and in their significant accounting policies. EAC implemented the Codification in this Report by providing references to the Codification topics alongside references to the corresponding standards.

New Accounting Pronouncements

FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2” or ASC 820.10)

     In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157,“Fair Value Measurements”(“SFAS 157” or ASC 820-10) for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). EAC elected a partial deferral of SFAS 157 (ASC 820-10) for all instruments within the scope of FSP FAS 157-2 (ASC 820-10), including, but not limited to, its asset retirement obligations and indefinite lived assets. FSP FAS 157-2 (ASC 820-10) was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of FSP FAS 157-2 (ASC 820-10) on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. Please read “Note 6. Fair Value Measurements” for additional discussion.

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R” or ASC 805)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations” (ASC 805). SFAS 141R (ASC 805) establishes principles and requirements for the acquiror in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies” (“FSP FAS 141R-1” or ASC 805), which amends and clarifies SFAS 141R (ASC 805) to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R (ASC 805) and FSP FAS 141R-1 (ASC 805) were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. The adoption of SFAS 141R (ASC 805) and FSP FAS 141R-1 (ASC 805) on January 1, 2009 did not impact EAC’s results of operations or financial condition. However, the application of SFAS 141R (ASC 805) and FSP FAS 141R-1 (ASC 805) to future acquisitions could impact EAC’s results of operations and financial condition and the reporting of acquisitions in the consolidated financial statements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51” (“SFAS 160” or ASC 810-10-65-1)

     In December 2007, the FASB issued SFAS 160 (ASC 810-10-65-1), which amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” (ASC 810-10, 860-10-60-1, 850-10-60, 970-810-25-1, 958-810-60, and 505-10), to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 (ASC 810-10-65-1) was prospectively effective for financial statements issued for fiscal years beginning on or after December 15,

7

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

2008, except for the presentation and disclosure requirements which were retrospectively effective. SFAS 160 (ASC 810-10-65-1) clarifies that a noncontrolling interest in a subsidiary, which was often referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 (ASC 810-10-65-1) requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains or losses on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 (ASC 810-10-65-1) on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition; however, it did impact the presentation of noncontrolling interest in the accompanying Consolidated Financial Statements.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161” or ASC 815-10-65-1)

     In March 2008, the FASB issued SFAS 161 (ASC 815-10-65-1), which amends SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities”(“SFAS 133” or ASC 815), to require enhanced disclosures, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 (ASC 815) and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 (ASC 815-10-65-1) was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of SFAS 161 (ASC 815-10-65-1) on January 1, 2009 required additional disclosures regarding EAC’s derivative instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 6. Fair Value Measurements” for additional discussion.

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1” or ASC 260-10)

     In June 2008, the FASB issued FSP EITF 03-6-1 (ASC 260-10), which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share (“EPS”) under the two-class method prescribed by SFAS No. 128, “Earnings per Share” (“SFAS 128” or ASC 260-10). FSP EITF 03-6-1 (ASC 260-10) was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The adoption of FSP EITF 03-6-1 (ASC 260-10) on January 1, 2009 did not have a material impact on EAC’s EPS calculations. In the accompanying Consolidated Financial Statements, periods prior to the adoption of FSP EITF 03-6-1 (ASC 260-10) have been restated to calculate EPS in accordance with this pronouncement. Please read “Note 11. Earnings Per Share” for additional discussion.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”)

     In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 is prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009. EAC is evaluating the impact Release 33-8995 will have on its financial condition, results of operations, and disclosures.

FSP No. FAS 107-1 and APB 28-1, “Disclosure of Fair Value of Financial Instruments in Interim Statements” (“FSP FAS 107-1 and APB 28-1” or ASC 825-10-65-1)

     In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1), which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1) was prospectively effective for financial statements issued for interim periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1) on June 30, 2009 required additional disclosures regarding EAC’s

8

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

financial instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 6. Fair Value Measurements” for additional discussion.

SFAS No. 165, “Subsequent Events” (“SFAS 165” or ASC 855-10)

     In June 2009, the FASB issued SFAS 165 (ASC 855-10) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, SFAS 165 (ASC 855-10) sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 (ASC 855-10) was prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 (ASC 855-10) on June 30, 2009 did not impact EAC’s results of operations or financial condition.

ASU No. 2009-05, “Fair Value Measurement and Disclosure: Measuring Liabilities at Fair Value” (“ASU 2009-05” or ASC 820-10)

     In August 2009, the FASB issued ASU 2009-05 (ASC 820-10) to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a valuation technique should be applied that uses either the quote of the liability when traded as an asset, the quoted prices for similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. The adoption of ASU 2009-05 (ASC 820-10) on December 31, 2009 will not impact EAC’s results of operations or financial condition.

Note 3. Acquisitions

Acquisitions from EXCO

     In August 2009, Encore Operating acquired certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO Resources, Inc. (together with its affiliates, “EXCO”) for approximately $357.0 million in cash, substantially all of which are proved producing. The operations of these properties have been included with those of EAC from the date of acquisition forward. EAC financed the acquisitions through borrowings under its revolving credit facilities and proceeds from the issuance of ENP common units to the public. A portion of the properties acquired in the EXCO acquisition and the sale of properties to ENP in August 2009, as discussed in “Note 17. ENP,” qualified as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended, and I.R.S. Revenue Procedure 2000-37.

CO2 Supply Agreement

     In July 2009, EAC acquired contract rights for $24 million in cash, which procures a CO2 supply to be used for a tertiary oil recovery project in EAC’s Bell Creek Field. The initial term of the contract is 15 years. The contract is classified as an intangible asset and is included in “Other” assets in the accompanying Consolidated Balance Sheet as of September 30, 2009.

Note 4. Inventory

     Inventory includes materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. Inventory consisted of the following as of the dates indicated:

	September 30,		December 31,
	2009		2008
	(in thousands)
Materials and supplies	$	17,592	$	15,933
Oil in pipelines		7,001		8,865
Total inventory	$	24,593	$	24,798

     During the three and nine months ended September 30, 2009, EAC recorded a lower of cost or market adjustment of approximately $0.7 million and $6.5 million, respectively, to the carrying value of pipe and other tubular inventory whose market value had declined below cost, which are included in “Other operating expense” in the accompanying Consolidated Statements of Operations.

9

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 5. Proved Properties

     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:

	September 30,		December 31,
	2009		2008
	(in thousands)
Proved leasehold costs	$	1,775,500	$	1,421,859
Wells and related equipment — Completed		2,336,717		1,943,275
Wells and related equipment — In process		34,664		173,325
Total proved properties	$	4,146,881	$	3,538,459

     EAC follows FSP No. 19-1 “Accounting for Suspended Well Costs” (“FSP 19-1” or ASC 932), which permits the continued capitalization of exploratory well costs beyond one year if the well found a sufficient quantity of reserves to justify its completion as a producing well or the entity is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The following table reflects the net changes in capitalized exploratory well costs during the periods indicated, and does not include amounts that were capitalized and subsequently expensed in the same period.

	Three Months Ended			Nine Months Ended
	September 30, 2009			September 30, 2009
	(in thousands)
Beginning balance	$	28,948		$	18,220
Additions to capitalized exploratory well costs pending the determination of proved reserves		1,456			4,588
Reclassification to proved property and equipment based on the determination of proved reserves		(20,201	)		(15,054	)
Capitalized exploratory well costs charged to expense		(5,614	)		(3,165	)
Total	$	4,589		$	4,589

     The following table provides an aging, as of the dates indicated, of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year:

	September 30,		December 31,
	2009		2008
	(in thousands, except project counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	2,755	$	18,220
More than one year		1,834		—
Total	$	4,589	$	18,220
Number of projects with exploratory well costs that have been suspended for a period of greater than one year		1		0

     The following table provides an aging of gross capitalized costs of exploration projects with exploratory well costs which have been suspended for more than one year as of September 30, 2009:

	Total		2009		2008
	(in thousands)
Tuscaloosa Marine Shale	$	1,834	$	1,834	$	—

10

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 6. Fair Value Measurements

     The following table sets forth EAC’s book value and estimated fair value of financial instruments as of the dates indicated:

	September 30, 2009				December 31, 2008
	Book		Fair		Book		Fair
	Value		Value		Value		Value
	(in thousands)
Assets:
Cash and cash equivalents	$	6,683	$	6,683	$	2,039	$	2,039
Accounts receivable, net		104,980		104,980		117,995		117,995
Plugging bond		862		1,059		824		1,202
Bell Creek escrow		9,260		9,260		9,229		9,241
Commodity derivative contracts		99,668		99,668		387,841		387,841
Long-term receivables, net		61,779		61,779		71,986		71,986
Liabilities:
Accounts payable		10,412		10,412		10,017		10,017
6.25% Senior Subordinated Notes		150,000		140,250		150,000		101,250
6.0% Senior Subordinated Notes		296,421		276,000		296,040		194,250
9.5% Senior Subordinated Notes		208,228		234,000		—		—
7.25% Senior Subordinated Notes		148,847		140,250		148,771		94,500
Revolving credit facilities		440,000		440,000		725,000		725,000
Commodity derivative contracts		29,230		29,230		229		229
Deferred premiums on commodity derivative contracts		43,228		43,228		67,610		67,610
Interest rate swaps		4,150		4,150		4,559		4,559

     The book values of cash and cash equivalents, accounts receivable, net, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of long-term receivables, net, approximates fair value as it is net of amounts deemed to be uncollectible and bears interest at market rates. The plugging bond and Bell Creek escrow are included in “Other assets” in the accompanying Consolidated Balance Sheets and are classified as “held to maturity” and therefore, are recorded at amortized cost, which was less than fair value. The fair values of the plugging bond, Bell Creek escrow, and senior subordinated notes were determined using open market quotes. The difference between book value and fair value of the senior subordinated notes represents the premium or discount on that date. The book value of the revolving credit facilities approximates fair value as the interest rate is variable. EAC’s and ENP’s credit risk have not changed materially from the date the revolving credit facilities were entered into. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets. Deferred premiums on commodity derivative contracts were recorded at their net present value at the time the contracts were entered into and EAC accretes that value to the eventual settlement price by recording interest expense each period.

Derivative Policy

     EAC uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production. These arrangements are structured to reduce EAC’s exposure to commodity price decreases, but they can also limit the benefit EAC might otherwise receive from commodity price increases. EAC’s risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. EAC also uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.

     EAC applies the provisions of SFAS 133 (ASC 815), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be

11

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.

     EAC has elected to designate its outstanding interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

     EAC has not elected to designate its current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

Commodity Derivative Contracts

     EAC manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.

     From time to time, EAC enters into floor spreads. In a floor spread, EAC purchases puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables EAC to achieve some downside protection for a portion of its production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then EAC has protection against commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, EAC wished to protect downside price exposure at the higher price. In order to do this, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, EAC had purchased two oil put options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in EAC owning one oil put option for 2,000 Bbls/D at $75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.

12

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following tables summarize EAC’s open commodity derivative contracts as of September 30, 2009:

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(in thousands)
Oct. - Dec. 2009 (a)													$	10,941
		3,130	$	110.00		440	$	97.75		1,000	$	68.70
2010														16,086
		880		80.00		2,940		90.57		—		—
		5,500		73.47		3,000		74.13		3,885		77.79
		8,385		62.83		500		65.60		1,750		64.08
		1,000		56.00		—		—		1,000		59.70
2011														27,767
		1,880		80.00		1,440		95.41		325		80.00
		2,500		70.00		—		—		1,060		78.42
		4,385		65.00		—		—		250		69.65
2012														4,628
		750		70.00		500		82.05		835		81.19
		2,135		65.00		250		79.25		1,300		76.54
													$	59,422

(a) In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.

Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted		Asset
	Daily		Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
Oct. - Dec. 2009													$	4,829
		3,800	$	8.20		3,800	$	9.83		—	$	—
		3,800		7.20		5,000		7.45		—		—
		6,800		6.57		15,000		6.63		—		—
		15,000		5.64		—		—		—		—
Jan. - June 2010														4,434
		3,800		8.20		3,800		9.58		25,452		6.46
		4,698		7.26		—		—		20,550		5.23
July - Dec. 2010														3,005
		3,800		8.20		3,800		9.58		—		—
		4,698		7.26		10,000		6.25		25,452		6.46
		10,000		5.13		—		—		550		5.86
2011														212
		3,398		6.31		—		—		27,952		6.48
		—		—		—		—		550		5.86
2012														(1,463	)
		898		6.76		—		—		25,452		6.47
		—		—		—		—		550		5.86
													$	11,017

     As of September 30, 2009, EAC had $43.2 million of deferred premiums payable, of which $26.0 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $17.2 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from October 2009 to January 2013.

13

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     Counterparty Risk.At September 30, 2009, EAC had committed 10 percent or greater (in terms of fair market value) of either its oil or natural gas derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed
BNP Paribas		33	%		23	%
Calyon		15	%		43	%
JP Morgan		14	%		6	%
RBC		17	%		2	%
Wachovia Bank		14	%		26	%

     In order to mitigate the credit risk of financial instruments, EAC enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and EAC. Instead of treating each derivative financial transaction between the counterparty and EAC separately, the master netting agreement enables the counterparty and EAC to aggregate all financial trades and treat them as a single agreement. This arrangement benefits EAC in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by EAC; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces EAC’s credit exposure to a given counterparty in the event of close-out. EAC’s accounting policy is to not offset fair value amounts for derivative instruments.

Interest Rate Swaps

     ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit facility to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swaps as of September 30, 2009, all of which were entered into with Bank of America, N.A.:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
Oct. 2009 - Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
Oct. 2009 - Jan. 2011		25,000		2.9650	%	1-month LIBOR
Oct. 2009 - Jan. 2011		25,000		2.9613	%	1-month LIBOR
Oct. 2009 - Mar. 2012		50,000		2.4200	%	1-month LIBOR

     The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred loss recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet due to the fluctuation of interest rates.

Current Period Impact

     EAC recognizes derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:

14

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Ineffectiveness	$	18		$	(6	)	$	(16	)	$	(349	)
Mark-to-market loss (gain)		576			(276,932	)		281,569			(11,884	)
Premium amortization		6,838			14,773			91,557			47,579
Settlements		(20,688	)		22,730			(373,851	)		46,747
Total derivative fair value loss (gain)	$	(13,256	)	$	(239,435	)	$	(741	)	$	82,093

     In March 2009, EAC elected to monetize certain of its 2009 oil derivative contracts and received proceeds of approximately $190.4 million from these settlements, which were used to reduce outstanding borrowings under EAC’s revolving credit facility.

Accumulated Other Comprehensive Loss

     At September 30, 2009 and December 31, 2008, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheet consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $1.2 million and $1.7 million, respectively. During the twelve months ending September 30, 2010, EAC expects to reclassify $3.5 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense.

Tabular Disclosures of Fair Value Measurements

     The following table summarizes the fair value of EAC’s derivative contracts as of the dates indicated (in thousands):

	Asset Derivatives						Liability Derivatives
	September 30, 2009			December 31, 2008			September 30, 2009			December 31, 2008
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet			Balance Sheet
	Location	Value		Location	Value		Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments under SFAS 133 (ASC 815)
Commodity derivative contracts	Derivatives - current	$	51,974	Derivatives - current	$	349,344	Derivatives - current	$	16,532	Derivatives - current	$	—
Commodity derivative contracts	Derivatives - noncurrent		47,694	Derivatives - noncurrent		38,497	Derivatives - noncurrent		12,698	Derivatives - noncurrent		229
Total derivatives not designated as hedging instruments under SFAS 133 (ASC 815)		$	99,668		$	387,841		$	29,230		$	229
Derivatives designated as hedging instruments under SFAS 133 (ASC 815)
Interest rate swaps	Derivatives - current	$	—	Derivatives - current	$	—	Derivatives - current	$	3,470	Derivatives - current	$	1,297
Interest rate swaps	Derivatives - noncurrent		—	Derivatives - noncurrent		—	Derivatives - noncurrent		680	Derivatives-noncurrent		3,262
Total derivatives designated as hedging instruments under SFAS 133 (ASC 815)		$	—		$	—		$	4,150		$	4,559
Total derivatives		$	99,668		$	387,841		$	33,380		$	4,788

     The following table summarizes the effect of derivative instruments not designated as hedges under SFAS 133 (ASC 815) on the Consolidated Statements of Operations for the periods indicated (in thousands):

		Amount of Loss (Gain) Recognized In Income
Derivatives Not Designated as	Location of Loss	Three Months Ended September 30,						Nine Months Ended September 30,
Hedges Under SFAS 133 (ASC 815)	Recognized In Income	2009			2008			2009			2008
Commodity derivative contracts	Derivative fair value loss (gain)	$	(13,274	)	$	(239,429	)	$	(725	)	$	82,442

15

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following tables summarize the effect of derivative instruments designated as hedges under SFAS 133 (ASC 815) on the Consolidated Statements of Operations for the periods indicated (in thousands):

						Amount of Loss
	Amount of Loss					Reclassified from					Amount of Loss (Gain)
	Recognized in Accumulated OCI				Location of Loss	Accumulated OCI into					Recognized In Income
	(Effective Portion)				(Gain) Reclassified	Income (Effective Portion)					as Ineffective
Derivatives Designated as	Three months ended				from Accumulated	Three months ended				Location of Loss (Gain)	Three months ended
Hedges Under	September 30,				OCI into Income	September 30,				Recognized in Income	September 30,
SFAS 133 (ASC 815)	2009		2008		(Effective Portion)	2009		2008		as Ineffective	2009		2008
Interest rate swaps	$	725	$	381	Interest expense	$	983	$	117	Derivative fair value loss (gain)	$	18	$	(6	)
						Amount of Loss
	Amount of Loss					Reclassified from					Amount of Gain
	Recognized in Accumulated OCI				Location of Loss	Accumulated OCI into					Recognized In Income
	(Effective Portion)				(Gain) Reclassified	Income (Effective Portion)					as Ineffective
Derivatives Designated as	Nine months ended				from Accumulated	Nine months ended				Location of Gain	Nine months ended
Hedges Under	September 30,				OCI into Income	September 30,				Recognized in Income	September 30,
SFAS 133 (ASC 815)	2009		2008		(Effective Portion)	2009		2008		as Ineffective	2009		2008
Interest rate swaps	$	2,214	$	1,142	Interest expense	$	2,786	$	224	Derivative fair value gain	$	16	$	349
Commodity derivative contracts		—		—	Oil and natural gas revenues		—		2,857			—		—
Total	$	2,214	$	1,142		$	2,786	$	3,081		$	16	$	349

Fair Value Hierarchy

     As discussed in “Note 2. Basis of Presentation,” EAC adopted FSP FAS 157-2 (ASC 820-10) on January 1, 2009 and SFAS 157 (ASC 820-10) on January 1, 2008. SFAS 157 (ASC 820-10) establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 (ASC 820-10) are as follows:

• Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

• Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

• Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s assets and liabilities that are accounted for at fair value on a recurring basis:

• Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income-based and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.

• Level 3 — EAC’s oil and natural gas calls, puts, and short puts are average value options, which are not exchange-traded contracts. Settlement is determined by the average underlying price over a predetermined period of time. EAC uses both observable and unobservable inputs in a Black-Scholes valuation model to determine fair value. Accordingly, these derivative instruments are classified within the Level 3 valuation hierarchy. The observable inputs of EAC’s valuation model include: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; and (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract. The unobservable input of EAC’s valuation model is volatility. The implied volatilities for EAC’s calls, puts, and short puts with comparable strike prices are based on the settlement values from certain exchange-traded contracts. The implied volatilities for calls, puts, and short puts where there are no exchange-traded contracts with the same strike price are extrapolated from exchange-traded implied volatilities by an independent party.

     EAC adjusts the valuations from the valuation model for nonperformance risk, using management’s estimate of the counterparty’s credit quality for asset positions and EAC’s credit quality for liability positions. EAC uses the multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. EAC considers the impact of netting and offset

16

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

provisions in the agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. There have been no changes in the valuation techniques used to measure the fair value of EAC’s oil and natural gas calls, puts, or short puts during 2009.

     The following table sets forth EAC’s assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
	Asset (Liability) at			Identical Assets		Observable Inputs			Unobservable Inputs
Description	September 30, 2009			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	(7,860	)	$	—	$	(7,860	)	$	—
Oil derivative contracts — floors and caps		67,282			—		—			67,282
Natural gas derivative contracts — swaps		(387	)		—		(387	)		—
Natural gas derivative contracts — floors and caps		11,404			—		—			11,404
Interest rate swaps		(4,150	)		—		(4,150	)		—
Total	$	66,289		$	—	$	(12,397	)	$	78,686

     The following table summarizes the changes in the fair value of EAC’s Level 3 assets and liabilities for the nine months ended September 30, 2009:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts -			Derivative Contracts -
	Floors and Caps			Floors and Caps			Total
	(in thousands)
Balance at January 1, 2009	$	337,335		$	12,741		$	350,076
Total gains (losses):
Included in earnings		30,329			20,882			51,211
Purchases, issuances, and settlements		(300,382	)		(22,219	)		(322,601	)
Balance at September 30, 2009	$	67,282		$	11,404		$	78,686
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	30,329		$	20,882		$	51,211

     Since EAC does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

     All fair values have been adjusted for nonperformance risk resulting in a reduction of the net commodity derivative asset of approximately $0.5 million as of September 30, 2009. For commodity derivative contracts which are in an asset position, EAC uses the counterparty’s credit default swap rating. For commodity derivative contracts which are in a liability position, EAC uses the average credit default swap rating of its peer companies as EAC does not have its own credit default swap rating.

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s assets and liabilities that are accounted for at fair value on a nonrecurring basis:

• Level 3—Fair values of asset retirement obligations are determined using discounted cash flow methodologies based on inputs, such as plugging costs and reserve lives, which are not readily available in public markets. See “Note 7. Asset Retirement Obligations” for additional discussion of EAC’s asset retirement obligations.

17

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table sets forth EAC’s assets and liabilities that were measured at fair value on a nonrecurring basis as of September 30, 2009:

			Fair Value Measurements Using
			Quoted Prices in
			Active Markets for		Significant Other		Significant
	Liability at		Identical Assets		Observable Inputs		Unobservable Inputs		Total Gains
Description	September 30, 2009		(Level 1)		(Level 2)		(Level 3)		(Losses)
	(in thousands)
Asset retirement obligations	$	3,775	$	—	$	—	$	3,775	$	—

Note 7. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in EAC’s asset retirement obligations for the nine months ended September 30, 2009 (in thousands):

Future abandonment liability at January 1, 2009	$	49,569
Wells drilled		283
Acquisition of properties		3,492
Disposition of properties		(220	)
Accretion of discount		1,761
Plugging and abandonment costs incurred		(1,223	)
Revision of previous estimates		49
Future abandonment liability at September 30, 2009	$	53,711

     As of September 30, 2009, $51.7 million of EAC’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $2.0 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.7 million of the future abandonment liability represents the estimated cost for decommissioning ENP’s Elk Basin natural gas processing plant.

     As of September 30, 2009 and December 31, 2008, EAC held $9.3 million and $9.2 million, respectively, in escrow, which is to be released only for reimbursement of actual plugging and abandonment costs incurred on its Bell Creek properties. These amounts are included in “Other assets” in the accompanying Consolidated Balance Sheets.

Note 8. Long-Term Debt

     Long-term debt consisted of the following as of the dates indicated:

	Maturity		September 30,		December 31,
	Date		2009		2008
			(in thousands)
Revolving credit facilities		3/7/2012	$	440,000	$	725,000
6.25% Senior Subordinated Notes		4/15/2014		150,000		150,000
6.0% Senior Subordinated Notes, net of unamortized discount of $3,579 and $3,960, respectively		7/15/2015		296,421		296,040
9.5% Senior Subordinated Notes, net of unamortized discount of $16,772 and zero, respectively		5/1/2016		208,228		—
7.25% Senior Subordinated Notes, net of unamortized discount of $1,153 and $1,229, respectively		12/1/2017		148,847		148,771
Total			$	1,243,496	$	1,319,811

18

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Encore Acquisition Company Credit Agreement

     EAC is a party to a five-year amended and restated credit agreement dated March 7, 2007 (as amended, the “EAC Credit Agreement”). The EAC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, EAC amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement. The EAC Credit Agreement provides for revolving credit loans to be made to EAC from time to time and letters of credit to be issued from time to time for the account of EAC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. In March 2009, the borrowing base of the EAC Credit Agreement was reaffirmed at $1.1 billion before a reduction of $200 million solely as a result of the monetization of certain of EAC’s 2009 oil derivative contracts during the first quarter of 2009. In April 2009, the borrowing base of the EAC Credit Agreement was reduced by $75 million as a result of EAC’s issuance of senior subordinated notes. As of September 30, 2009, the borrowing base was $825 million and there were $180 million of outstanding borrowings, $0.3 million of outstanding letters of credit, and $644.7 million of borrowing capacity under the EAC Credit Agreement.

     EAC incurs a commitment fee on the unused portion of the EAC Credit Agreement determined based on the ratio of outstanding borrowings under the EAC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the commitment fee percentage under the EAC Credit Agreement:

	Commitment
Ratio of Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     Obligations under the EAC Credit Agreement are secured by a first-priority security interest in substantially all of EAC’s restricted subsidiaries’ proved oil and natural gas reserves and in EAC’s equity interests in its restricted subsidiaries. In addition, obligations under the EAC Credit Agreement are guaranteed by EAC’s restricted subsidiaries.

     Loans under the EAC Credit Agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under the EAC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the EAC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.500	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

     The EAC Credit Agreement contains covenants including, among others, the following:

• a prohibition against incurring debt, subject to permitted exceptions;

• a prohibition against paying dividends or making distributions, purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

19

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

• a restriction on creating liens on the assets of EAC and its restricted subsidiaries, subject to permitted exceptions;

• restrictions on merging and selling assets outside the ordinary course of business;

• restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that EAC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and

• a requirement that EAC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.

     As of September 30, 2009, EAC was in compliance with all covenants of the EAC Credit Agreement.

     The EAC Credit Agreement contains customary events of default including, among others, the following:

• failure to pay principal on any loan when due;

• failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

• failure to observe or perform covenants and agreements contained in the EAC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

• failure to make a payment when due on any other debt in a principal amount equal to or greater than $15 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

• the commencement of liquidation, reorganization, or similar proceedings with respect to EAC or any guarantor under bankruptcy or insolvency law, or the failure of EAC or any guarantor generally to pay its debts as they become due;

• the entry of one or more judgments in excess of $15 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

• the occurrence of certain ERISA events involving an amount in excess of $15 million;

• there cease to exist liens covering at least 80 percent of the borrowing base properties; or

• the occurrence of a change in control.

     If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.

Encore Energy Partners Operating LLC Credit Agreement

     Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. Effective August 11, 2009, OLLC amended the OLLC Credit Agreement to, among other things, (1) increase the borrowing base from $240 million to $375 million, (2) increase the aggregate commitments of the lenders from $300 million to $475 million, and (3) increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As of September 30, 2009, the borrowing base was $375 million and there were $260 million of outstanding borrowings and $115 million of borrowing capacity under the OLLC Credit Agreement.

     OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.

     Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, Obligations under

20

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.

     Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) amount outstanding in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under the OLLC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the OLLC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		2.250	%		1.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.500	%		1.500	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.750	%		1.750	%
Greater than or equal to .90 to 1		3.000	%		2.000	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants including, among others, the following:

• a prohibition against incurring debt, subject to permitted exceptions;

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

• restrictions on merging and selling assets outside the ordinary course of business;

• restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and

• a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0.

     As of September 30, 2009, ENP and OLLC were in compliance with all covenants of the OLLC Credit Agreement.

     The OLLC Credit Agreement contains customary events of default including, among others, the following:

• failure to pay principal on any loan when due;

• failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

• failure to observe or perform covenants and agreements contained in the OLLC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

• failure to make a payment when due on any other debt in a principal amount equal to or greater than $3 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

• the commencement of liquidation, reorganization, or similar proceedings with respect to OLLC or any guarantor under bankruptcy or insolvency law, or the failure of OLLC or any guarantor generally to pay its debts as they become due;

21

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

• the entry of one or more judgments in excess of $3 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

• the occurrence of certain ERISA events involving an amount in excess of $3 million;

• there cease to exist liens covering at least 80 percent of the borrowing base properties; or

• the occurrence of a change in control.

     If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

9.50% Senior Subordinated Notes due 2016 (the “9.5% Notes”)

     In April 2009, EAC issued $225 million of its 9.5% Notes at 92.228 percent of par value. EAC used the net proceeds of approximately $202.5 million, after deducting the underwriters’ discounts and commissions of $4.5 million, in the aggregate, and offering expenses of approximately $0.6 million. EAC used the net proceeds to reduce outstanding borrowings under the EAC Credit Agreement. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

Note 9. Stockholders’ Equity

Stock Repurchase Program

     In October 2008, EAC announced that its Board of Directors (the “Board”) approved a share repurchase program authorizing EAC to repurchase up to $40 million of its common stock. As of September 30, 2009, EAC had repurchased and retired 620,265 shares of its outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the three and nine months ended September 30, 2009, EAC did not repurchase any shares of its outstanding common stock under the share repurchase program. As of September 30, 2009, approximately $22.8 million of EAC’s common stock remained authorized for repurchase.

Stock Option Exercises and Restricted Stock Vestings

     During the three and nine months ended September 30, 2009, certain employees exercised 1,621 options and 23,105 options, respectively, for which EAC received proceeds of approximately $49 thousand and $0.5 million, respectively. During the nine months ended September 30, 2009, certain employees elected to satisfy minimum tax withholding obligations in conjunction with the vesting of restricted stock by directing EAC to withhold 111,819 shares of common stock, which are accounted for as treasury stock until they are formally retired.

Issuance of EAC Common Stock

     In September 2009, EAC issued 2,750,000 shares of common stock under its shelf registration statement at a price to the public of $37.40 per common share. EAC used the net proceeds of approximately $100.7 million, after deducting the underwriters’ discounts and commissions of $2.0 million, in the aggregate, and offering costs of approximately $0.1 million, to reduce outstanding borrowings under the EAC Credit Facility.

Issuance of ENP Common Units

     In May 2009, ENP issued 2,760,000 common units at a price to the public of $15.60 per common unit. As a result, EAC’s partnership percentage of ENP’s common units decreased from approximately 63 percent to approximately 58 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $31.2 million and $9.3 million, respectively, to recognize the net proceeds from the issuance of ENP’s common units.

     In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. As a result, EAC’s partnership percentage of ENP’s common units decreased from approximately 58 percent to its current partnership of approximately 46 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $109.0 million and $20.4 million, respectively, to recognize the net proceeds from the issuance of ENP’s common units.

     The following table summarizes EAC’s change of ownership of ENP since December 31, 2008:

	Common Units Owned						EAC %			GP Units Owned		EAC % of
Date	EAC		Others		Total		of Common Units			by EAC		All Units
12/31/2008		20,924,055		12,153,555		33,077,610		63.3	%		504,851		63.8	%
Equity Offering		—		2,760,000		2,760,000
5/22/2009		20,924,055		14,913,555		35,837,610		58.4	%		504,851		59.0	%
Equity Offering		—		9,430,000		9,430,000
7/22/2009		20,924,055		24,343,555		45,267,610		46.2	%		504,851		46.8	%

22

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 10. Income Taxes

     The components of income tax benefit (provision) were as follows for the periods indicated:

	Nine months ended
	September 30,
	2009			2008
	(in thousands)
Federal:
Current	$	2,683		$	(6,693	)
Deferred		25,117			(104,436	)
Total federal		27,800			(111,129	)
State, net of federal benefit:
Current		(3,332	)		(2,249	)
Deferred		786			(5,217	)
Total state		(2,546	)		(7,466	)
Income tax benefit (provision)	$	25,254		$	(118,595	)

     The following table reconciles income tax benefit (provision) with income tax at the Federal statutory rate for the periods indicated:

	Nine months ended
	September 30,
	2009			2008
	(in thousands)
Income (loss) before income taxes	$	(94,453	)	$	336,600
Income taxes at the Federal statutory rate	$	33,059		$	(117,810	)
State income taxes, net of federal benefit		(2,546	)		(7,466	)
Tax on income attributable to noncontrolling interest		(3,384	)		5,669
2008 provision to return adjustment		(1,735	)		872
Permanent and other		(140	)		140
Income tax benefit (provision)	$	25,254		$	(118,595	)

     As of September 30, 2009 and December 31, 2008, all of EAC’s tax positions met the “more-likely-than-not” threshold prescribed by FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (ASC 740, 805-740, and 835-10). As a result, no additional tax expense, interest, or penalties have been accrued. EAC includes interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. During the nine months ended September 30, 2009 and 2008, EAC recorded only a nominal amount of interest and penalties on certain tax positions.

Note 11. Earnings Per Share

     As discussed in “Note 2. Basis of Presentation,” EAC adopted FSP EITF 03-6-1 (ASC 260-10) on January 1, 2009, and all periods prior to adoption have been restated to calculate EPS in accordance with this pronouncement. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all earnings for the period had been distributed. A participating security is any security that contains nonforfeitable rights to dividends or dividend equivalents paid to common stockholders. For purposes of calculating EPS, unvested restricted stock awards are considered participating securities. EPS is calculated by dividing the common stockholders’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average shares outstanding. The adoption of EITF 03-6-1 (ASC 260-10) reduced EAC’s basic EPS by $0.07 for the three and nine months ended September 30, 2008 and reduced EAC’s diluted EPS by $0.03 for the three and nine months ended September 30, 2008.

23

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table reflects the allocation of net income (loss) to EAC’s common stockholders and EPS computations for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands, except per share amounts)
Basic Earnings Per Share
Numerator:
Undistributed net income (loss) — attributable to EAC	$	(4,999	)	$	206,307		$	(59,530	)	$	201,807
Participation rights of unvested restricted stock in undistributed earnings (a)		—			(3,737	)		—			(3,642	)
Basic undistributed net income (loss) — attributable to EAC common shares	$	(4,999	)	$	202,570		$	(59,530	)	$	198,165
Denominator:
Basic weighted average shares outstanding		52,349			52,258			51,964			52,466
Basic EPS — attributable to EAC common shares	$	(0.10	)	$	3.88		$	(1.15	)	$	3.78
Diluted Earnings Per Share
Numerator:
Basic undistributed net income (loss) — attributable to EAC common shares	$	(4,999	)	$	206,307		$	(59,530	)	$	201,807
Participation rights of unvested restricted stock in undistributed earnings (a)		—			(3,631	)		—			(3,535	)
Incremental noncontrolling interest from assumed conversion of ENP MIUs		—			(3,143	)		—			(3,461	)
Basic undistributed net income (loss) — attributable to EAC common shares	$	(4,999	)	$	199,533		$	(59,530	)	$	194,811
Denominator:
Basic weighted average shares outstanding		52,349			52,258			51,964			52,466
Effect of dilutive options (b)		—			721			—			668
Diluted weighted average shares outstanding		52,349			52,979			51,964			53,134
Diluted EPS — attributable to EAC common shares	$	(0.10	)	$	3.77		$	(1.15	)	$	3.67

(a)	Unvested restricted stock has no contractual obligation to absorb losses of EAC. Therefore, for the three and nine months ended September 30, 2009, 923,122 shares of restricted stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. Please read “Note 12. Incentive Stock Plans” for additional discussion of restricted stock.
(b)	For the three and nine months ended September 30, 2009, options to purchase 1,730,762 shares of common stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. Please read “Note 12. Incentive Stock Plans” for additional discussion of stock options.

Note 12. Incentive Stock Plans

     In May 2008, EAC’s stockholders approved the 2008 Incentive Stock Plan (the “2008 Plan”). No additional awards will be granted under EAC’s 2000 Incentive Stock Plan (the “2000 Plan”) and any outstanding awards granted under the 2000 Plan will remain outstanding in accordance with their terms. The purpose of the 2008 Plan is to attract, motivate, and retain selected employees of EAC and to provide EAC with the ability to provide incentives more directly linked to the profitability of the business and increases in stockholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the 2008 Plan. The 2008 Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Board. The Board also has a Special Stock Award Committee whose sole member is Jon S. Brumley, EAC’s Chief Executive Officer and President. The Special Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual basis to non-executive employees at its discretion.

     The total number of shares of EAC’s common stock reserved for issuance pursuant to the 2008 Plan is 2,400,000, of which 1,600,000 are available for grants of “full value” stock awards, such as restricted stock or stock units. As of September 30, 2009, there were 1,715,900 shares available for issuance under the 2008 Plan, of which 1,181,143 are available for grants of “full value” stock awards. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax withholding, shares subject to options or other awards that expire or are forfeited, and restricted shares that are forfeited will again become available for issuance under the 2008 Plan.

     The 2008 Plan contains the following individual limits:

• an employee may not be granted awards covering or relating to more than 300,000 shares of common stock during any calendar year;

24

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

• a non-employee director may not be granted awards covering or relating to more than 20,000 shares of common stock during any calendar year; and

• an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having grant date fair value in excess of $5.0 million.

     During the nine months ended September 30, 2009 and 2008, EAC recorded non-cash stock-based compensation expense related to its incentive stock plans of $9.5 million and $6.5 million, respectively, which was allocated to LOE and general and administrative expense in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees’ cash compensation. During the nine months ended September 30, 2009 and 2008, EAC also capitalized $1.8 million and $1.7 million, respectively, of non-cash stock-based compensation expense related to its incentive stock plans as a component of “Proved properties” in the accompanying Consolidated Balance Sheets. During the nine months ended September 30, 2009 and 2008, EAC recognized income tax benefits related to its incentive stock plans of $3.5 million and $2.4 million, respectively.

     Please read “Note 17. ENP” for a discussion of ENP’s unit-based compensation plans.

Stock Options

     All options have a strike price equal to the fair market value of EAC’s common stock on the grant date, have a ten-year life, and vest over a three-year period. The fair value of options granted during the nine months ended September 30, 2009 and 2008 was estimated on the grant date using a Black-Scholes option valuation model based on the following assumptions:

	Nine months ended September 30,
	2009			2008
Expected volatility		51.9	%		33.7	%
Expected dividend yield		0.0	%		0.0	%
Expected term (in years)		6.25			6.25
Risk-free interest rate		2.1	%		3.0	%
Weighted-average fair value per share	$	15.81		$	13.15

     The expected volatility was based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the options. EAC determined the expected term of the options based on an analysis of historical exercise and forfeiture behavior as well as expectations about future behavior. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the options.

     The following table summarizes the changes in EAC’s outstanding options for the nine months ended September 30, 2009:

						Weighted
				Weighted		Average		Aggregate
	Number of			Average		Remaining		Intrinsic
	Options			Strike Price		Contractual Term		Value
								(in thousands)
Outstanding at January 1, 2009		1,497,413		$	18.02
Granted		269,417			30.55
Forfeited or expired		(12,963	)		30.91
Exercised		(23,105	)		20.17
Outstanding at September 30, 2009		1,730,762			19.85		5.1	$	30,377
Exercisable at September 30, 2009		1,298,056			16.23		3.9		27,477

     The total intrinsic value of options exercised during the nine months ended September 30, 2009 and 2008 was $0.3 million and $1.6 million, respectively. During the nine months ended September 30, 2009 and 2008, EAC received proceeds from the exercise of stock options of $0.5 million and $0.5 million, respectively. During the nine months ended September 30, 2009 and 2008, EAC recognized income tax benefits related to stock options of $38 thousand and $0.5 million, respectively. At September 30, 2009, EAC had $2.4 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 2.1 years.

25

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Restricted Stock

     Restricted stock awards vest over varying periods from one to five years, subject to performance-based vesting for certain members of senior management. During the nine months ended September 30, 2009, EAC recognized expense related to restricted stock of $7.3 million and recognized an income tax provision related to the vesting of restricted stock of $0.4 million. During the nine months ended September 30, 2008, EAC recognized expense related to restricted stock of $5.5 million and recognized an income tax benefit related to the vesting of restricted stock of $0.8 million. The following table summarizes the changes in EAC’s unvested restricted stock awards for the nine months ended September 30, 2009:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2009		938,407		$	30.67
Granted		412,449			30.52
Vested		(408,478	)		29.25
Forfeited		(19,256	)		30.26
Outstanding at June 30, 2009		923,122			31.20

     As of September 30, 2009, there were 704,102 shares of unvested restricted stock, 188,837 shares of which were granted during 2009, in which the vesting is dependent only on the passage of time and continued employment. Additionally, as of September 30, 2009, there were 219,020 shares of unvested restricted stock, all of which were granted during 2009, in which the vesting is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures.

     None of EAC’s unvested restricted stock awards are subject to variable accounting. During the nine months ended September 30, 2009 and 2008, there were 408,478 shares and 235,086 shares, respectively, of restricted stock that vested for which certain employees elected to satisfy minimum tax withholding obligations related thereto by directing EAC to withhold 111,819 shares and 28,193 shares of common stock, respectively. EAC accounts for these shares as treasury stock until they are formally retired and have been reflected as such in the accompanying consolidated financial statements. The total fair value of restricted stock that vested during the nine months ended September 30, 2009 and 2008 was $11.0 million and $8.2 million, respectively. As of September 30, 2009, EAC had $10.6 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 2.9 years.

Note 13. Comprehensive Income (Loss)

     The components of comprehensive income (loss), net of tax, were as follows for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Consolidated net income (loss)	$	(1,776	)	$	237,393		$	(69,199	)	$	218,005
Amortization of deferred loss on commodity derivative contracts		—			—			—			1,786
Change in deferred hedge loss on interest rate swaps		(343	)		(264	)		89			153
Consolidated comprehensive income (loss)		(2,119	)		237,129			(69,110	)		219,944
Less: comprehensive loss (income) attributable to noncontrolling interest		(2,630	)		(30,901	)		10,144			(16,330	)
Comprehensive income (loss) attributable to EAC stockholders	$	(4,749	)	$	206,228		$	(58,966	)	$	203,614

Note 14. Financial Statements of Subsidiary Guarantors

     Certain of EAC’s wholly owned subsidiaries are subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. The following Condensed Consolidating Balance Sheets as of September 30, 2009 and December 31, 2008, Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) for the three and nine

26

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

months ended September 30, 2009 and 2008, and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2009 and 2008 present consolidating financial information for Encore Acquisition Company (the “Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. As of September 30, 2009, EAC’s guarantor subsidiaries were:

• EAP Properties, Inc.;

• EAP Operating, LLC;

• Encore Operating, L.P.;

• Encore Operating Louisiana, LLC;

• Greencore Pipeline Company LLC;

• Green Rock LLC; and

• Belle Aire LLC.

As of September 30, 2009, EAC’s non-guarantor subsidiaries were:

• ENP;

• OLLC;

• GP LLC;

• Encore Partners GP Holdings LLC;

• Encore Partners LP Holdings LLC;

• Encore Energy Partners Finance Corporation; and

• Encore Clear Fork Pipeline LLC.

     All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses between the Parent, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements. Prior period amounts have not been adjusted for ENP’s acquisitions from EAC. Please read “Note 17. ENP” for a discussion of transactions with ENP.

27

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
September 30, 2009
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	3,246		$	3,437		$	—		$	6,683
Other current assets		9,522		150,710			51,369			(4,618	)		206,983
Total current assets		9,522		153,956			54,806			(4,618	)		213,666
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,295,370			851,511			—			4,146,881
Unproved properties		—		104,870			61			—			104,931
Accumulated depletion, depreciation, and amortization		—		(787,211	)		(198,138	)		—			(985,349	)
		—		2,613,029			653,434			—			3,266,463
Other property and equipment, net		—		12,087			411			—			12,498
Other assets, net		15,462		166,180			39,551			(6	)		221,187
Investment in subsidiaries		2,869,292		(3,473	)		—			(2,865,819	)		—
Total assets	$	2,894,276	$	2,941,779		$	748,202		$	(2,870,443	)	$	3,713,814
LIABILITIES AND EQUITY
Current liabilities	$	85,661	$	160,997		$	33,567		$	(4,618	)	$	275,607
Deferred taxes		431,072		9			—			(6	)		431,075
Long-term debt		983,496		—			260,000			—			1,243,496
Other liabilities		—		76,238			18,633			—			94,871
Total liabilities		1,500,229		237,244			312,200			(4,624	)		2,045,049
Commitments and contingencies (see Note 15)
Total equity		1,394,047		2,704,535			436,002			(2,865,819	)		1,668,765
Total liabilities and equity	$	2,894,276	$	2,941,779		$	748,202		$	(2,870,443	)	$	3,713,814

28

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2008
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	607	$	813		$	619		$	—		$	2,039
Other current assets		29,004		421,392			90,797			(2,302	)		538,891
Total current assets		29,611		422,205			91,416			(2,302	)		540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,016,937			521,522			—			3,538,459
Unproved properties		—		124,272			67			—			124,339
Accumulated depletion, depreciation, and amortization		—		(670,991	)		(100,573	)		—			(771,564	)
		—		2,470,218			421,016			—			2,891,234
Other property and equipment, net		—		11,877			562			—			12,439
Other assets, net		12,846		129,482			46,264			—			188,592
Investment in subsidiaries		2,976,208		(12,865	)		—			(2,963,343	)		—
Total assets	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195
LIABILITIES AND EQUITY
Current liabilities	$	118,089	$	215,640		$	20,825		$	(2,302	)	$	352,252
Deferred taxes		416,637		—			278			—			416,915
Long-term debt		1,169,811		—			150,000			—			1,319,811
Other liabilities		—		48,000			12,969			—			60,969
Total liabilities		1,704,537		263,640			184,072			(2,302	)		2,149,947
Commitments and contingencies (see Note 15)
Total equity		1,314,128		2,757,277			375,186			(2,963,343	)		1,483,248
Total liabilities and equity	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195

29

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended September 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	117,669		$	35,280		$	—		$	152,949
Natural gas		—			26,518			5,650			—			32,168
Marketing		—			785			102			—			887
Total revenues		—			144,972			41,032			—			186,004
Expenses:
Production:
Lease operating		—			29,124			9,017			—			38,141
Production, ad valorem, and severance taxes		—			14,529			4,693			—			19,222
Depletion, depreciation, and amortization		—			58,169			14,458			—			72,627
Exploration		—			13,634			3,034			—			16,668
General and administrative		3,881			8,011			2,912			(1,534	)		13,270
Marketing		—			304			54			—			358
Derivative fair value gain		—			(8,434	)		(4,822	)		—			(13,256	)
Other operating		48			6,890			1,303			—			8,241
Total expenses		3,929			122,227			30,649			(1,534	)		155,271
Operating income (loss)		(3,929	)		22,745			10,383			1,534			30,733
Other income (expenses):
Interest		(18,936	)		—			(2,984	)		—			(21,920	)
Equity income from subsidiaries		29,184			2,162			—			(31,346	)		—
Other		(91	)		2,202			23			(1,534	)		600
Total other expenses		10,157			4,364			(2,961	)		(32,880	)		(21,320	)
Income (loss) before income taxes		6,228			27,109			7,422			(31,346	)		9,413
Income tax benefit (provision)		(11,228	)		1			38			—			(11,189	)
Consolidated net income (loss)		(5,000	)		27,110			7,460			(31,346	)		(1,776	)
Change in deferred hedge loss on interest rate swaps, net of tax		(37	)		—			(306	)		—			(343	)
Consolidated comprehensive income (loss)	$	(5,037	)	$	27,110		$	7,154		$	(31,346	)	$	(2,119	)

30

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Three Months Ended September 30, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	224,101		$	44,442		$	—		$	268,543
Natural gas		—			56,956			9,816			—			66,772
Marketing		—			718			1,445			—			2,163
Total revenues		—			281,775			55,703			—			337,478
Expenses:
Production:
Lease operating		—			40,124			8,842			—			48,966
Production, ad valorem, and severance taxes		—			27,609			5,741			—			33,350
Depletion, depreciation, and amortization		—			49,481			9,064			—			58,545
Impairment of long-lived assets		—			26,292			—			—			26,292
Exploration		—			13,335			46			—			13,381
General and administrative		4,723			9,050			2,600			(1,070	)		15,303
Marketing		—			539			1,316			—			1,855
Derivative fair value gain		—			(168,992	)		(70,443	)		—			(239,435	)
Other operating		41			3,688			344			—			4,073
Total expenses		4,764			1,126			(42,490	)		(1,070	)		(37,670	)
Operating income (loss)		(4,764	)		280,649			98,193			1,070			375,148
Other income (expenses):
Interest		(16,357	)		—			(1,767	)		—			(18,124	)
Equity income from subsidiaries		347,114			32,564			—			(379,678	)		—
Other		78			2,535			10			(1,070	)		1,553
Total other income (expenses)		330,835			35,099			(1,757	)		(380,748	)		(16,571	)
Income before income taxes		326,071			315,748			96,436			(379,678	)		358,577
Income tax benefit (provision)		(120,943	)		81			(322	)		—			(121,184	)
Consolidated net income		205,128			315,829			96,114			(379,678	)		237,393
Change in deferred hedge gain on interest rate swaps, net of tax		150			—			(414	)		—			(264	)
Consolidated comprehensive income	$	205,278		$	315,829		$	95,700		$	(379,678	)	$	237,129

31

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS
For the Nine Months Ended September 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	286,482		$	88,433		$	—		$	374,915
Natural gas		—			71,765			15,143			—			86,908
Marketing		—			1,627			381			—			2,008
Total revenues		—			359,874			103,957			—			463,831
Expenses:
Production:
Lease operating		—			91,697			31,120			—			122,817
Production, ad valorem, and severance taxes		—			36,488			11,586			—			48,074
Depletion, depreciation, and amortization		—			173,677			43,684			—			217,361
Exploration		—			40,727			3,074			—			43,801
General and administrative		13,595			21,860			9,138			(3,850	)		40,743
Marketing		—			1,367			245			—			1,612
Derivative fair value loss (gain)		—			(22,452	)		21,711			—			(741	)
Other operating		131			26,558			2,730			—			29,419
Total expenses		13,726			369,922			123,288			(3,850	)		503,086
Operating loss		(13,726	)		(10,048	)		(19,331	)		3,850			(39,255	)
Other income (expenses):
Interest		(49,458	)		—			(7,551	)		—			(57,009	)
Equity loss from subsidiaries		(21,460	)		(8,845	)		—			30,305			—
Other		(187	)		5,819			29			(3,850	)		1,811
Total other expenses		(71,105	)		(3,026	)		(7,522	)		26,455			(55,198	)
Loss before income taxes		(84,831	)		(13,074	)		(26,853	)		30,305			(94,453	)
Income tax benefit (provision)		25,299			118			(163	)		—			25,254
Consolidated net loss		(59,532	)		(12,956	)		(27,016	)		30,305			(69,199	)
Change in deferred hedge loss on interest rate swaps, net of tax		(253	)		—			342			—			89
Consolidated comprehensive loss	$	(59,785	)	$	(12,956	)	$	(26,674	)	$	30,305		$	(69,110	)

32

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2008
(in thousands)

				Guarantor		Non-Guarantor						Consolidated
	Parent			Subsidiaries		Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	647,223	$	128,778		$	—		$	776,001
Natural gas		—			154,347		28,626			—			182,973
Marketing		—			3,533		5,207			—			8,740
Total revenues		—			805,103		162,611			—			967,714
Expenses:
Production:
Lease operating		—			108,191		21,822			—			130,013
Production, ad valorem, and severance taxes		—			79,524		16,321			—			95,845
Depletion, depreciation, and amortization		—			131,715		27,399			—			159,114
Impairment of long-lived assets		—			26,292		—			—			26,292
Exploration		—			30,349		113			—			30,462
General and administrative		11,668			19,630		8,455			(3,204	)		36,549
Marketing		—			4,044		5,318			—			9,362
Derivative fair value loss		—			60,521		21,572			—			82,093
Other operating		124			8,655		1,026			—			9,805
Total expenses		11,792			468,921		102,026			(3,204	)		579,535
Operating income (loss)		(11,792	)		336,182		60,585			3,204			388,179
Other income (expenses):
Interest		(49,353	)		—		(5,316	)		—			(54,669	)
Equity income from subsidiaries		378,946			18,724		—			(397,670	)		—
Other		30			6,172		92			(3,204	)		3,090
Total other income (expenses)		329,623			24,896		(5,224	)		(400,874	)		(51,579	)
Income before income taxes		317,831			361,078		55,361			(397,670	)		336,600
Income tax provision		(118,435	)		—		(160	)		—			(118,595	)
Consolidated net income		199,396			361,078		55,201			(397,670	)		218,005
Amortization of deferred loss on commodity derivative contracts, net of tax		(1,071	)		2,857		—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(103	)		—		256			—			153
Consolidated comprehensive income	$	198,222		$	363,935	$	55,457		$	(397,670	)	$	219,944

33

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(42,913	)	$	583,522		$	92,544		$	—		$	633,153
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(391,975	)		(31,984	)		—			(423,959	)
Development of oil and natural gas properties		—			(286,113	)		(7,330	)		—			(293,443	)
Investments in subsidiaries		122,389			—			—			(122,389	)		—
Other		—			7,086			—			—			7,086
Net cash provided by (used in) investing activities		122,389			(671,002	)		(39,314	)		(122,389	)		(710,316	)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		387,029			—			203,061			—			590,090
Payments on long-term debt		(580,000	)		—			(96,000	)		—			(676,000	)
Proceeds from issuance of common stock, net of offering costs		100,690			—			—			—			100,690
Proceeds from ENP issuance of common units, net of offering costs		—			—			170,149			—			170,149
Net equity contributions (distributions)		—			147,600			(269,989	)		122,389			—
Other		12,198			(57,687	)		(57,633	)		—			(103,122	)
Net cash provided by (used in) financing activities		(80,083	)		89,913			(50,412	)		122,389			81,807
Increase (decrease) in cash and cash equivalents		(607	)		2,433			2,818			—			4,644
Cash and cash equivalents, beginning of period		607			813			619			—			2,039
Cash and cash equivalents, end of period	$	—		$	3,246		$	3,437		$	—		$	6,683

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by operating activities	$	289,310		$	141,580		$	98,097		$	—		$	528,987
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(116,679	)		(88	)		—			(116,767	)
Development of oil and natural gas properties		—			(369,396	)		(15,468	)		—			(384,864	)
Investments in subsidiaries		(259,105	)		—			—			259,105			—
Other		—			(34,161	)		(302	)		—			(34,463	)
Net cash used in investing activities		(259,105	)		(520,236	)		(15,858	)		259,105			(536,094	)
Cash flows from financing activities:
Repurchase of common stock		(50,000	)		—			—			—			(50,000	)
Proceeds from long-term debt, net of issuance costs		864,969			—			205,269			—			1,070,238
Payments on long-term debt		(861,500	)		—			(113,000	)		—			(974,500	)
Net equity contributions (distributions)		—			383,823			(124,718	)		(259,105	)		—
Other		17,303			(4,175	)		(49,636	)		—			(36,508	)
Net cash provided by (used in) financing activities		(29,228	)		379,648			(82,085	)		(259,105	)		9,230
Increase in cash and cash equivalents		977			992			154			—			2,123
Cash and cash equivalents, beginning of period		1			1,700			3			—			1,704
Cash and cash equivalents, end of period	$	978		$	2,692		$	157		$	—		$	3,827

34

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 15. Commitments and Contingencies

     EAC is a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these proceedings will have a material adverse effect on EAC’s business, financial condition, results of operations, or liquidity.

     Additionally, EAC has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, derivative contracts, capital and operating leases, and development commitments. Please read “Capital Commitments, Capital Resources, and Liquidity — Capital commitments — Contractual obligations” included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for a description of EAC’s contractual obligations as of September 30, 2009.

Note 16. Related Party Transactions

     During the nine months ended September 30, 2008, EAC received approximately $132.3 million, from affiliates of Tesoro Corporation (“Tesoro”) related to gross oil and gas production sold from wells operated by Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC. Mr. John V. Genova, a member of the Board, served as an employee of Tesoro until May 2008.

     Please read “Note 17. ENP” for a discussion of transactions with ENP.

Note 17. ENP

Administrative Services Agreement

     ENP does not have any employees. The employees supporting ENP’s operations are employees of EAC. Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by ENP. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

     Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. From April 1, 2008 to March 31, 2009, the administration fee was $1.88 per BOE of ENP’s production. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of ENP’s production. ENP also reimburses Encore Operating for actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator.

     The administrative fee will increase in the following circumstances:

• beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

• if ENP or one of its subsidiaries acquires additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of GP LLC upon the recommendation of its conflicts committee; and

• otherwise as agreed upon by Encore Operating and GP LLC, with the approval of the conflicts committee of the board of directors of GP LLC.

     ENP reimburses EAC for any state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP and its subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP and its subsidiaries would have incurred had they not been included in a combined group with EAC.

35

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Sales of Assets to ENP

     In August 2009, Encore Operating sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) to ENP for approximately $186.8 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement and proceeds from the issuance of ENP common units to the public. EAC used the proceeds from the sale of properties to fund a portion of the purchase price of its acquisitions from EXCO.

     In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.2 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement and proceeds from the issuance of ENP common units to the public. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

     In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

     In February 2008, Encore Operating sold certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota to ENP for approximately $125.0 million in cash and 6,884,776 ENP common units. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. ENP financed the cash portion of the purchase price through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

Shelf Registration Statement on Form S-3

     In November 2008, ENP’s “shelf” registration statement on Form S-3 was declared effective by the SEC. Under the shelf registration statement, ENP may offer common units, senior debt, or subordinated debt in one or more offerings with a total initial offering price of up to $1 billion.

Public Offerings of Common Units

     In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. ENP used the net proceeds of approximately $129.2 million, after deducting the underwriters’ discounts and commissions of $5.4 million, in the aggregate, and offering costs of $0.2 million, to fund a portion of the purchase price of the Rockies and Permian Basin Assets.

     In May 2009, ENP issued 2,760,000 common units under its shelf registration statement at a price to the public of $15.60 per common unit. ENP used the net proceeds of approximately $40.9 million, after deducting the underwriters’ discounts and commissions of $1.9 million, in the aggregate, and offering costs of approximately $0.2 million, to fund the acquisition of certain natural gas producing properties in the Vinegarone Field in Val Verde County, Texas (the “Vinegarone Assets”) from an independent energy company for approximately $27.5 million, and a portion of the purchase price of the Williston Basin Assets.

Long-Term Incentive Plan

     In September 2007, the board of directors of GP LLC adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Plan”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, GP LLC, and any of their subsidiaries and affiliates who perform services for ENP are eligible to be granted awards under the ENP Plan. The ENP Plan is administered by the board of directors of GP LLC or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the ENP Plan, ENP may issue common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.

36

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The total number of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of September 30, 2009, there were 1,100,000 common units available for issuance under the ENP Plan.

     Phantom Units.Each October, ENP issues 5,000 phantom units to each member of GP LLC’s board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units to the grantee; therefore, these phantom units are classified as equity instruments. Phantom units vest equally over a four-year period. The holders of phantom units are also entitled to distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions paid by ENP with respect to a common unit during the period the right is outstanding. During the nine months ended September 30, 2009 and 2008, ENP recognized non-cash unit-based compensation expense related to phantom units of approximately $0.3 million and $0.2 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

     The following table summarizes the changes in ENP’s unvested phantom units for the nine months ended September 30, 2009:

			Weighted
			Average
	Number of		Grant Date
	Shares		Fair Value
Outstanding at January 1, 2009		43,750	$	18.67
Granted		—		—
Vested		—		—
Forfeited		—		—
Outstanding at September 30, 2009		43,750		18.67

     As of September 30, 2009, ENP had $0.4 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 1.9 years.

Management Incentive Units

     In May 2007, the board of directors of GP LLC issued 550,000 management incentive units to certain executive officers of GP LLC. During the fourth quarter of 2008, the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units, and all 550,000 management incentive units were converted into 1,715,205 ENP common units.

     During the three and nine months ended September 30, 2008, ENP recognized non-cash unit-based compensation expense related to management incentive units of $1.1 million and $3.2 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have been no additional issuances of management incentive units.

Distributions

     During the three and nine months ended September 30, 2009, ENP paid cash distributions of approximately $23.5 million and $57.1 million, respectively, of which $11.0 million and $32.4 million, respectively, was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash. During the three and nine months ended September 30, 2008, ENP paid cash distributions of approximately $23.1 million and $52.3 million, respectively, of which $14.7 million and $32.7 million, respectively, was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

     During the three and nine months ended September 30, 2008, ENP paid cash distributions of approximately $1.2 million and $2.4 million, respectively, to certain executive officers of GP LLC, who serve in the same capacities for EAC, based on their ownership of management incentive units.

37

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 18. Segment Information

     EAC operates in only one industry: the oil and natural gas exploration and production industry in the United States. However, EAC is organizationally structured along two reportable segments: EAC Standalone and ENP. EAC’s segments are components of its business for which separate financial information is available and regularly evaluated by the chief operating decision maker in deciding how to allocate capital resources to projects and in assessing performance. The accounting policies used in the generation of segment financial statements are the same as those described in Note 2 to Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Date” of EAC’s 2008 Annual Report on Form 10-K.

     The following tables provide EAC’s operating segment information required by SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information” (ASC 280-10). The prior period financial information of ENP in the following tables was recast to include the financial results of the Rockies and Permian Basin Assets, the Arkoma Basin Assets, and the Williston Basin Assets.

		For the Three Months Ended September 30, 2009
		EAC									Consolidated
		Standalone			ENP			Eliminations			Total
		(in thousands)
Revenues:
Oil		$	117,669		$	35,280		$	—		$	152,949
Natural gas			26,518			5,650			—			32,168
Marketing			785			102			—			887
Total revenues			144,972			41,032			—			186,004
Expenses:
Production:
Lease operating			29,124			9,017			—			38,141
Production, ad valorem, and severance taxes			14,529			4,693			—			19,222
Depletion, depreciation, and amortization			58,169			14,458			—			72,627
Exploration			13,634			3,034			—			16,668
General and administrative			11,892			2,912			(1,534	)		13,270
Marketing			304			54			—			358
Derivative fair value gain			(8,434	)		(4,822	)		—			(13,256	)
Other operating			6,938			1,303			—			8,241
Total expenses			126,156			30,649			(1,534	)		155,271
Operating income			18,816			10,383			1,534			30,733
	��
Other income (expenses):
Interest			(18,936	)		(2,984	)		—			(21,920	)
Other			2,111			23			(1,534	)		600
Total other expenses			(16,825	)		(2,961	)		(1,534	)		(21,320	)
Income before income taxes			1,991			7,422			—			9,413
Income tax benefit (provision)			(11,227	)		38			—			(11,189	)
Consolidated net income (loss)			(9,236	)		7,460			—			(1,776	)
Change in deferred hedge loss on interest rate swaps, net of tax			(37	)		(306	)		—			(343	)
Consolidated comprehensive income (loss)		$	(9,273	)	$	7,154		$	—		$	(2,119	)

38

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Three Months Ended September 30, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	201,322		$	67,221		$	—		$	268,543
Natural gas		51,328			15,444			—			66,772
Marketing		718			1,445			—			2,163
Total revenues		253,368			84,110			—			337,478
Expenses:
Production:
Lease operating		35,999			12,967			—			48,966
Production, ad valorem, and severance taxes		25,140			8,210			—			33,350
Depletion, depreciation, and amortization		44,725			13,820			—			58,545
Impairment of long-lived assets		26,292			—			—			26,292
Exploration		13,334			47			—			13,381
General and administrative		12,601			3,772			(1,070	)		15,303
Marketing		539			1,316			—			1,855
Derivative fair value gain		(168,992	)		(70,443	)		—			(239,435	)
Other operating		3,633			440			—			4,073
Total expenses		(6,729	)		(29,871	)		(1,070	)		(37,670	)
Operating income		260,097			113,981			1,070			375,148
Other income (expenses):
Interest		(16,357	)		(1,767	)		—			(18,124	)
Other		2,613			10			(1,070	)		1,553
Total other expenses		(13,744	)		(1,757	)		(1,070	)		(16,571	)
Income before income taxes		246,353			112,224			—			358,577
Income tax provision		(120,852	)		(332	)		—			(121,184	)
Consolidated net income		125,501			111,892			—			237,393
Change in deferred hedge gain on interest rate swaps, net of tax		333			(597	)		—			(264	)
Consolidated comprehensive income	$	125,834		$	111,295		$	—		$	237,129

39

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Nine Months Ended September 30, 2009
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	286,482		$	88,433		$	—		$	374,915
Natural gas		71,765			15,143			—			86,908
Marketing		1,627			381			—			2,008
Total revenues		359,874			103,957			—			463,831
Expenses:
Production:
Lease operating		91,697			31,120			—			122,817
Production, ad valorem, and severance taxes		36,488			11,586			—			48,074
Depletion, depreciation, and amortization		173,677			43,684			—			217,361
Exploration		40,727			3,074			—			43,801
General and administrative		35,458			9,135			(3,850	)		40,743
Marketing		1,367			245			—			1,612
Derivative fair value loss (gain)		(22,452	)		21,711			—			(741	)
Other operating		26,689			2,730			—			29,419
Total expenses		383,651			123,285			(3,850	)		503,086
Operating loss		(23,777	)		(19,328	)		3,850			(39,255	)
Other income (expenses):
Interest		(49,458	)		(7,551	)		—			(57,009	)
Other		5,632			29			(3,850	)		1,811
Total other expenses		(43,826	)		(7,522	)		(3,850	)		(55,198	)
Loss before income taxes		(67,603	)		(26,850	)		—			(94,453	)
Income tax benefit (provision)		25,417			(163	)		—			25,254
Consolidated net loss		(42,186	)		(27,013	)		—			(69,199	)
Change in deferred hedge loss on interest rate swaps, net of tax		(253	)		342			—			89
Consolidated comprehensive loss	$	(42,439	)	$	(26,671	)	$	—		$	(69,110	)

40

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Nine Months Ended September 30, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	578,414		$	197,587		$	—		$	776,001
Natural gas		137,563			45,410			—			182,973
Marketing		3,533			5,207			—			8,740
Total revenues		719,510			248,204			—			967,714
Expenses:
Production:
Lease operating		95,944			34,069			—			130,013
Production, ad valorem, and severance taxes		72,134			23,711			—			95,845
Depletion, depreciation, and amortization		116,618			42,496			—			159,114
Impairment of long-lived assets		26,292			—			—			26,292
Exploration		30,347			115			—			30,462
General and administrative		27,854			11,899			(3,204	)		36,549
Marketing		4,044			5,318			—			9,362
Derivative fair value loss		60,521			21,572			—			82,093
Other operating		8,511			1,294			—			9,805
Total expenses		442,265			140,474			(3,204	)		579,535
Operating income		277,245			107,730			3,204			388,179
Other income (expenses):
Interest		(49,353	)		(5,316	)		—			(54,669	)
Other		6,202			92			(3,204	)		3,090
Total other expenses		(43,151	)		(5,224	)		(3,204	)		(51,579	)
Income before income taxes		234,094			102,506			—			336,600
Income tax provision		(118,401	)		(194	)		—			(118,595	)
Consolidated net income		115,693			102,312			—			218,005
Amortization of deferred loss on commodity derivative contracts, net of tax		1,786			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(234	)		387			—			153
Consolidated comprehensive income	$	117,245		$	102,699		$	—		$	219,944

     The following table provides EAC’s balance sheet segment information as of the dates indicated:

	September 30, 2009			December 31, 2008
	(in thousands)
Segment assets:
EAC Standalone	$	2,967,971		$	2,823,778
ENP		748,202			813,313
Eliminations		(2,359	)		(3,896	)
Total consolidated assets	$	3,713,814		$	3,633,195
Segment liabilities:
EAC Standalone	$	1,735,108		$	1,961,453
ENP		312,200			193,962
Eliminations		(2,259	)		(5,468	)
Total consolidated liabilities	$	2,045,049		$	2,149,947

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 19. Subsequent Events

     Subsequent events were evaluated through November 2, 2009, which is the date the financial statements were issued.

     On October 26, 2009, the board of directors of GP LLC declared an ENP cash distribution for the third quarter of 2009 to unitholders of record as of the close of business on November 9, 2009 at a rate of $0.5375 per unit. Approximately $24.6 million is expected to be paid to unitholders on or about November 13, 2009.

     On October 26, 2009, ENP issued 25,000 phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan. The phantom units vest in four equal installments beginning on the first anniversary of the date of grant.

     On November 1, 2009, EAC announced that it had entered into a definitive merger agreement with Denbury Resources Inc. (“Denbury”) pursuant to which Denbury will acquire EAC in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of the minority interest in ENP. Under the definitive agreement, EAC stockholders will receive $50.00 per share for each share of EAC common stock, comprised of $15.00 in cash and $35.00 in Denbury common stock subject to both an election feature and a collar mechanism on the stock portion of the consideration. Completion of the transaction is subject to the approval of both Denbury and EAC stockholders, regulatory approvals, and other conditions.

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

     The following discussion and analysis contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results could differ materially from those discussed in the forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report and in “Item 8. Financial Statements and Supplementary Data” of our 2008 Annual Report on Form 10-K.

Introduction

     In this management’s discussion and analysis of financial condition and results of operations, the following are discussed and analyzed:

• Third Quarter 2009 Highlights

• Results of Operations

o Comparison of Quarter Ended September 30, 2009 to Quarter Ended September 30, 2008

o Comparison of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2008

• Capital Commitments, Capital Resources, and Liquidity

• Critical Accounting Policies and Estimates

• New Accounting Pronouncements

Third Quarter 2009 Highlights

     Our financial and operating results for the third quarter of 2009 included the following:

• Our average daily production volumes increased nine percent to 43,225 BOE/D as compared to 39,617 BOE/D in the third quarter of 2008. Oil represented 64 percent of our total production volumes as compared to 68 percent in the third quarter of 2008.

• In September 2009, we issued 2,750,000 shares of our common stock at a price to the public of $37.40 per common share. The net proceeds of approximately $100.7 million were used to reduce outstanding borrowings under our revolving credit facility.

• In August, we purchased certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO for approximately $357.0 million in cash (including a deposit of $37.5 million made in June 2009).

• In August, we sold the Rockies and Permian Basin Assets to ENP for approximately $186.8 million in cash.

• In July, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. The net proceeds of approximately $129.1 million were used to fund a portion of the purchase price of the Rockies and Permian Basin Assets.

• We invested $411.5 million in oil and natural gas activities (excluding $3.5 million of asset retirement obligations), of which $42.7 million was invested in development, exploitation, and exploration activities, yielding 22 gross (7.7 net) productive wells, and $368.8 million was invested in acquisitions, primarily related to our EXCO asset acquisition.

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Results of Operations

Comparison of Quarter Ended September 30, 2009 to Quarter Ended September 30, 2008

     Revenues.The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Three months ended September 30,				Increase / (Decrease)
	2009		2008		$			%
Revenues (in thousands):
Oil wellhead	$	152,949	$	268,543	$	(115,594	)		-43	%
Natural gas wellhead		32,168		66,772		(34,604	)		-52	%
Total combined oil and natural gas revenues		185,117		335,315		(150,198	)		-45	%
Marketing		887		2,163		(1,276	)		-59	%
Total revenues	$	186,004	$	337,478	$	(151,474	)		-45	%
Average realized prices:
Oil ($/Bbl)	$	60.45	$	108.21	$	(47.76	)		-44	%
Natural gas ($/Mcf)	$	3.71	$	9.57	$	(5.86	)		-61	%
Total combined oil and natural gas revenues ($/BOE)	$	46.55	$	92.00	$	(45.45	)		-49	%
Total production volumes:
Oil (MBbls)		2,530		2,482		48			2	%
Natural gas (MMcf)		8,681		6,978		1,703			24	%
Combined (MBOE)		3,977		3,645		332			9	%
Average daily production volumes:
Oil (Bbls/D)		27,500		26,975		525			2	%
Natural gas (Mcf/D)		94,353		75,847		18,506			24	%
Combined (BOE/D)		43,225		39,617		3,608			9	%
Average NYMEX prices:
Oil (per Bbl)	$	68.24	$	118.67	$	(50.43	)		-42	%
Natural gas (per Mcf)	$	3.40	$	10.27	$	(6.87	)		-67	%

     Oil revenues decreased 43 percent from $268.5 million in the third quarter of 2008 to $152.9 million in the third quarter of 2009 as a result of a $47.76 per Bbl decrease in our average realized oil price, partially offset by a 48 MBbls increase in our oil production volumes. Our lower average realized oil price decreased oil revenues by approximately $120.8 million and was primarily due to a lower average NYMEX price, which decreased from $118.67 per Bbl in the third quarter of 2008 to $68.24 per Bbl in the third quarter of 2009. Our higher oil production volumes increased oil revenues by approximately $5.2 million and was primarily due to our acquisitions of properties from EXCO in August 2009.

     In the third quarter of 2009 and 2008, our average daily production volumes were decreased by 1,654 BOE/D and 1,535 BOE/D, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by approximately $8.8 million and $18.5 million, respectively.

     Natural gas revenues decreased 52 percent from $66.8 million in the third quarter of 2008 to $32.2 million in the third quarter of 2009 as a result of a $5.86 per Mcf decrease in our average realized natural gas price, partially offset by a 1,703 MMcf increase in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $50.9 million and was primarily due to a lower average NYMEX price, which decreased from $10.27 per Mcf in the third quarter of 2008 to $3.40 per Mcf in the third quarter of 2009. Our higher natural gas production increased natural gas revenues by approximately $16.3 million and was primarily due to our acquisitions of properties from EXCO in August 2009.

     The following table shows the relationship between our oil and natural gas wellhead prices as a percentage of average NYMEX prices for the periods indicated. Management uses the wellhead price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

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	Three months ended September 30,
	2009			2008
Average realized oil price ($/Bbl)	$	60.45		$	108.21
Average NYMEX ($/Bbl)	$	68.24		$	118.67
Differential to NYMEX	$	(7.79	)	$	(10.46	)
Average realized oil price to NYMEX percentage		89	%		91	%
Average realized natural gas price ($/Mcf)	$	3.71		$	9.57
Average NYMEX ($/Mcf)	$	3.40		$	10.27
Differential to NYMEX	$	0.31		$	(0.70	)
Average realized natural gas price to NYMEX percentage		109	%		93	%

     Our average oil wellhead price as a percentage of the average NYMEX price was 89 percent in the third quarter of 2009 as compared to 91 percent in the third quarter of 2008.

     Our average natural gas wellhead price as a percentage of the average NYMEX price was 109 percent in the third quarter of 2009 as compared to 93 percent in the third quarter of 2008. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. In the third quarter of 2009, the natural gas index prices related to our West Texas, East Texas, and Rocky Mountains natural gas contracts all improved in their relationship to NYMEX narrowing the average differential. As a result of the incremental NGLs value and the narrower differentials, the price we were paid per Mcf for natural gas sold under certain contracts during the third quarter of 2009 increased to a level above NYMEX.

     Marketing revenues decreased 59 percent from $2.2 million in the third quarter of 2008 to $0.9 million in the third quarter of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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     Expenses.The following table provides the components of our expenses for the periods indicated:

	Three months ended September 30,						Increase / (Decrease)
	2009			2008			$			%
Expenses (in thousands):
Production:
Lease operating	$	38,141		$	48,966		$	(10,825	)
Production, ad valorem, and severance taxes		19,222			33,350			(14,128	)
Total production expenses		57,363			82,316			(24,953	)		-30	%
Other:
Depletion, depreciation, and amortization		72,627			58,545			14,082
Impairment of long-lived assets		—			26,292			(26,292	)
Exploration		16,668			13,381			3,287
General and administrative		13,270			15,303			(2,033	)
Marketing		358			1,855			(1,497	)
Derivative fair value gain		(13,256	)		(239,435	)		226,179
Other operating		8,241			4,073			4,168
Total operating expenses		155,271			(37,670	)		192,941			-512	%
Interest		21,920			18,124			3,796
Income tax provision		11,189			121,184			(109,995	)
Total expenses	$	188,380		$	101,638		$	86,742			85	%
Expenses (per BOE):
Production:
Lease operating	$	9.59		$	13.43		$	(3.84	)
Production, ad valorem, and severance taxes		4.83			9.15			(4.32	)
Total production expenses		14.42			22.58			(8.16	)		-36	%
Other:
Depletion, depreciation, and amortization		18.26			16.06			2.20
Impairment of long-lived assets		—			7.21			(7.21	)
Exploration		4.19			3.67			0.52
General and administrative		3.34			4.20			(0.86	)
Marketing		0.09			0.51			(0.42	)
Derivative fair value gain		(3.33	)		(65.69	)		62.36
Other operating		2.07			1.12			0.95
Total operating expenses		39.04			(10.34	)		49.38			-478	%
Interest		5.51			4.97			0.54
Income tax provision		2.81			33.25			(30.44	)
Total expenses	$	47.36		$	27.88		$	19.48			70	%

     Production expenses.Total production expenses decreased 30 percent from $82.3 million in the third quarter of 2008 to $57.4 million in the third quarter of 2009. Our production margin decreased 50 percent from $253.0 million in the third quarter of 2008 to $127.8 million in the third quarter of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 49 percent and total production expenses per BOE decreased by 36 percent. On a per BOE basis, our production margin decreased 54 percent to $32.13 per BOE in the third quarter of 2009 as compared to $69.42 per BOE in the third quarter of 2008.

     Production expense attributable to LOE decreased $10.8 million from $49.0 million in the third quarter of 2008 to $38.1 million in the third quarter of 2009 as a result of a $3.84 decrease in the per BOE rate, partially offset by higher production volumes. Our lower average LOE per BOE rate decreased LOE by approximately $15.3 million and was primarily due to decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs, lower prices paid to oilfield service companies and suppliers, and retention bonuses paid in August 2008 related to our 2008 strategic alternatives process. Our higher production volumes increased LOE by approximately $4.5 million.

     Production expense attributable to production taxes decreased $14.1 million from $33.4 million in the third quarter of 2008 to $19.2 million in the third quarter of 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes increased to 10.4 percent in the third quarter of 2009 as

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compared to 9.9 percent in the third quarter of 2008 primarily due to higher ad valorem taxes, which are based on production volumes as opposed to a percentage of wellhead revenues.

     Depletion, depreciation, and amortization expense (“DD&A”).DD&A expense increased $14.1 million from $58.5 million in the third quarter of 2008 to $72.6 million in the third quarter of 2009 as a result of a $2.20 increase in the per BOE rate and higher production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $8.7 million and was primarily due to the decrease in our proved reserves as a result of lower average commodity prices, partially offset by reserves added through our EXCO asset acquisition. Our higher production volumes increased DD&A expense by approximately $5.3 million.

     Impairment of long-lived assets.During the third quarter of 2008, circumstances indicated that the carrying value of the two wells we drilled in the Tuscaloosa Marine Shale may not be recoverable. We compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a write-down of the value of proved oil and natural gas properties of $26.3 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

     Exploration expense.Exploration expense increased $3.3 million from $13.4 million in the third quarter of 2008 to $16.7 million in the third quarter of 2009. During the third quarter of 2009, we expensed 1.6 net exploratory dry holes totaling $9.8 million. During the third quarter of 2008, we expensed 1.3 net exploratory dry holes totaling $7.2 million. Impairment of unproved acreage increased $1.4 million from $5.0 million in the third quarter of 2008 to $6.4 million in the third quarter of 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table provides the components of exploration expense for the periods indicated:

	Three months ended September 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
Dry holes	$	9,759	$	7,161	$	2,598
Geological and seismic		282		1,070		(788	)
Delay rentals		276		157		119
Impairment of unproved acreage		6,351		4,993		1,358
Total	$	16,668	$	13,381	$	3,287

     General and administrative expense (“G&A”).G&A expense decreased $2.0 million from $15.3 million in the third quarter of 2008 to $13.3 million in the third quarter of 2009 primarily due to retention bonuses paid in August 2008 related to our 2008 strategic alternatives process and a decrease in non-cash equity-based compensation related to ENP’s management incentive units, partially offset by the expensing of transaction costs related to our EXCO asset acquisition.

     Marketing expenses.Marketing expenses decreased $1.5 million from $1.9 million in the third quarter of 2008 to $0.4 million in the third quarter of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

     Derivative fair value gain.During the third quarter of 2009, we recorded a $13.3 million derivative fair value gain as compared to $239.4 million in the third quarter of 2008, the components of which were as follows:

	Three months ended September 30,						Increase /
	2009			2008			(Decrease)
	(in thousands)
Ineffectiveness	$	18		$	(6	)	$	24
Mark-to-market loss (gain)		576			(276,932	)		277,508
Premium amortization		6,838			14,773			(7,935	)
Settlements		(20,688	)		22,730			(43,418	)
Total derivative fair value gain	$	(13,256	)	$	(239,435	)	$	226,179

     Other operating expense.Other operating expense increased $4.2 million from $4.1 million in the third quarter of 2008 to $8.2

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million in the third quarter of 2009 primarily due to a $0.7 million adjustment to the carrying value of pipe and other tubular inventory whose market value had declined below cost, a $2.4 million adjustment to the carrying value of certain receivables, primarily from ExxonMobil related to our West Texas joint venture, and higher gathering and transportation fees.

     Interest expense.Interest expense increased $3.8 million from $18.1 million in the third quarter of 2008 to $21.9 million in the third quarter of 2009 primarily due to the issuance of $225 million of our 9.5% Notes. We received net proceeds of approximately $202.5 million from the issuance of the 9.5% Notes, which we used to reduce outstanding borrowings under our revolving credit facility. Our weighted average interest rate was 6.5 percent for the third quarter of 2009 as compared to 5.6 percent for the third quarter of 2008.

     The following table provides the components of interest expense for the periods indicated:

	Three months ended September 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
6.25% Senior Subordinated Notes	$	2,439	$	2,433	$	6
6.0% Senior Subordinated Notes		4,648		4,640		8
9.5% Senior Subordinated Notes		5,904		—		5,904
7.25% Senior Subordinated Notes		2,752		2,749		3
Revolving credit facilities		4,786		7,478		(2,692	)
Other		1,391		824		567
Total	$	21,920	$	18,124	$	3,796

     Income taxes.In the third quarter of 2009, we recorded an income tax provision of $11.2 million as compared to $121.2 million in the third quarter of 2008. In the third quarter of 2009, we had income before income taxes and noncontrolling interest of $9.4 million as compared to $358.6 million in the third quarter of 2008. Our effective tax rate increased to 118.9 percent in the third quarter of 2009 as compared to 33.8 percent in the third quarter of 2008 primarily due to the loss of the production activities deduction in 2009, the 2008 provision to return difference in the production activities deduction estimated at the end of 2008 due to a change in tax planning as a result of the hedge monetization in the first quarter of 2009, and an increase in the effective state income tax rate due to changes in apportionment associated with our 2009 acquisitions.

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Comparison of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2008

     Revenues.The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Nine months ended September 30,					Increase / (Decrease)
	2009		2008			$			%
Revenues (in thousands):
Oil wellhead	$	374,915	$	778,858		$	(403,943	)
Oil hedges		—		(2,857	)		2,857
Total oil revenues	$	374,915	$	776,001		$	(401,086	)		-52	%
Natural gas wellhead	$	86,908	$	182,973		$	(96,065	)		-53	%
Combined wellhead	$	461,823	$	961,831		$	(500,008	)
Combined hedges		—		(2,857	)		2,857
Total combined oil and natural gas revenues		461,823		958,974			(497,151	)		-52	%
Marketing		2,008		8,740			(6,732	)		-77	%
Total revenues	$	463,831	$	967,714		$	(503,883	)		-52	%
Average realized prices:
Oil wellhead ($/Bbl)	$	50.34	$	104.61		$	(54.27	)
Oil hedges ($/Bbl)		—		(0.38	)		0.38
Total oil revenues ($/Bbl)	$	50.34	$	104.23		$	(53.89	)		-52	%
Natural gas wellhead ($/Mcf)	$	3.56	$	9.67		$	(6.11	)		-63	%
Combined wellhead ($/BOE)	$	40.10	$	90.76		$	(50.66	)
Combined hedges ($/BOE)		—		(0.27	)		0.27
Total combined oil and natural gas revenues ($/BOE)	$	40.10	$	90.49		$	(50.39	)		-56	%
Total production volumes:
Oil (MBbls)		7,448		7,446			2			0	%
Natural gas (MMcf)		24,408		18,915			5,493			29	%
Combined (MBOE)		11,516		10,598			918			9	%
Average daily production volumes:
Oil (Bbls/D)		27,281		27,174			107			0	%
Natural gas (Mcf/D)		89,405		69,031			20,374			30	%
Combined (BOE/D)		42,182		38,679			3,503			9	%
Average NYMEX prices:
Oil (per Bbl)	$	57.22	$	113.59		$	(56.37	)		-50	%
Natural gas (per Mcf)	$	3.93	$	9.74		$	(5.81	)		-60	%

     Oil revenues decreased 52 percent from $776.0 million in the first nine months of 2008 to $374.9 million in the first nine months of 2009 as a result of a $53.89 per Bbl decrease in our average realized oil price. Our lower average oil wellhead price decreased oil revenues by approximately $404.2 million, or $54.27 per Bbl, and was primarily due to a lower average NYMEX price, which decreased from $113.59 per Bbl in the first nine months of 2008 to $57.22 Bbl in the first nine months of 2009. Oil revenues in the first nine months of 2008 were also reduced by approximately $2.9 million, or $0.38 per Bbl, for oil derivative contracts previously designated as hedges.

     In the first nine months of 2009 and 2008, our average daily production volumes were decreased by 1,710 BOE/D and 1,766 BOE/D, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by approximately $21.1 million and $49.7 million, respectively.

     Natural gas revenues decreased 53 percent from $183.0 million in the first nine months of 2008 to $86.9 million in the first nine months of 2009 as a result of a $6.11 per Mcf decrease in our average realized natural gas price, partially offset by a 5,493 MMcf increase in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $149.2 million and was primarily due to a lower average NYMEX price, which decreased from $9.74 per Mcf in the

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first nine months of 2008 to $3.93 per Mcf in the first nine months of 2009. Our higher natural gas production increased natural gas revenues by approximately $53.1 million and was primarily due to successful development programs in our Permian Basin and Mid-Continent areas and our acquisitions of properties from EXCO in August 2009.

     The following table shows the relationship between our oil and natural gas wellhead prices as a percentage of average NYMEX prices for the periods indicated:

	Nine months ended September 30,
	2009			2008
Average oil wellhead ($/Bbl)	$	50.34		$	104.61
Average NYMEX ($/Bbl)	$	57.22		$	113.59
Differential to NYMEX	$	(6.88	)	$	(8.98	)
Average oil wellhead to NYMEX percentage		88	%		92	%
Average natural gas wellhead ($/Mcf)	$	3.56		$	9.67
Average NYMEX ($/Mcf)	$	3.93		$	9.74
Differential to NYMEX	$	(0.37	)	$	(0.07	)
Average natural gas wellhead to NYMEX percentage		91	%		99	%

     Our average oil wellhead price as a percentage of the average NYMEX price was 88 percent in the first nine months of 2009 as compared to 92 percent in the first nine months of 2008. The percentage differential widened as a result of a 50 percent decrease in NYMEX as compared to the first nine months of 2008. However, the per Bbl differential improved from $8.98 per Bbl in the first nine months of 2008 to $6.88 per Bbl in the first nine months of 2009.

     Our average natural gas wellhead price as a percentage of the average NYMEX price was 91 percent in the first nine months of 2009 as compared to 99 percent in the first nine months of 2008. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. During the first nine months of 2008, the price of NGLs increased at a much faster pace than did the price of natural gas resulting in a price we were paid per Mcf under certain contracts to be higher than the average NYMEX price. However, in the first nine months of 2009, the total average natural gas index prices related to our West Texas, East Texas, and Rocky Mountains natural gas contracts all deteriorated in their relationship to NYMEX widening the year-to-date average differential.

     Marketing revenues decreased 77 percent from $8.7 million in the first nine months of 2008 to $2.0 million in the first nine months of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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     Expenses.The following table provides the components of our expenses for the periods indicated:

	Nine months ended September 30,					Increase / (Decrease)
	2009			2008		$				%
Expenses (in thousands):
Production:									��
Lease operating	$	122,817		$	130,013	$	(7,196	)
Production, ad valorem, and severance taxes		48,074			95,845		(47,771	)
Total production expenses		170,891			225,858		(54,967	)			-24	%
Other:
Depletion, depreciation, and amortization		217,361			159,114		58,247
Impairment of long-lived assets		—			26,292		(26,292	)
Exploration		43,801			30,462		13,339
General and administrative		40,743			36,549		4,194
Marketing		1,612			9,362		(7,750	)
Derivative fair value loss (gain)		(741	)		82,093		(82,834	)
Other operating		29,419			9,805		19,614
Total operating expenses		503,086			579,535		(76,449	)			-13	%
Interest		57,009			54,669		2,340
Income tax provision (benefit)		(25,254	)		118,595		(143,849	)
Total expenses	$	534,841		$	752,799	$	(217,958	)			-29	%
Expenses (per BOE):
Production:
Lease operating	$	10.67		$	12.27	$	(1.60	)
Production, ad valorem, and severance taxes		4.17			9.04		(4.87	)
Total production expenses		14.84			21.31		(6.47	)			-30	%
Other:
Depletion, depreciation, and amortization		18.88			15.01		3.87
Impairment of long-lived assets		—			2.48		(2.48	)
Exploration		3.80			2.87		0.93
General and administrative		3.54			3.45		0.09
Marketing		0.14			0.88		(0.74	)
Derivative fair value loss (gain)		(0.06	)		7.75		(7.81	)
Other operating		2.55			0.93		1.62
Total operating expenses		43.69			54.68		(10.99	)			-20	%
Interest		4.95			5.16		(0.21	)
Income tax provision (benefit)		(2.19	)		11.19		(13.38	)
Total expenses	$	46.45		$	71.03	$	(24.58	)			-35	%

     Production expenses.Total production expenses decreased 24 percent from $225.9 million in the first nine months of 2008 to $170.9 million in the first nine months of 2009. Our production margin decreased 60 percent from $736.0 million in the first nine months of 2008 to $290.9 million in the first nine months of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 56 percent and total production expenses per BOE decreased by 30 percent. On a per BOE basis, our production margin decreased 64 percent to $25.26 per BOE in the first nine months of 2009 as compared to $69.45 per BOE in the first nine months of 2008.

     Production expense attributable to LOE decreased $7.2 million from $130.0 million in the first nine months of 2008 to $122.8 million in the first nine months of 2009 as a result of a $1.60 decrease in the per BOE rate, partially offset by higher production volumes. Our lower average LOE per BOE rate decreased LOE by approximately $18.5 million and was primarily due to decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs and lower prices paid to oilfield service companies and suppliers. Our higher production volumes increased LOE by approximately $11.3 million.

     Production expense attributable to production taxes decreased $47.8 million from $95.8 million in the first nine months of 2008 to $48.1 million in the first nine months of 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes increased to 10.4 percent in the first nine months of 2009 as compared to 10.0 percent in the first nine months of 2008 primarily due to higher ad valorem taxes, which are based on production volumes as opposed to a percentage of wellhead revenues.

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     DD&A expense.DD&A expense increased $58.2 million from $159.1 million in the first nine months of 2008 to $217.4 million in the first nine months of 2009 as a result of a $3.87 increase in the per BOE rate and higher production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $44.5 million and was primarily due to the decrease in our proved reserves as a result of lower average commodity prices, partially offset by reserves added through our EXCO asset acquisition. Our higher production volumes increased DD&A expense by approximately $13.8 million.

     Impairment of long-lived assets.During the third quarter of 2008, circumstances indicated that the carrying value of the two wells we drilled in the Tuscaloosa Marine Shale may not be recoverable. We compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a write-down of the value of proved oil and natural gas properties of $26.3 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

     Exploration expense.Exploration expense increased $13.3 million from $30.5 million in the first nine months of 2008 to $43.8 million in the first nine months of 2009. During the first nine months of 2009, we expensed 5.6 net exploratory dry holes totaling $24.3 million. During the first nine months of 2008, we expensed 3.8 net exploratory dry holes totaling $14.4 million. Impairment of unproved acreage increased $4.8 million from $13.3 million in the first nine months of 2008 to $18.1 million in the first nine months of 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table provides the components of exploration expense for the periods indicated:

	Nine months ended September 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
Dry holes	$	24,272	$	14,395	$	9,877
Geological and seismic		921		1,903		(982	)
Delay rentals		506		860		(354	)
Impairment of unproved acreage		18,102		13,304		4,798
Total	$	43,801	$	30,462	$	13,339

     G&A expense.G&A expense increased $4.2 million from $36.5 million in the first nine months of 2008 to $40.7 million in the first nine months of 2009 primarily due to retention bonuses paid in August 2009 related to our 2008 strategic alternatives process and the expensing of transaction costs related to our EXCO asset acquisition.

     Marketing expenses.Marketing expenses decreased $7.8 million from $9.4 million in the first nine months of 2008 to $1.6 million in the first nine months of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

     Derivative fair value loss (gain).During the first nine months of 2009, we recorded a $0.7 million derivative fair value gain as compared to an $82.1 million derivative fair value loss in the first nine months of 2008, the components of which were as follows:

	Nine Months Ended September 30,						Increase /
	2009			2008			(Decrease)
	(in thousands)
Ineffectiveness	$	(16	)	$	(349	)	$	333
Mark-to-market loss (gain)		281,569			(11,884	)		293,453
Premium amortization		91,557			47,579			43,978
Settlements		(373,851	)		46,747			(420,598	)
Total derivative fair value loss (gain)	$	(741	)	$	82,093		$	(82,834	)

     Other operating expense.Other operating expense increased $19.6 million from $9.8 million in the first nine months of 2008 to $29.4 million in the first nine months of 2009 primarily due to a $6.5 million adjustment to the carrying value of pipe and other tubular inventory whose market value had declined below cost, a $7.1 million adjustment to the carrying value of certain receivables, primarily from ExxonMobil related to our West Texas joint venture, and higher gathering and transportation fees.

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     Interest expense.Interest expense increased $2.3 million from $54.7 million in the first nine months of 2008 to $57.0 million in the first nine months of 2009 primarily due to the issuance of our 9.5% Notes. Our weighted average interest rate was 5.5 percent for the first nine months of 2009 as compared to 5.8 percent for the first nine months of 2008.

     The following table provides the components of interest expense for the periods indicated:

	Nine months ended September 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
6.25% Senior Subordinated Notes	$	7,312	$	7,294	$	18
6.0% Senior Subordinated Notes		13,936		13,910		26
9.5% Senior Subordinated Notes		10,073		—		10,073
7.25% Senior Subordinated Notes		8,253		8,247		6
Revolving credit facilities		13,472		23,082		(9,610	)
Other		3,963		2,136		1,827
Total	$	57,009	$	54,669	$	2,340

     Income taxes.In the first nine months of 2009, we recorded an income tax benefit of $25.3 million as compared to an income tax provision of $118.6 million in the first nine months of 2008. In the first nine months of 2009, we had a loss before income taxes and noncontrolling interest of $94.5 million as compared to income before income taxes and noncontrolling interest of $336.6 million in the first nine months of 2008. Our effective tax rate decreased to 26.7 percent in the first nine months of 2009 as compared to 35.2 percent in the first nine months of 2008 primarily due to the 2008 provision to return difference in the production activities deduction estimated at the end of 2008 due to a change in tax planning as a result of the hedges monetization in the first quarter of 2009 and an increase in the effective state income tax rate due to changes in apportionment associated with our 2009 acquisitions.

Capital Commitments, Capital Resources, and Liquidity

     Capital commitments

     Our primary uses of cash are:

• Development, exploitation, and exploration of oil and natural gas properties;

• Acquisitions of oil and natural gas properties;

• Funding of working capital; and

• Contractual obligations.

     Development, exploitation, and exploration of oil and natural gas properties.The following table summarizes our costs incurred (excluding asset retirement obligations) related to development, exploitation, and exploration activities for the periods indicated:

	Three months ended September 30,				Nine months ended September 30,
	2009		2008		2009		2008
	(in thousands)
Development and exploitation	$	22,670	$	116,376	$	94,934	$	250,624
Exploration		20,046		69,960		140,138		179,217
Total	$	42,716	$	186,336	$	235,072	$	429,841

     Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for the third quarter of 2009 yielded 6 gross (2.0 net) successful wells and no dry holes. Our development and exploitation capital for the first nine months of 2009 yielded 54 gross (24.7 net) successful wells and no dry holes.

     Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for the third quarter of 2009 yielded 16 gross (5.7 net) successful wells and 3 gross (1.6 net) dry holes. Our exploration capital for the first nine months of 2009 yielded 48 gross (15.5 net) successful wells and 7 gross (5.6 net) dry holes.

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     Acquisitions of oil and natural gas properties and leasehold acreage.The following table summarizes our costs incurred (excluding asset retirement obligations) related to oil and natural gas property acquisitions for the periods indicated:

	Three months ended September 30,				Nine months ended September 30,
	2009		2008		2009		2008
	(in thousands)
Acquisitions of proved property	$	366,930	$	8,725	$	394,482	$	29,193
Acquisitions of leasehold acreage		1,828		61,275		6,004		95,916
Total	$	368,758	$	70,000	$	400,486	$	125,109

     In August 2009, we acquired certain oil and natural gas properties from EXCO for approximately $357.0 million in cash (including a deposit of $37.5 million made in June 2009). In May 2009, ENP acquired the Vinegarone Assets for approximately $27.5 million in cash.

     During the three and nine months ended September 30, 2009, our capital expenditures for leasehold acreage related to the acquisition of unproved acreage in various areas. During the three and nine months ended September 30, 2008, $44.0 million of our capital expenditures for leasehold acreage related to the exercise of preferential rights in the Haynesville area and the remainder related to the acquisition of unproved acreage in various areas.

     Funding of working capital.As of September 30, 2009 and December 31, 2008, our working capital (defined as total current assets less total current liabilities) was a negative $61.9 million and a positive $188.7 million, respectively. The decrease was primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and higher oil prices at September 30, 2009 as compared to December 31, 2008, which negatively impacted the fair value of our outstanding oil derivative contracts.

     For the remainder of 2009, we expect working capital to remain negative primarily due to higher oil prices as compared to December 31, 2008. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and reduce outstanding borrowings and related interest expense under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. We do not plan to pay cash dividends in the foreseeable future. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Given our current commodity derivative contracts, assuming relatively stable commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for the remainder of 2009.

     The Board approved a capital budget of $340 million for 2009, excluding proved property acquisitions. The level of these and other future expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and availability under our revolving credit facility.

     Off-balance sheet arrangements.We have no investments in unconsolidated entities or persons that could materially affect our liquidity or availability of capital resources. We have no off-balance sheet arrangements that are material to our financial position or results of operations.

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     Contractual obligations.The following table provides the components of our contractual obligations and commitments at September 30, 2009:

		Payments Due by Period
				Three Months Ending		Years Ending		Years Ending
Contractual Obligations	Maturity			December 31,		December 31,		December 31,
and Commitments	Date	Total		2009		2010 - 2011		2012 - 2013		Thereafter
		(in thousands)
6.25% Senior Subordinated Notes (a)	4/15/2014	$	196,875	$	4,687	$	18,750	$	18,750	$	154,688
6.0% Senior Subordinated Notes (a)	7/15/2015		408,000		—		36,000		36,000		336,000
9.5% Senior Subordinated Notes (a)	5/1/2016		374,625		10,687		42,750		42,750		278,438
7.25% Senior Subordinated Notes (a)	12/1/2017		242,438		5,438		21,750		21,750		193,500
Revolving credit facilities (a)	3/7/2012		467,527		5,005		20,020		442,502		—
Commodity derivative contracts (b)			44,652		—		38,810		5,842		—
Interest rate swaps (c)			4,239		942		3,297		—		—
Capital lease obligations			1,398		117		932		349		—
Development commitments (d)			47,704		12,044		35,660		—		—
Operating leases and commitments (e)			14,556		988		7,603		5,965		—
Asset retirement obligations (f)			192,735		511		4,093		4,093		184,038
Total		$	1,994,749	$	40,419	$	229,665	$	578,001	$	1,146,664

(a)	Includes principal and projected interest payments. Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.
(b)	Represents net liabilities for commodity derivative contracts. With the exception of $43.2 million of deferred premiums on commodity derivative contracts, the ultimate settlement amounts of our commodity derivative contracts are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.
(c)	Represents net liabilities for interest rate swaps, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our interest rate swaps.
(d)	Includes authorized purchases for work in process of $47.5 million and future minimum payments for drilling rig operations of $0.2 million. Also at September 30, 2009, we had approximately $155.1 million of authorized purchases not placed with vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and expected to be made unless circumstances change.
(e)	Includes office space and equipment obligations that have non-cancelable initial lease terms in excess of one year of $14.1 million and future minimum payments for other operating commitments of $0.5 million.
(f)	Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our asset retirement obligations.

     Other contingencies and commitments. In order to facilitate ongoing sales of our oil production in the CCA, we ship a portion of our production in pipelines downstream and sell to purchasers at major market hubs. From time to time, shipping delays, purchaser stipulations, or other conditions may require that we sell our oil production in periods subsequent to the period in which it is produced. In such case, the deferred sale would have an adverse effect in the period of production on reported production volumes, oil and natural gas revenues, and costs as measured on a unit-of-production basis.

     The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and subject to apportionment, we have been allocated sufficient pipeline capacity to move our crude oil production. An expansion of the Enbridge Pipeline was completed in early 2008, which moved the total Rockies area pipeline takeaway closer to a balancing point with increasing production volumes and thereby provided greater stability to oil differentials in the area. In spite of the increase in capacity, the Enbridge Pipeline continues to run at full capacity and is scheduled to complete an additional expansion by the beginning of 2010. However, further restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

     The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot accurately predict future oil and natural gas differentials. Increases in the percentage differential between the NYMEX

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price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows.

     Capital resources

     Cash flows from operating activities. Cash provided by operating activities increased $104.2 million from $529.0 million for the first nine months of 2008 to $633.2 million for the first nine months of 2009, primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and decreased settlements paid under our oil derivative contracts as a result of lower average oil prices in the first nine months of 2009 as compared to the first nine months of 2008, partially offset by a decrease in our production margin.

     Cash flows from investing activities. Cash used in investing activities increased $174.2 million from $536.1 million in the first nine months of 2008 to $710.3 million in the first nine months of 2009, primarily due to a $307.2 million increase in amounts paid to acquire oil and natural gas properties, namely our EXCO asset acquisition, partially offset by a $91.4 million decrease in amounts paid to develop oil and natural gas properties and a $38.7 million decrease in net advancements to working interest partners. During the first nine months of 2009, we collected $5.5 million (net of advancements) from ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement. During the first nine months of 2008, we advanced $33.3 million (net of collections) to ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement.

     Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt and issuances of EAC shares of common stock and ENP common units. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.

     During the first nine months of 2009, we received net cash of $81.8 million in financing activities, including $202.5 million of net proceeds from the issuance of the 9.5% Notes, $100.7 million of net proceeds from EAC’s issuance of common stock, and $170.1 million of net proceeds from ENP’s issuance of common units, partially offset by net repayments on revolving credit facilities of $285 million, payments for deferred commodity derivative contract premiums of $70.5 million, and ENP distributions to noncontrolling interests of $24.6 million. Net repayments decreased the outstanding borrowings under revolving credit facilities from $725 million at December 31, 2008 to $440 million at September 30, 2009.

     In October 2008, we announced that the Board approved a share repurchase program authorizing us to repurchase up to $40 million of our common stock. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. The share repurchase program will be funded using our available cash. As of September 30, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the first nine months of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of September 30, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

     During the first nine months of 2008, we received net cash of $9.2 million from financing activities, including net borrowings on revolving credit facilities of $96.9 million, partially offset by $50 million of share repurchases, payments for deferred commodity derivative contract premiums of $30.8 million, and ENP distributions to noncontrolling interests of $19.5 million.

     Liquidity

     Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our revolving credit facility. We also have the ability to adjust the level of our capital expenditures. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures for the foreseeable future. However, should commodity prices decline or the capital markets remain tight, the borrowing capacity under our revolving credit facilities could be adversely affected. In the event of a reduction in the borrowing base under our revolving credit facilities, we do not believe it will result in any required prepayments of indebtedness.

     We plan to make substantial capital expenditures in the future for the acquisition, exploitation, and development of oil and natural gas properties. We intend to finance these capital expenditures with cash flows from operations. We intend to finance our acquisition

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and future development and exploitation activities with a combination of cash flows from operations and issuances of debt, equity, or a combination thereof.

     Issuance of 9.5% Senior Subordinated Notes Due 2016.On April 27, 2009, we issued $225 million of our 9.5% Notes at 92.228 percent of par value. We used the net proceeds of approximately $202.5 million to reduce outstanding borrowings under our revolving credit facility. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

     Internally generated cash flows.Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During the first nine months of 2009, our average realized oil and natural gas prices decreased by 52 percent and 63 percent, respectively, as compared to the first nine months of 2008. Realized oil and natural gas prices fluctuate widely in response to changing market forces. If oil and natural gas prices decline or we experience a significant widening of our differentials, then our earnings, cash flows from operations, and borrowing base under our revolving credit facilities may be adversely impacted. Prolonged periods of lower oil and natural gas prices or sustained wider differentials could cause us to not be in compliance with financial covenants under our revolving credit facilities and thereby affect our liquidity. However, we have protected a portion of our forecasted production through 2012 against declining commodity prices. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.

     Revolving credit facilities.The syndicate of lenders underwriting our revolving credit facility includes 29 banking and other financial institutions, and the syndicate of lenders underwriting ENP’s revolving credit facility includes 15 banking and other financial institutions. None of the lenders are underwriting more than ten percent of the respective total commitment. We believe the number of lenders, the small percentage participation of each, and the level of availability under each facility provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

     Encore Acquisition Company Credit Agreement

     In March 2007, we entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, we amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement. The EAC Credit Agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for the account of us or any of our restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. In March 2009, the borrowing base of our revolving credit facility was reaffirmed at $1.1 billion before a reduction of $200 million solely as a result of the monetization of certain of our 2009 oil derivative contracts during the first quarter of 2009. In addition, the provisions of the EAC Credit Agreement require the borrowing base to be reduced by 33 1/3 percent of the principal amount of the 9.5% Notes. As a result, the borrowing base on the EAC Credit Agreement was reduced by $75 million in April 2009. The reductions in the borrowing base under the EAC Credit Agreement did not result in any required prepayments of indebtedness. As of September 30, 2009, the borrowing base was $825 million.

     We incur a commitment fee on the unused portion of the EAC Credit Agreement determined based on the ratio of outstanding borrowings under the EAC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the commitment fee percentage under the EAC Credit Agreement:

	Commitment
Ratio of Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     Obligations under the EAC Credit Agreement are secured by a first-priority security interest in substantially all of our restricted subsidiaries’ proved oil and natural gas reserves and in our equity interests in our restricted subsidiaries. In addition, obligations under the EAC Credit Agreement are guaranteed by our restricted subsidiaries.

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     Loans under the EAC Credit Agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.500	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

     The EAC Credit Agreement contains covenants including, among others, the following:

• a prohibition against incurring debt, subject to permitted exceptions;

• a prohibition against paying dividends or making distributions, purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on our and our restricted subsidiaries’ assets, subject to permitted exceptions;

• restrictions on merging and selling assets outside the ordinary course of business;

• restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that we maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “EAC Current Ratio”); and

• a requirement that we maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0 (the “EAC Interest Coverage Ratio”).

     In order to show EAC’s compliance with the covenants of the EAC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.

     As of September 30, 2009, EAC was in compliance with all covenants in the EAC Credit Agreement, including the following financial covenants:

		Actual Ratio as of
Financial Covenant	Required Ratio	September 30, 2009
EAC Current Ratio	Minimum 1.0 to 1.0	3.3 to 1.0
EAC Interest Coverage Ratio	Minimum 2.5 to 1.0	9.4 to 1.0

     The following table shows the calculation of the EAC Current Ratio as of September 30, 2009 ($ in thousands):

EAC current assets	$	161,219
Availability under the EAC Credit Agreement		644,700
EAC consolidated current assets	$	805,919
Divided by: EAC consolidated current liabilities	$	244,299
EAC Current Ratio		3.3

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     The following table shows the calculation of the EAC Interest Coverage Ratio for the twelve months ended September 30, 2009 ($ in thousands):

EAC Consolidated EBITDA (a)	$	599,808
Divided by: EAC consolidated net interest expense and letter of credit fees	$	63,726
EAC Interest Coverage Ratio		9.4

(a) EAC Consolidated EBITDA is defined in the EAC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. EAC Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table presents a calculation of EAC Consolidated EBITDA for the twelve months ended September 30, 2009 (in thousands) as required under the EAC Credit Agreement, together with a reconciliation of such amount to its most directly comparable financial measures calculated and presented in accordance with GAAP. This EBITDA measure should not be considered an alternative to consolidated net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. This EBITDA measure may not be comparable to similarly titled measures of another company because all companies may not calculate this measure in the same manner.

EAC consolidated net income	$	108,314
EAC unrealized non-cash hedge gain		(21,456	)
EAC consolidated net interest expense		63,726
EAC income and franchise taxes		97,025
EAC depletion, depreciation, and amortization expense		242,358
EAC non-cash equity-based compensation		11,805
EAC exploration expense		82,638
EAC other non-cash		15,398
EAC Consolidated EBITDA	$	599,808

     The EAC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.

     On September 30, 2009, there were $180 million of outstanding borrowings, $0.3 million of outstanding letters of credit, and $644.7 million of borrowing capacity under the EAC Credit Agreement. On October 27, 2009, there were $200 million of outstanding borrowings, $0.3 million of outstanding letters of credit, and $624.7 million of borrowing capacity under the EAC Credit Agreement.

     Encore Energy Partners Operating LLC Credit Agreement

     In March 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. Effective August 11, 2009, OLLC amended the OLLC Credit Agreement to, among other things, (1) increase the borrowing base from $240 million to $375 million, (2) increase the aggregate commitments of the lenders from $300 million to $475 million, and (3) increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As of September 30, 2009, the borrowing base was $375 million.

     OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.

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     Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. We consolidate the debt of ENP with that of our own; however, obligations under the OLLC Credit Agreement are non-recourse to us and our restricted subsidiaries.

     Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans (a)			Base Rate Loans (a)
Less than .50 to 1		2.250	%		1.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.500	%		1.500	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.750	%		1.750	%
Greater than or equal to .90 to 1		3.000	%		2.000	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants including, among others, the following:

• a prohibition against incurring debt, subject to permitted exceptions;

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

• restrictions on merging and selling assets outside the ordinary course of business;

• restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “ENP Current Ratio”);

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0 (the “ENP Interest Coverage Ratio”); and

• a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0 (the “ENP Leverage Ratio”).

     In order to show ENP’s and OLLC’s compliance with the covenants of the OLLC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.

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     As of September 30, 2009, ENP and OLLC were in compliance with all covenants in the OLLC Credit Agreement, including the following financial covenants:

		Actual Ratio as of
Financial Covenant	Required Ratio	September 30, 2009
ENP Current Ratio	Minimum 1.0 to 1.0	5.1 to 1.0
ENP Interest Coverage Ratio	Minimum 2.5 to 1.0	10.8 to 1.0
ENP Leverage Ratio	Maximum 3.5 to 1.0	2.2 to 1.0

     The following table shows the calculation of the ENP Current Ratio as of September 30, 2009 ($ in thousands):

ENP current assets	$	54,806
Availability under the OLLC Credit Agreement		115,000
ENP consolidated current assets	$	169,806
Divided by: ENP consolidated current liabilities	$	33,567
ENP Current Ratio		5.1

     The following table shows the calculation of the ENP Interest Coverage Ratio for the twelve months ended September 30, 2009 ($ in thousands):

ENP Consolidated EBITDA (a)	$	98,721
Divided by:
ENP consolidated interest expense and letter of credit fees	$	9,204
ENP consolidated interest income		(36	)
ENP consolidated net interest expense and letter of credit fees	$	9,168
ENP Interest Coverage Ratio		10.8

(a) ENP Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. ENP Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table shows the calculation of the ENP Leverage Ratio for the twelve months ended September 30, 2009 ($ in thousands):

ENP consolidated funded debt	$	260,000
Divided by: ENP Consolidated Adjusted EBITDA (a)	$	116,179
ENP Leverage Ratio		2.2

(a) ENP Consolidated Adjusted EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense, after giving pro forma effect to one or more acquisitions or dispositions in excess of $20 million in the aggregate. ENP Consolidated Adjusted EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table presents a calculation of ENP Consolidated EBITDA and ENP Consolidated Adjusted EBITDA for the twelve months ended September 30, 2009 (in thousands) as required under the OLLC Credit Agreement, together with a reconciliation of such amounts to their most directly comparable financial measures calculated and presented in accordance with GAAP. These EBITDA measures should not be considered an alternative to net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. These EBITDA measures may not be comparable to similarly titled measures of another company because all companies may not calculate these measures in the same manner.

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ENP consolidated net income	$	90,122
ENP unrealized non-cash hedge gain		(51,881	)
ENP consolidated net interest expense		9,168
ENP income and franchise taxes		638
ENP depletion, depreciation, amortization, and exploration expense		47,282
ENP non-cash unit-based compensation		2,108
ENP other non-cash		1,284
ENP Consolidated EBITDA		98,721
Pro forma effect of acquisitions		17,458
ENP Consolidated Adjusted EBITDA	$	116,179

     The OLLC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

     On September 30, 2009 and October 27, 2009, there were $260 million of outstanding borrowings and $115 million of borrowing capacity under the OLLC Credit Agreement.

     Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.

     Capitalization.At September 30, 2009, we had total assets of $3.7 billion and total capitalization of $2.9 billion, of which 57 percent was represented by equity and 43 percent by long-term debt. At December 31, 2008, we had total assets of $3.6 billion and total capitalization of $2.8 billion, of which 53 percent was represented by equity and 47 percent by long-term debt. The percentages of our capitalization represented by equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Critical Accounting Policies and Estimates

     Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our 2008 Annual Report on Form 10-K for information regarding our critical accounting policies and estimates.

New Accounting Pronouncements

     The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.

     The information included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2008 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.

Commodity Price Sensitivity

     Our commodity derivative contracts are discussed in Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” The counterparties to our commodity derivative contracts are a diverse group of seven institutions, all of

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which are currently rated A- or better by Standard & Poor’s and/or Fitch. As of September 30, 2009, the fair market value of our oil derivative contracts was a net asset of approximately $59.4 million and the fair market value of our natural gas derivative contracts was a net asset of approximately $11.0 million. These amounts exclude deferred premiums of $43.2 million that are not subject to changes in commodity prices. Based on our open commodity derivative positions at September 30, 2009, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net commodity derivative asset by approximately $50.4 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net commodity derivative asset by approximately $52.4 million.

Interest Rate Sensitivity

     Our long-term debt is discussed in Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” At September 30, 2009, we had total long-term debt of $1.2 billion, net of discount of $21.5 million. Of this amount, $150 million bears interest at a fixed rate of 6.25 percent, $300 million bears interest at a fixed rate of 6.0 percent, $225 million bears interest at a fixed rate of 9.5 percent, and $150 million bears interest at a fixed rate of 7.25 percent. The remaining long-term debt balance of $440 million as of September 30, 2009 consisted of outstanding borrowings under revolving credit facilities, which are subject to floating market rates of interest that are linked to the Eurodollar rate.

     At this level of floating rate debt, if the Eurodollar rate increased by 10 percent, we would incur an additional $1.0 million of interest expense per year on revolving credit facilities, and if the Eurodollar rate decreased by 10 percent, we would incur $1.0 million less. Additionally, if the discount rates on our senior notes increased by 10 percent, we estimate the fair value of our fixed rate debt at September 30, 2009 would increase from approximately $790.5 million to approximately $794.0 million, and if the discount rates on our senior notes decreased by 10 percent, we estimate the fair value would decrease to approximately $787.1 million.

     ENP’s interest rate swaps are discussed in Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of September 30, 2009, the fair market value of ENP’s interest rate swaps was a net liability of approximately $4.1 million. If the Eurodollar rate increased by 10 percent, we estimate the liability would decrease to approximately $3.9 million, and if the Eurodollar rate decreased by 10 percent, we estimate the liability would increase to approximately $4.4 million.

Item 4. Controls and Procedures

     In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2009 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

     There were no changes in our internal control over financial reporting during the third quarter of 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

     We are a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these legal proceedings will have a material adverse effect on our business, financial condition, results of operations, or liquidity.

Item 1A. Risk Factors

     In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K, which could materially affect our business, financial condition, or results of operations. The risks described in our 2008 Annual Report on Form 10-K are not the only risks we face. Unknown risks and uncertainties or risks and uncertainties that we currently believe to be immaterial may also have a material adverse effect on our business, financial condition, or results of operations.

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

Issuer Purchases of Equity Securities

     In October 2008, the Board approved a share repurchase program authorizing us to repurchase up to $40 million of our common stock. As of September 30, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the third quarter of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of September 30, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

     The following table summarizes purchases of our common stock during the third quarter of 2009:

					Total Number of		Approximate Dollar
					Shares Purchased		Value of Shares
	Total Number				as Part of Publicly		That May Yet Be
	of Shares		Average Price		Announced Plans		Purchased Under the
Month	Purchased		Paid per Share		or Programs		Plans or Programs
July		—	$	—		—
August		—	$	—		—
September		—	$	—		—
Total		—	$	—		—	$	22,830,139

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