Encore Acquisition 10-Q 2008 Q1 Quarterly report

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 March 31, 2008

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. Yes þ No o

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

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

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

Number of shares of common stock, $0.01 par value, outstanding as of May 2, 2008                                                                  53,295,415

ENCORE ACQUISITION COMPANY

INDEX

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007		1
Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007		2
Consolidated Statement of Stockholders’ Equity for the three months ended March 31, 2008		3
Consolidated Statements of Cash Flows for the three months ended March 31, 2008 and 2007		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 3. Quantitative and Qualitative Disclosures About Market Risk		42
Item 4. Controls and Procedures		42
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		43
Item 1A. Risk Factors		43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		43
Item 6. Exhibits		43
Signature		45
Form of Stock Option Agreement - Nonqualified
Form of Stock Option Agreement - Incentive
Form of Restricted Stock Award - Executive
Amendment No.1 to Second Amended and Restated Agreement
Rule 13a-14(a)/15d-14(a) Certification
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
Section 1350 Certification
Statement showing Computation of Ratios of Earnings to Fixed Charges

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

     Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and other materials filed with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. These forward-looking statements give our current expectations or forecasts of future events. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “may,” “will,” “could,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “predict,” “potential,” “pursue,” “target,” “continue,” and other words and terms of similar meaning. Readers are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Report. Our actual results may differ significantly from the results discussed in the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in “Item 1A. Risk Factors” in our Annual Report on Form 10-K and in our other filings with the SEC. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or indicated. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

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ENCORE ACQUISITION COMPANY

GLOSSARY

     The following are abbreviations and definitions of certain terms used in this Report. The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

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

• Bbl/D. One Bbl per day.

• BOE.One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

• BOE/D. One BOE per day.

• Completion.The installation of permanent equipment for the production of oil or natural gas.

• Council of Petroleum Accountants Societies (“COPAS”). A professional organization of oil and gas accountants that maintains consistency in accounting procedures and interpretations, including the procedures that are part of most joint operating agreements. These procedures establish a drilling rate and an overhead rate to reimburse the operator of a well for overhead costs, such as accounting and engineering.

• Delay Rentals.Fees paid to the lessor of an oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.

• Development Well.A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

• Dry Hole.A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed LOE and production taxes.

• EAC.Encore Acquisition Company, a Delaware corporation, together with its subsidiaries.

• ENP.Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.

• Exploratory Well.A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously producing oil or natural gas in another reservoir, or to extend a known reservoir.

• Field.An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

• Gross Acres or Gross Wells.The total acres or wells, as the case may be, in which we own a working interest.

• Lease Operations Expense (“LOE”).All direct and allocated indirect costs of producing oil and natural gas after completion of drilling. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.

• LIBOR.London Interbank Offered Rate.

• MBbl.One thousand Bbls.

• MBOE.One thousand BOE.

• MBOE/D.One thousand BOE per day.

• Mcf.One thousand cubic feet, used in reference to natural gas.

• Mcf/D.One Mcf per day.

• MMcf.One million cubic feet, used in reference to natural gas.

• Natural Gas Liquids (“NGLs”).The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

• Net Acres or Net Wells.Gross acres or wells, as the case may be, multiplied by the working interest percentage owned by us.

• Net Profits Interest (“NPI”).An interest that entitles the owner to a specified share of net profits from production of hydrocarbons.

• NYMEX.New York Mercantile Exchange.

• Oil.Crude oil, condensate, and NGLs.

• Operator.The entity responsible for the exploration, exploitation, and production of an oil or natural gas well or lease.

• Production Margin.Oil and natural gas revenues less LOE and production, ad valorem, and severance taxes.

• Productive Wells.Producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

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

• Proved Reserves.The estimated quantities of oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating

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ENCORE ACQUISITION COMPANY

	conditions.
•	Proved Undeveloped Reserves.Proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production, including unrealized production response from enhanced recovery techniques that have been proved effective by actual tests in the area and in the same reservoir.
•	SEC.The United States Securities and Exchange Commission.
•	Secondary Recovery.Enhanced recovery of oil or natural gas from a reservoir beyond the oil or natural gas that can be recovered by normal flowing and pumping operations. Secondary recovery techniques involve maintaining or enhancing reservoir pressure by injecting water, gas, or other substances into the formation. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding.
•	Successful Well.A well capable of producing oil and/or natural gas in commercial quantities.
•	Tertiary Recovery.An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gases are used as the injectant.
•	Undeveloped Acreage.Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
•	Waterflood.A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.
•	Working Interest.An interest in an oil or natural gas lease that gives the owner the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the LOE and development costs.
•	Workover.Operations on a producing well to restore or increase production.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)

	March 31,			December 31,
	2008			2007
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	205		$	1,704
Accounts receivable, net of allowance for doubtful accounts of $6,045		152,017			134,880
Inventory		30,736			16,257
Derivatives		10,259			9,722
Deferred taxes		29,316			20,420
Other		9,507			5,527
Total current assets		232,040			188,510
			��
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		2,963,795			2,845,776
Unproved properties		73,220			63,352
Accumulated depletion, depreciation, and amortization		(537,130	)		(489,004	)
		2,499,885			2,420,124
Other property and equipment		22,005			21,750
Accumulated depreciation		(10,914	)		(10,733	)
		11,091			11,017
Goodwill		60,606			60,606
Derivatives		25,606			34,579
Long-term receivables		50,363			40,945
Other		28,244			28,780
Total assets	$	2,907,835		$	2,784,561
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	17,835		$	21,548
Accrued liabilities:
Lease operations expense		17,771			15,057
Development capital		51,181			48,359
Interest		12,758			12,795
Production, ad valorem, and severance taxes		31,630			24,694
Oil and natural gas purchases		11,496			8,721
Derivatives		74,084			39,337
Oil and natural gas revenues payable		14,624			13,076
Other		16,704			21,143
Total current liabilities		248,083			204,730
Derivatives		57,335			47,091
Future abandonment cost, net of current portion		28,912			27,371
Deferred taxes		335,207			312,914
Long-term debt		1,174,377			1,120,236
Other		1,520			1,530
Total liabilities		1,845,434			1,713,872
Commitments and contingencies (see Note 16)
Minority interest in consolidated partnership		119,068			122,534
Stockholders’ 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, 52,326,023 and 53,303,464 issued and outstanding, respectively		524			534
Additional paid-in capital		531,348			538,620
Treasury stock, at cost, 28,193 and 17,690 shares, respectively		(954	)		(590	)
Retained earnings		414,493			411,377
Accumulated other comprehensive loss		(2,078	)		(1,786	)
Total stockholders’ equity		943,333			948,155
Total liabilities and stockholders’ equity	$	2,907,835		$	2,784,561

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

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

	Three months ended
	March 31,
	2008			2007
Revenues:
Oil	$	220,534		$	82,623
Natural gas		48,312			32,978
Marketing		4,056			14,941
Total revenues		272,902			130,542
Expenses:
Production:
Lease operations		40,350			30,520
Production, ad valorem, and severance taxes		27,452			12,515
Depletion, depreciation, and amortization		49,543			35,028
Exploration		5,488			11,521
General and administrative		9,687			7,360
Marketing		3,782			15,011
Derivative fair value loss		65,138			45,614
Other operating		2,506			2,565
Total expenses		203,946			160,134
Operating income (loss)		68,956			(29,592	)
Other income (expenses):
Interest		(19,760	)		(16,287	)
Other		851			431
Total other income (expenses)		(18,909	)		(15,856	)
Income (loss) before income taxes and minority interest		50,047			(45,448	)
Income tax benefit (provision)		(18,733	)		16,019
Minority interest in income of consolidated partnership		(94	)		—
Net income (loss)	$	31,220		$	(29,429	)
Net income (loss) per common share:
Basic	$	0.59		$	(0.55	)
Diluted	$	0.58		$	(0.55	)
Weighted average common shares outstanding:
Basic		52,799			53,077
Diluted		53,869			53,077

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

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ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(in thousands)
(unaudited)

	Issued																		Accumulated
	Shares of						Additional			Shares of									Other			Total
	Common			Common			Paid-in			Treasury			Treasury			Retained			Comprehensive			Stockholders’
	Stock			Stock			Capital			Stock			Stock			Earnings			Loss			Equity
Balance at December 31, 2007		53,321		$	534		$	538,620			(18	)	$	(590	)	$	411,377		$	(1,786	)	$	948,155
Exercise of stock options and vesting of restricted stock		225			2			1,636			—			—			—			—			1,638
Repurchase and retirement of common stock		(1,174	)		(12	)		(11,679	)		—			—			(27,427	)		—			(39,118	)
Purchase of treasury stock		—			—			—			(28	)		(954	)		—			—			(954	)
Cancellation of treasury stock		(18	)		—			(179	)		18			590			(411	)		—			—
Non-cash equity-based compensation		—			—			2,950			—			—			—			—			2,950
ENP distributions to MIU holders		—			—			—			—			—			(266	)		—			(266	)
Components of comprehensive income:
Net income		—			—			—			—			—			31,220			—			31,220
Change in deferred hedge loss on interest rate swaps, net of tax of $397		—			—			—			—			—			—			(1,171	)		(1,171	)
Amortization of deferred loss on commodity derivative contracts, net of tax of $549		—			—			—			—			—			—			879			879
Total comprehensive income																							30,928
Balance at March 31, 2008		52,354		$	524		$	531,348			(28	)	$	(954	)	$	414,493		$	(2,078	)	$	943,333

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

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ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

	Three months ended
	March 31,
	2008			2007
Cash flows from operating activities:
Net income (loss)	$	31,220		$	(29,429	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		49,543			35,028
Non-cash exploration expense		3,656			9,665
Deferred taxes		14,623			(15,899	)
Non-cash equity-based compensation expense		2,896			3,070
Non-cash derivative loss		62,176			53,610
Loss (gain) on disposition of assets		(23	)		226
Minority interest in income of consolidated partnership		94			—
Other		2,376			821
Changes in operating assets and liabilities, net of effects from acquisition:
Accounts receivable		(16,753	)		146
Current derivatives		(670	)		(14,732	)
Other current assets		(18,459	)		(3,685	)
Long-term derivatives		(1,196	)		(18,084	)
Other assets		(67	)		(683	)
Accounts payable		(6,303	)		(2,056	)
Other current liabilities		8,953			(2,890	)
Other noncurrent liabilities		(339	)		(49	)
Net cash provided by operating activities		131,727			15,059
Cash flows from investing activities:
Proceeds from disposition of assets		184			1,214
Purchases of other property and equipment		(1,054	)		(606	)
Acquisition of oil and natural gas properties		(30,780	)		(438,568	)
Development of oil and natural gas properties		(97,802	)		(101,924	)
Net advances to working interest partners		(8,972	)		(13,382	)
Net cash used in investing activities		(138,424	)		(553,266	)
Cash flows from financing activities:
Repurchase of common stock		(39,118	)		—
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		684			60
Proceeds from long-term debt, net of issuance costs		357,274			606,778
Payments on long-term debt		(303,500	)		(75,027	)
Payment of commodity derivative contract premiums		(8,534	)		(5,350	)
ENP distributions to holders of MIUs and public units		(4,198	)		—
Change in cash overdrafts		2,590			11,609
Net cash provided by financing activities		5,198			538,070
Decrease in cash and cash equivalents		(1,499	)		(137	)
Cash and cash equivalents, beginning of period		1,704			763
Cash and cash equivalents, end of period	$	205		$	626

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

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ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. About EAC

     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 of Montana and North Dakota;

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

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

• the Mid-Continent area, which includes the Arkoma and Anadarko Basins of 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 wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

     In February 2007, EAC formed ENP to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. In September 2007, ENP completed its initial public offering (“IPO”). As of March 31, 2008 and December 31, 2007, EAC owned approximately 67.3 percent and 58.0 percent, respectively, of ENP’s common units, as well as all of the interests of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and ENP’s general partner, which is an indirect wholly owned non-guarantor subsidiary of EAC. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force 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”, the financial position, results of operations, and cash flows of ENP are consolidated with those of EAC. EAC elected to account for gains on ENP’s issuance of common units as capital transactions as permitted by Staff Accounting Bulletin (“SAB”) Topic 5H, “Accounting for Sales of Stock by a Subsidiary”. See “Note 18. ENP” for additional discussion.

     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, its financial position as of March 31, 2008, and results of operations and cash flows for the three months ended March 31, 2008 and 2007. 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 related notes thereto included in EAC’s 2007 Annual Report on Form 10-K.

Minority Interest

     As presented in the accompanying Consolidated Balance Sheets, “Minority interest in consolidated partnership” as of March 31, 2008 and December 31, 2007 of $119.1 million and $122.5 million, respectively, represents third-party ownership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Minority interest in income of consolidated partnership” for the three months ended March 31, 2008 of $0.1 million represents the net income of ENP attributable to third-party owners.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, certain amounts on the accompanying Consolidated Statements of Operations and Consolidated Statements of Cash Flows have been either combined or classified in more detail.

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

New Accounting Pronouncements

Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS 157”)

     In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 157. SFAS 157 standardizes the definition of fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not require any new fair value measurements. SFAS 157 is prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”), which delays the effective date of SFAS 157 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 for all instruments within the scope of FSP 157-2, including but not limited to, its asset retirement obligations and goodwill. EAC will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities, did not have a material impact on EAC’s results of operations or financial condition. See “Note 7. Fair Values of Financial Assets and Liabilities” for additional discussion.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115” (“SFAS 159”)

     In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. EAC did not elect the fair value option for eligible instruments and therefore, the adoption of SFAS 159 on January 1, 2008 did not have a material impact on EAC’s results of operations or financial condition.

FSP Interpretation 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”)

     In April 2007, the FASB issued FSP FIN 39-1. FSP FIN 39-1 amends FASB Interpretation (“FIN”) No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007. The adoption of FSP FIN 39-1 on January 1, 2008 did not have an impact on EAC’s results of operations or financial condition. EAC will assess the impact of electing the fair value option for any newly acquired eligible instruments. Electing the fair value option for such instruments could have a material impact on EAC’s future results of operations or financial condition.

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

     In December 2007, the FASB issued SFAS 141R. SFAS 141R is a revision of SFAS No. 141, “Business Combinations” (“SFAS 141”). SFAS 141R amends SFAS 141 by requiring an acquirer to recognize: (i) the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at fair value as of the acquisition date, (ii) a gain attributable to any “negative goodwill” in a bargain purchase, and (iii) an expense related to acquisition costs. SFAS 141R is effective for fiscal years beginning on or after December 15, 2008. EAC does not expect the adoption of SFAS 141R to have a material impact on its current results of operations or financial condition. However, future results of operations or financial condition may be materially affected if a significant acquisition is consummated subsequent to the effective date.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51” (“SFAS 160”)

     In December 2007, the FASB issued SFAS 160. SFAS 160 amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. EAC expects

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

the adoption of SFAS 160 to have a material impact on how it accounts for and discloses the noncontrolling interest in ENP. “Minority interest in consolidated partnership” in EAC’s Consolidated Balance Sheets will be reflected as a component of stockholders’ equity and “Minority interest in income of consolidated partnership” in EAC’s Consolidated Statements of Operations will be moved to below net income.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”)

     In March 2008, the FASB issued SFAS 161. SFAS 161 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” to require enhanced disclosures about an entity’s derivative and hedging activities and thereby improve the transparency of financial reporting. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008 with early application permitted. The adoption of SFAS 161 is not expected to impact EAC’s results of operations or financial condition.

Note 3. Acquisitions and Dispositions

Acquisitions

     On January 23, 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) to acquire oil and natural gas properties and related assets in the Williston Basin of Montana and North Dakota. The closing of the Williston Basin acquisition occurred on April 11, 2007 after which time the operations have been included with those of EAC. The Williston Basin acquisition was treated as a reverse like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended, and I.R.S. Revenue Procedure 2000-37 with the Mid-Continent disposition discussed below.

     The total purchase price for the Williston Basin assets was approximately $392.1 million, including transaction costs of approximately $1.3 million. The calculation of the total purchase price and the allocation to the fair value of the Williston Basin assets acquired and liabilities assumed from Anadarko are as follows (in thousands):

Calculation of total purchase price:
Cash paid to Anadarko	$	390,728
Transaction costs		1,333
Total purchase price	$	392,061
Allocation of purchase price to the fair value of net assets acquired:
Proved properties, including wells and related equipment	$	383,909
Unproved properties		16,134
Accounts receivable		3,008
Inventory		805
Total assets acquired		403,856
Current liabilities		8,289
Future abandonment cost and assumed liabilities		3,506
Total liabilities assumed		11,795
Fair value of net assets acquired	$	392,061

     On January 16, 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included oil and natural gas properties and related assets in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas properties and related assets in the Gooseberry field in Park County, Wyoming. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, and the rights and duties under the purchase and sale agreement relating to the Gooseberry assets to Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned guarantor subsidiary of EAC. The closing of the Big Horn Basin acquisition occurred on March 7, 2007 after which time the operations have been included with those of EAC.

7

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

     The total purchase price for the Big Horn Basin assets was approximately $393.6 million, including transaction costs of approximately $1.3 million. The calculation of the total purchase price and the allocation to the fair value of the Big Horn Basin assets acquired and liabilities assumed from Anadarko are as follows (in thousands):

Calculation of total purchase price:
Cash paid to Anadarko	$	392,289
Transaction costs		1,288
Total purchase price	$	393,577
Allocation of purchase price to the fair value of net assets acquired:
Proved properties, including wells and related equipment	$	395,606
Intangibles		4,225
Accounts receivable		1,673
Other property and equipment		346
Total assets acquired		401,850
Current liabilities		1,300
Future abandonment cost and assumed liabilities		6,973
Total liabilities assumed		8,273
Fair value of net assets acquired	$	393,577

     Proved properties include the fair value of proved leasehold costs, lease and well equipment (including flue gas reinjection facilities used to maintain reservoir pressure by compressing and reinjecting the gas produced), and pipelines used primarily to transport production from the acquired fields. NGLs are produced as a byproduct of the flue gas tertiary recovery project and are sold at market prices. The revenues generated by NGLs are included in “Oil revenues” in the accompanying Consolidated Statements of Operations. Third-party revenues and expenses related to the pipelines are included in “Marketing revenues” and “Marketing expenses”, respectively, in the accompanying Consolidated Statements of Operations.

     EAC financed the acquisitions of the Gooseberry field and Williston Basin assets through borrowings under its revolving credit facility. ENP financed the acquisition of the Elk Basin assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, LLC, a Delaware corporation and direct wholly owned subsidiary of EAC, and borrowings under its revolving credit facility. See “Note 9. Long-Term Debt” for additional discussion of EAC’s and ENP’s revolving credit facilities. See “Note 15. Financial Statements of Subsidiary Guarantors” for a discussion of EAC’s guarantor and non-guarantor subsidiaries.

Dispositions

     On June 29, 2007, EAC completed the sale of certain oil and natural gas properties in the Mid-Continent area and in July 2007, additional Mid-Continent properties that were subject to preferential rights were sold. EAC received total net proceeds of approximately $294.8 million, after deducting transaction costs of approximately $3.6 million, and recorded a loss on sale of approximately $7.4 million. The disposed properties included certain properties in the Anadarko and Arkoma basins of Oklahoma. EAC retained material oil and natural gas interests in other properties in these basins and remains active in those areas. Proceeds from the Mid-Continent disposition were used to reduce outstanding borrowings under EAC’s revolving credit facility.

Pro Forma

     The following unaudited pro forma condensed financial data was derived from the historical financial statements of EAC and from the accounting records of Anadarko to give effect to the Big Horn Basin and Williston Basin asset acquisitions and the Mid-Continent disposition as if they had occurred on January 1, 2007. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Big Horn Basin and Williston Basin asset acquisitions and the Mid-Continent disposition taken place as of the date indicated and are not intended to be a projection of future results.

8

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

	Three months ended
	March 31, 2007
	(in thousands, except per
	share amounts)
Pro forma total revenues	$	155,579
Pro forma net loss	$	(30,646	)
Pro forma net loss per common share:
Basic	$	(0.58	)
Diluted	$	(0.58	)

Note 4. Inventory

     Inventory is composed of 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. EAC’s inventory consisted of the following as of the dates indicated:

	March 31,		December 31,
	2008		2007
	(in thousands)
Materials and supplies	$	12,800	$	11,567
Oil in pipelines		17,936		4,690
Total inventory	$	30,736	$	16,257

Note 5. Proved Properties

     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties” include leasehold costs and wells and related equipment, both completed and in process, and consisted of the following as of the dates indicated:

	March 31,		December 31,
	2008		2007
	(in thousands)
Proved leasehold costs	$	1,363,008	$	1,346,516
Wells and related equipment — Completed		1,480,436		1,408,512
Wells and related equipment — In process		120,351		90,748
Total proved properties	$	2,963,795	$	2,845,776

Note 6. Derivative Financial Instruments

     As of March 31, 2008, EAC had $70.6 million of deferred premiums payable of which $30.7 million is long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $39.9 million is 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 April 2008 to January 2010. EAC recorded these premiums at their net present value at the time the contracts were entered into and accretes that value up to the eventual settlement price by recording interest expense each period.

Commodity Derivative Contracts — Mark-to-Market Accounting

     In order to partially finance the cost of premiums on certain purchased floors, EAC may sell floors with a strike price below the strike price of the purchased floor. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. As with EAC’s other commodity derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss” in the accompanying Consolidated Statements of Operations. In the following table, the purchased floor component of these floor

9

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

spreads has been included with EAC’s other floor contracts and the short floor component is shown separately as negative volumes.

     The following tables summarize EAC’s open commodity derivative contracts as of March 31, 2008:

Oil Derivative Contracts

	Daily		Average		Daily			Average		Daily		Average		Daily		Average
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price
	(Bbls)		(per Bbl)		(Bbls)			(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)
April — June 2008
		19,880	$	83.77		—		$	—		2,440	$	101.99		—	$	—
		6,000		71.67		—			—		2,000		96.65		—		—
		9,500		61.32		—			—		—		—		—		—
		3,000		56.67		(4,000	)		50.00		—		—		1,000		58.59
Second Half 2008
		14,880		83.36		—			—		2,440		101.99		5,000		91.56
		6,000		71.67		—			—		2,000		96.65		—		—
		5,500		62.27		—			—		—		—		—		—
		3,000		56.67		(4,000	)		50.00		—		—		—		—
2009
		13,380		80.00		—			—		440		97.75		2,000		90.46
		2,250		74.11		—			—		—		—		3,000		89.22
		—		—		(5,000	)		50.00		—		—		1,000		68.70
2010
		880		80.00		—			—		440		93.80		—		—
		2,000		75.00		—			—		1,000		77.23		—		—
2011
		1,880		80.00		—			—		1,440		95.41		—		—
		1,000		70.00		—			—		—		—		—		—

Natural Gas Derivative Contracts

	Daily		Average		Daily		Average		Daily		Average		Daily		Average
	Floor		Floor		Short Floor		Short Floor		Cap		Cap		Swap		Swap
Period	Volume		Price		Volume		Price		Volume		Price		Volume		Price
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)
April — Dec. 2008
		6,300	$	8.18		—	$	—		6,300	$	9.52		5,000	$	8.14
		11,300		7.38		—		—		7,500		8.35		5,000		7.47
		20,000		6.35		—		—		—		—		—		—
2009
		3,800		8.20		—		—		3,800		9.83		—		—
		3,800		7.20		—		—		—		—		—		—
2010
		3,800		8.20		—		—		3,800		9.58		—		—
		3,800		7.20		—		—		—		—		—		—

Interest Rate Swaps

     In the first quarter of 2008, as a result of the increase in debt levels, ENP entered into interest rate swaps whereby it swapped $100 million of floating rate debt on its revolving credit facility to a weighted average fixed rate of 3.06 percent and an expected margin of 1.25 percent. These interest rate swaps were designated as cash flow hedges. The following table summarizes ENP’s open interest rate swaps as of March 31, 2008:

10

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

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
March 2008-January 2011	$	50,000		3.1610	%	1 month LIBOR
March 2008-January 2011		25,000		2.9650	%	1 month LIBOR
March 2008-January 2011		25,000		2.9613	%	1 month LIBOR

     During the three months ended March 31, 2008, settlements of interest rate swaps reduced ENP’s interest expense by approximately $18,000.

Current Period Impact

     As a result of commodity derivative contracts that were previously designated as hedges, EAC recognized a pre-tax reduction in oil and natural gas revenues of approximately $1.4 million and $13.4 million during the three months ended March 31, 2008 and 2007, respectively. EAC also recognized derivative fair value gains and losses related to (i) changes in the market value of commodity derivative contracts, (ii) settlements on commodity derivative contracts, (iii) premium amortization, and (iv) changes in fair value of interest rate swaps prior to designation. The following table summarizes the components of derivative fair value loss for the periods indicated:

	Three months ended March 31,
	2008			2007
	(in thousands)
Mark-to-market loss on commodity derivative contracts	$	46,779		$	47,445
Premium amortization		15,513			6,364
Change in fair value of interest rate swaps prior to designation		(381	)		—
Settlements on commodity derivative contracts		3,227			(8,195	)
Total derivative fair value loss	$	65,138		$	45,614

Accumulated Other Comprehensive Loss (“AOCL”)

     At March 31, 2008, AOCL consisted of deferred losses, net of tax, on commodity derivative contracts that were previously designated as hedges of $0.9 million and deferred losses, net of tax, on interest rate swaps, which are designated as hedges, of $1.2 million. At December 31, 2007, AOCL consisted entirely of deferred losses, net of tax, on commodity derivative contracts that were previously designated as hedges of $1.8 million.

     EAC expects to reclassify the remaining $1.4 million of deferred losses associated with its dedesignated commodity derivative contracts from AOCL to oil and natural gas revenues by June 30, 2008. EAC also expects to reclassify the remaining $0.5 million of income taxes associated with its dedesignated commodity derivative contracts from AOCL to income tax benefit by June 30, 2008. EAC expects to reclassify $0.5 million of deferred losses associated with ENP’s interest rate swaps from AOCL to interest expense during the twelve months ending March 31, 2009. EAC also expects to reclassify $0.1 million of income taxes associated with ENP’s interest rate swaps from AOCL to income tax benefit during the twelve months ending March 31, 2009.

Note 7. Fair Values of Financial Assets and Liabilities

     As discussed in “Note 2. Basis of Presentation”, effective January 1, 2008, EAC adopted SFAS 157, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.

     As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). EAC utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. EAC primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Accordingly, EAC utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. EAC has reviewed its recurring transactions and found that its markets and instruments are fairly liquid and

11

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

has established that EAC is able to transact at the mid-point of the bid/ask spread. EAC is able to classify fair value balances based on the observability of those inputs.

     SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

• Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

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

• Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. EAC performs an analysis of all instruments subject to SFAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

     The carrying values of Cash and cash equivalents, Accounts receivable, net, Long-term receivables, outstanding borrowings under revolving credit facilities (included in Long-term debt), Accounts payable, and Accrued liabilities included in the accompanying Consolidated Balance Sheets approximated fair value at March 31, 2008. These assets and liabilities are not presented in the following tables.

     The following table sets forth by level within the fair value hierarchy EAC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

				Fair Value Measurements at Reporting Date Using
				Quoted Prices
				in Active		Significant
				Markets for		Other			Significant
				Identical		Observable			Unobservable
				Assets		Inputs			Inputs
Description	March 31, 2008			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	(30,444	)	$	—	$	(30,444	)	$	—
Oil derivative contracts — floors and caps		15,685			—		—			15,685
Natural gas derivative contracts — swaps		(5,279	)		—		(5,279	)		—
Natural gas derivative contracts — floors and caps		(3,740	)		—		—			(3,740	)
Interest rate swaps		(1,186	)		—		(1,186	)		—
Total	$	(24,964	)	$	—	$	(36,909	)	$	11,945

     The following table provides a reconciliation of the fair value of EAC’s financial assets and liabilities that were accounted for at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three months ended March 31, 2008:

12

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

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
				Natural Gas
	Oil Derivative			Derivative
	Contracts —			Contracts —
	Floors and Caps			Floors and Caps			Total
	(in thousands)
Balance at January 1, 2008	$	16,647		$	7,081		$	23,728
Total gains (losses):
Included in earnings		(2,158	)		(11,491	)		(13,649	)
Purchases, issuances, and settlements		1,196			670			1,866
Balance at March 31, 2008	$	15,685		$	(3,740	)	$	11,945
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	$	(2,158	)	$	(11,491	)	$	(13,649	)

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

     The following methods and assumptions were used to estimate the fair values of the financial assets and liabilities in the above tables that are accounted for at fair value on a recurring basis. As per the requirements under SFAS 157, all fair values reflected in the table above and on the accompanying Consolidated Balance Sheet have been adjusted for non-performance risk. The adjustment to fair value related to non-performance risk as of March 31, 2008 was a reduction of the net liability value of approximately $0.3 million.

     Level 1 Fair Value Measurements

     As of March 31, 2008, EAC did not have any assets or liabilities measured under the Level 1 fair value hierarchy.

     Level 2 Fair Value Measurements

     Oil and natural gas derivative contracts — swaps.The fair values of the oil and natural gas derivative contracts were estimated using a combined income and market-based valuation methodology based upon forward commodity prices. Forward curves were obtained from independent pricing services reflecting broker market quotes.

     Interest rate swaps.The fair values of the interest rate swaps were estimated using a combined income and market-based valuation methodology based upon forward interest rate yield curves and credit. The curves were obtained from independent pricing services reflecting broker market quotes.

     Level 3 Fair Value Measurements

     Oil and natural gas derivative contracts — floors and caps.The fair values of the oil and natural gas derivative contracts were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets and, accordingly, these floors and caps have been categorized as Level 3 within the valuation hierarchy.

Note 8. Asset Retirement Obligations

     EAC’s asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. As of March 31, 2008 and December 31, 2007, EAC had $7.5 million and $6.7 million, respectively, held in escrow from which funds are released only for reimbursement of plugging and abandonment expenses on its Bell Creek property, which is included in other long-term assets in the accompanying Consolidated Balance Sheets. The following table summarizes the changes in asset retirement obligations for the three months ended March 31, 2008 (in thousands):

13

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

Future abandonment liability at January 1, 2008	$	28,079
Wells drilled		45
Acquisition of properties		13
Accretion of discount		343
Plugging and abandonment costs incurred		(335	)
Revision of previous estimates		1,558
Future abandonment liability at March 31, 2008	$	29,703

     As of March 31, 2008, $28.9 million of EAC’s asset retirement obligations is long-term and recorded in “Future abandonment cost, net of current portion” and $0.8 million is current and included in “Other current liabilities” on the accompanying Consolidated Balance Sheets.

Note 9. Long-Term Debt

     EAC’s long-term debt consisted of the following as of the dates indicated:

	March 31,		December 31,
	2008		2007
	(in thousands)
Revolving credit facilities	$	580,000	$	526,000
6.25% Senior Subordinated Notes due April 15, 2014		150,000		150,000
6.0% Senior Subordinated Notes due July 15, 2015, net of unamortized discount of $4,322 and $4,440, respectively		295,678		295,560
7.25% Senior Subordinated Notes due December 1, 2017, net of unamortized discount of $1,301 and $1,324, respectively		148,699		148,676
Total	$	1,174,377	$	1,120,236

Revolving Credit Facilities

     Encore Acquisition Company Senior Secured Credit Agreement

     EAC is party to a five-year amended and restated credit agreement dated March 7, 2007 (as amended, the “EAC Credit Agreement”). 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. As of March 31, 2008, the borrowing base was $870 million.

     As of March 31, 2008, there were $415 million of outstanding borrowings and $435 million of borrowing capacity under the EAC Credit Agreement. As of March 31, 2008, there were $20 million of outstanding letters of credit, all of which related to EAC’s joint development agreement with ExxonMobil Corporation (“ExxonMobil”). See “Note 16. Commitments and Contingencies” for additional discussion of this agreement.

     Effective February 7, 2008, EAC amended the EAC Credit Agreement to, among other things, provide that certain negative covenants in the EAC Credit Agreement restricting hedge transactions do not apply to any oil and natural gas hedge transaction that is a floor or put transaction not requiring any future payments or delivery by EAC or any of its restricted subsidiaries.

     As of March 31, 2008, EAC was in compliance with all covenants of the EAC Credit Agreement.

     Encore Energy Partners Operating LLC Credit Agreement

     OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 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 March 31, 2008, the borrowing base was $240 million.

     As of March 31, 2008, there were $165 million of outstanding borrowings and $74.9 million of borrowing capacity under the OLLC Credit Agreement. As of March 31, 2008, there were $0.1 million of outstanding letters of credit.

14

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

     As of March 31, 2008, OLLC was in compliance with all covenants of the OLLC Credit Agreement.

Note 10. Stockholders’ Equity

     In December 2007, EAC announced that its Board of Directors (the “Board”) had approved a new share repurchase program authorizing the purchase of up to $50 million of EAC’s common stock. As of March 31, 2008, EAC had repurchased and retired 1,174,691 shares of its outstanding common stock for approximately $39.1 million, or an average price of $33.30 per share, under the share repurchase program.

Note 11. Income Taxes

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

	Three months ended
	March 31,
	2008			2007
	(in thousands)
Federal:
Current	$	(3,544	)	$	120
Deferred		(13,804	)		15,750
Total federal		(17,348	)		15,870
State, net of federal benefit/expense:
Current		(566	)		—
Deferred		(819	)		149
Total state		(1,385	)		149
Income tax benefit (provision)	$	(18,733	)	$	16,019

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

	Three months ended
	March 31,
	2008			2007
	(in thousands)
Income (loss) before income taxes, net of minority interest	$	49,953		$	(45,448	)
Income tax at the Federal statutory rate	$	(17,484	)	$	15,907
State income taxes, net of federal benefit/expense		(1,328	)		1,124
Change in estimated future state tax rate		—			(972	)
Nondeductible deferred compensation		(263	)		—
Permanent and other		342			(40	)
Income tax benefit (provision)	$	(18,733	)	$	16,019

     At March 31, 2008 and 2007, EAC had net operating loss (“NOL”) carryforwards related to federal and state income taxes of $14.0 million and $26.0 million, respectively, which are available to offset future regular taxable income, if any. At March 31, 2008, EAC also had alternative minimum tax (“AMT”) credits of $2.7 million, which are available to reduce future regular tax liabilities in excess of AMT. EAC believes it is more likely than not that these NOL carryforwards will offset future taxable income prior to their expiration. The AMT credits have no expiration. Therefore, a valuation allowance against these deferred tax assets is not considered necessary.

     EAC has no tax positions that do not meet the “highly certain positions” threshold prescribed by FIN No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109”. 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

15

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

related to income taxes in “Other expense” on its Consolidated Statements of Operations. For the three months ended March 31, 2008 and 2007, EAC recorded only a nominal amount of interest and penalties on certain tax positions.

Note 12. Earnings Per Share (“EPS”)

     The following table reflects EAC’s EPS computations for the periods indicated:

	Three months ended
	March 31,
	2008 (b)		2007
	(in thousands, except per share data)
Numerator:
Net income (loss)	$	31,220	$	(29,429	)
Denominator:
Denominator for basic EPS:
Weighted average shares outstanding		52,799		53,077
Effect of dilutive options and restricted stock (a)		1,070		—
Denominator for diluted EPS		53,869		53,077
Net income (loss) per common share:
Basic	$	0.59	$	(0.55	)
Diluted	$	0.58	$	(0.55	)

(a)

For the three months ended March 31, 2008 and 2007, options to purchase 121,653 and 1,498,202 shares of common stock, respectively, were outstanding but not included in the above calculation of diluted EPS because their effect would have been antidilutive.

(b)

For the three months ended March 31, 2008, EAC considered the impact of the conversion of vested management incentive units held by certain executive officers of GP LLC. The conversion of the management incentive units into limited partner units of ENP would reduce EAC’s share of ENP’s earnings. For the three months ended March 31, 2008, the impact of this conversion would have been immaterial and was thus excluded from the above calculation of diluted EPS.

Note 13. Incentive Stock Plans

     During 2000, the Board and stockholders approved the 2000 Incentive Stock Plan (the “EAC Plan”). The EAC Plan was amended and restated effective March 18, 2004. The purpose of the EAC 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 shareholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the EAC Plan. The total number of shares of common stock reserved for issuance pursuant to the EAC Plan is 4,500,000. As of March 31, 2008, there were 454,721 shares available for issuance under the EAC Plan. 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 EAC Plan. The EAC 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 Restricted Stock Award Committee whose sole member is Jon S. Brumley, EAC’s Chief Executive Officer and President. The Restricted 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 EAC Plan contains the following individual limits:

• an employee may not be granted awards covering or relating to more than 225,000 shares of common stock in any calendar year;

• a non-employee director may not be granted awards covering or relating to more than 15,000 shares of common stock in 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 a value determined on the grant date in excess of $1.0 million.

16

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

     All options granted under the EAC Plan have a strike price equal to the fair market value of EAC’s common stock on the grant date. Additionally, all options have a ten-year life and vest over a three-year period. Restricted stock granted under the EAC Plan vests over varying periods from one to five years, subject to performance-based vesting for certain members of senior management.

     The non-cash stock-based compensation expense related to the EAC Plan recorded in the accompanying Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007 was $1.8 million and $3.1 million, respectively. The income tax benefit of the non-cash stock-based compensation cost related to the EAC Plan recorded in the accompanying Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007 was $0.7 million and $1.1 million, respectively. During the three months ended March 31, 2008 and 2007, EAC also capitalized $0.4 million and $0.3 million, respectively, of non-cash stock-based compensation cost as a component of “Properties and equipment” in the accompanying Consolidated Balance Sheets. Non-cash stock-based compensation expense has been allocated to LOE and general and administrative (“G&A”) expense based on the allocation of the respective employees’ cash compensation.

     See “Note 18. ENP” for a discussion of ENP’s unit-based compensation plan.

Stock Options

     The fair value of options granted during the three months ended March 31, 2008 and 2007 was estimated on the grant date using a Black-Scholes option valuation model based on the assumptions noted in the following table. The expected volatility is based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the options. For options granted prior to January 1, 2008, EAC used the “simplified” method prescribed by SAB No. 107, “Valuation of Share-Based Payment Arrangements for Public Companies” to estimate the expected term of the options, which is calculated as the average midpoint between each vesting date and the life of the option. For options granted subsequent to December 31, 2007, EAC determined the expected life 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.

	Three months ended March 31,
	2008			2007
Expected volatility		33.7	%		35.7	%
Expected dividend yield		0.0	%		0.0	%
Expected term (in years)		6.25			6.00
Risk-free interest rate		3.0	%		4.8	%

     The following table summarizes the changes in the number of EAC’s outstanding options and the related weighted average strike prices during the three months ended March 31, 2008:

						Weighted
				Weighted		Average		Aggregate
	Number of			Average		Remaining		Intrinsic
	Options			Strike Price		Contractual Term		Value
								(in thousands)
Outstanding at January 1, 2008		1,381,782		$	16.03
Granted		176,170			33.76
Forfeited or expired		(11,264	)		30.61
Exercised		(12,857	)		22.35
Outstanding at March 31, 2008		1,533,831			17.90		5.8	$	34,322
Exercisable at March 31, 2008		1,209,774			14.54		4.9		31,134

     The weighted average fair value per share of options granted during the three months ended March 31, 2008 and 2007 was $13.15 and $11.16, respectively. The total intrinsic value of options exercised during the three months ended March 31, 2008 and 2007 was $0.2 million and $0.3 million, respectively. During the three months ended March 31, 2008 and 2007, EAC received proceeds from the exercise of stock options of $0.3 million and $0.4 million, respectively, and realized tax benefits related to stock options of $0.7 million and $0.2 million, respectively. At March 31, 2008, EAC had $2.4 million of total

17

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

unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 2.5 years.

Restricted Stock

     During the three months ended March 31, 2008 and 2007, EAC recognized expense related to restricted stock of $1.5 million and $2.6 million, respectively, and realized tax benefits related to restricted stock of $0.5 million and $1.0 million, respectively. The following table summarizes the changes in the number of EAC’s unvested restricted stock awards and their related weighted average grant date fair value for the three months ended March 31, 2008:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2008		918,338		$	27.07
Granted		266,042			33.76
Vested		(212,586	)		26.32
Forfeited		(26,161	)		28.89
Outstanding at March 31, 2008		945,633			29.07

     As of March 31, 2008, there were 878,394 shares of unvested restricted stock the vesting of which is dependent only on the passage of time and continued employment, 193,471 shares of which were granted during the three months ended March 31, 2008. Additionally, as of March 31, 2008, there were 67,239 shares of unvested restricted stock the vesting of which is dependent not only on the passage of time and continued employment, but on the achievement of certain performance measures, all of which were granted during the three months ended March 31, 2008.

     As of March 31, 2008, EAC had $12.4 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 3.1 years. None of EAC’s unvested restricted stock is subject to variable accounting. During the three months ended March 31, 2008 and 2007, there were 212,586 shares and 83,668 shares, respectively, of restricted stock that vested and employees elected to satisfy minimum tax withholding obligations related thereto by allowing EAC to withhold 28,193 shares and 15,743 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.

Note 14. Comprehensive Income (Loss)

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

	Three months ended
	March 31,
	2008			2007
	(in thousands)
Net income (loss)	$	31,220		$	(29,429	)
Amortization of deferred loss on commodity derivative contracts		879			8,181
Change in deferred hedge loss on interest rate swaps		(1,171	)		—
Comprehensive income (loss)	$	30,928		$	(21,248	)

Note 15. Financial Statements of Subsidiary Guarantors

     In February 2007, EAC formed certain non-guarantor subsidiaries in connection with the formation of ENP. See “Note 18. ENP” for additional discussion of ENP’s formation and other matters. As of March 31, 2008 and December 31, 2007, certain of EAC’s wholly owned subsidiaries were 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. In accordance with SEC rules, EAC has prepared condensed consolidating financial statements in order to quantify the financial position, results of operations, and cash flows of the subsidiary guarantors.

18

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

The following Condensed Consolidating Balance Sheets as of March 31, 2008 and December 31, 2007 and Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2008 and 2007 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 March 31, 2008, EAC’s guarantor subsidiaries were:

• EAP Properties, Inc.;

• EAP Operating, LLC;

• Encore Operating; and

• Encore Operating Louisiana, LLC.

As of March 31, 2008, EAC’s non-guarantor subsidiaries were:

• ENP;

• OLLC;

• Encore Partners GP Holdings LLC;

• Encore Partners LP Holdings LLC;

• GP LLC; and

• Encore Clear Fork Pipeline LLC.

     All intercompany investments in, loans due to/from, subsidiary equity, and 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 of EAC.

19

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

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

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	4		$	201		$	—		$	205
Other current assets		32,140		171,288			31,195			(2,788	)		231,835
Total current assets		32,140		171,292			31,396			(2,788	)		232,040
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		2,457,690			506,105			—			2,963,795
Unproved properties		—		72,941			279			—			73,220
Accumulated depletion, depreciation, and amortization		—		(464,790	)		(72,340	)		—			(537,130	)
		—		2,065,841			434,044			—			2,499,885
Other property and equipment, net		—		10,527			564			—			11,091
Other assets, net		14,269		131,450			19,100			—			164,819
Investment in subsidiaries		2,257,054		(43,143	)		—			(2,213,911	)		—
Total assets	$	2,303,463	$	2,335,967		$	485,104		$	(2,216,699	)	$	2,907,835
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	16,054	$	206,561		$	28,256		$	(2,788	)	$	248,083
Deferred taxes		334,995		—			212			—			335,207
Long-term debt		1,009,377		—			165,000			—			1,174,377
Other liabilities		—		60,160			27,607			—			87,767
Total liabilities		1,360,426		266,721			221,075			(2,788	)		1,845,434
Commitments and contingencies (see Note 16)
Minority interest in consolidated partnership		—		—			119,068			—			119,068
Total stockholders’ equity		943,037		2,069,246			144,961			(2,213,911	)		943,333
Total liabilities and stockholders’ equity	$	2,303,463	$	2,335,967		$	485,104		$	(2,216,699	)	$	2,907,835

20

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

CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2007
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	1	$	1,700		$	3		$	—		$	1,704
Other current assets		535,221		437,852			21,053			(807,320	)		186,806
Total current assets		535,222		439,552			21,056			(807,320	)		188,510
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		2,467,606			378,170			—			2,845,776
Unproved properties		—		63,352			—			—			63,352
Accumulated depletion, depreciation, and amortization		—		(451,343	)		(37,661	)		—			(489,004	)
		—		2,079,615			340,509			—			2,420,124
Other property and equipment, net		—		10,610			407			—			11,017
Other assets, net		14,899		121,904			28,107			—			164,910
Investment in subsidiaries		2,090,471		20,611			—			(2,111,082	)		—
Total assets	$	2,640,592	$	2,672,292		$	390,079		$	(2,918,402	)	$	2,784,561
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	306,787	$	687,351		$	17,885		$	(807,293	)	$	204,730
Deferred taxes		312,914		—			—			—			312,914
Long-term debt		1,072,736		—			47,500			—			1,120,236
Other liabilities		—		49,461			26,531			—			75,992
Total liabilities		1,692,437		736,812			91,916			(807,293	)		1,713,872
Commitments and contingencies (see Note 16)
Minority interest in consolidated partnership		—		—			122,534			—			122,534
Total stockholders’ equity		948,155		1,935,480			175,629			(2,111,109	)		948,155
Total liabilities and stockholders’ equity	$	2,640,592	$	2,672,292		$	390,079		$	(2,918,402	)	$	2,784,561

21

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

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2008
(in thousands)

				Guarantor		Non-Guarantor						Consolidated
	Parent			Subsidiaries		Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	183,339	$	37,195		$	—		$	220,534
Natural gas		—			41,310		7,002			—			48,312
Marketing		—			1,197		2,859			—			4,056
Total revenues		—			225,846		47,056			—			272,902
Expenses:
Production:
Lease operations		—			34,292		6,058			—			40,350
Production, ad valorem, and severance taxes		—			22,654		4,798			—			27,452
Depletion, depreciation, and amortization		—			40,423		9,120			—			49,543
Exploration		—			5,459		29			—			5,488
General and administrative		3,034			4,750		2,922			(1,019	)		9,687
Marketing		—			1,389		2,393			—			3,782
Derivative fair value loss		—			49,551		15,587			—			65,138
Other operating		41			2,114		351			—			2,506
Total expenses		3,075			160,632		41,258			(1,019	)		203,946
Operating income (loss)		(3,075	)		65,214		5,798			1,019			68,956
Other income (expenses):
Interest		(18,120	)		—		(1,640	)		—			(19,760	)
Equity income (loss) from subsidiaries		70,755			1,960		—			(72,715	)		—
Other		37			1,816		17			(1,019	)		851
Total other income (expenses)		52,672			3,776		(1,623	)		(73,734	)		(18,909	)
Income (loss) before income taxes and minority interest		49,597			68,990		4,175			(72,715	)		50,047
Income tax provision		(18,643	)		—		(90	)		—			(18,733	)
Minority interest in income of consolidated partnership		—			—		—			(94	)		(94	)
Net income (loss)		30,954			68,990		4,085			(72,809	)		31,220
Amortization of deferred loss on commodity derivative contracts, net of tax		(549	)		1,428		—			—			879
Change in deferred hedge loss on interest rate swaps, net of tax		397			—		(1,568	)		—			(1,171	)
Comprehensive income (loss)	$	30,802		$	70,418	$	2,517		$	(72,809	)	$	30,928

22

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

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS
For the Three Months Ended March 31, 2007
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	78,380		$	4,243		$	—		$	82,623
Natural gas		—			32,829			149			—			32,978
Marketing		—			13,703			1,238			—			14,941
Total revenues		—			124,912			5,630			—			130,542
Expenses:
Production:
Lease operations		—			29,552			968			—			30,520
Production, ad valorem, and severance taxes		—			11,878			637			—			12,515
Depletion, depreciation, and amortization		—			32,521			2,507			—			35,028
Exploration		—			11,521			—			—			11,521
General and administrative		24			7,148			188			—			7,360
Marketing		—			13,931			1,080			—			15,011
Derivative fair value loss		—			41,931			3,683			—			45,614
Other operating		41			2,500			24			—			2,565
Total expenses		65			150,982			9,087			—			160,134
Operating loss		(65	)		(26,070	)		(3,457	)		—			(29,592	)
Other income (expenses):
Interest		(15,656	)		(471	)		(1,102	)		942			(16,287	)
Equity income (loss) from subsidiaries		(30,156	)		—			—			30,156			—
Other		429			944			—			(942	)		431
Total other income (expenses)		(45,383	)		473			(1,102	)		30,156			(15,856	)
Income (loss) before income taxes		(45,448	)		(25,597	)		(4,559	)		30,156			(45,448	)
Income tax benefit		16,019			—			—			—			16,019
Net income (loss)		(29,429	)		(25,597	)		(4,559	)		30,156			(29,429	)
Amortization of deferred loss on commodity derivative contracts, net of tax		8,181			—			—			—			8,181
Comprehensive income (loss)	$	(21,248	)	$	(25,597	)	$	(4,559	)	$	30,156		$	(21,248	)

23

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

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Three Months Ended March 31, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by operating activities	$	49,477		$	59,302		$	22,948		$	—		$	131,727
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(30,780	)		—			—			(30,780	)
Development of oil and natural gas properties		—			(92,944	)		(4,858	)		—			(97,802	)
Investments in subsidiaries		48,619			—			—			(48,619	)		—
Other		—			(9,680	)		(162	)		—			(9,842	)
Net cash provided by (used in) investing activities		48,619			(133,404	)		(5,020	)		(48,619	)		(138,424	)
Cash flows from financing activities:
Repurchase of common stock		(39,118	)		—			—			—			(39,118	)
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		684			—			—			—			684
Proceeds from long-term debt, net of issuance costs		214,964			—			142,310			—			357,274
Payments on long-term debt		(278,500	)		—			(25,000	)		—			(303,500	)
Net equity contributions (distributions)		—			76,796			(125,415	)		48,619			—
Other		3,873			(4,390	)		(9,625	)		—			(10,142	)
Net cash provided by (used in) financing activities		(98,097	)		72,406			(17,730	)		48,619			5,198
Increase (decrease) in cash and cash equivalents		(1	)		(1,696	)		198			—			(1,499	)
Cash and cash equivalents, beginning of period		1			1,700			3			—			1,704
Cash and cash equivalents, end of period	$	—		$	4		$	201		$	—		$	205

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Three Months Ended March 31, 2007
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	—		$	17,339		$	(2,280	)	$	—		$	15,059
Cash flows from investing activities:
Proceeds from disposition of assets		—			1,214			—			—			1,214
Acquisition of oil and natural gas properties		(41,000	)		(69,210	)		(328,358	)		—			(438,568	)
Development of oil and natural gas properties		—			(101,924	)		—			—			(101,924	)
Intercompany loans		(120,000	)		(120,000	)		—			240,000			—
Investments in subsidiaries		(251,694	)		—			—			251,694			—
Other		—			(13,988	)		—			—			(13,988	)
Net cash used in investing activities		(412,694	)		(303,908	)		(328,358	)		491,694			(553,266	)
Cash flows from financing activities:
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		60			—			—			—			60
Proceeds from long-term debt, net of issuance costs		480,895			120,000			245,883			(240,000	)		606,778
Payments on long-term debt		(66,644	)		—			(8,383	)		—			(75,027	)
Net equity contributions (distributions)		—			158,036			93,658			(251,694	)		—
Other		(1,617	)		7,876			—			—			6,259
Net cash provided by financing activities		412,694			285,912			331,158			(491,694	)		538,070
Increase (decrease) in cash and cash equivalents		—			(657	)		520			—			(137	)
Cash and cash equivalents, beginning of period		—			763			—			—			763
Cash and cash equivalents, end of period	$	—		$	106		$	520		$	—		$	626

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

Note 16. Commitments and Contingencies

Litigation

     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 results of operations or financial position.

ExxonMobil

     In March 2006, EAC entered into a joint development agreement with ExxonMobil to develop legacy natural gas fields in West Texas. Under the terms of the agreement, EAC will have the opportunity to develop approximately 100,000 gross acres. EAC will earn 30 percent of ExxonMobil’s working interest and 22.5 percent of ExxonMobil’s net revenue interest in each well drilled. EAC will operate each well during the drilling and completion phase, after which ExxonMobil will assume operational control of the well.

     EAC will earn the right to participate in all fields by drilling a total of 24 commitment wells by the end of 2008. During the commitment phase, ExxonMobil will have the option to receive non-recourse advanced funds from EAC attributable to ExxonMobil’s 70 percent working interest in each commitment well. Once a commitment well is producing, ExxonMobil will repay 95 percent of the advanced funds plus accrued interest assessed on the unpaid balance through EAC’s monthly receipt of proceeds of oil and natural gas sales. As an alternative to receiving advanced funds during the commitment phase, ExxonMobil can elect to pay their share of capital costs for each well. After EAC has fulfilled its obligations under the commitment phase, it will be entitled to a 30 percent working interest in future drilling locations. EAC will have the right to propose and drill wells for as long as it is engaged in continuous drilling operations.

     During the three months ended March 31, 2008 and 2007, EAC advanced $11.1 million and $13.8 million, respectively, to ExxonMobil for its portion of capital related to drilling commitment wells. At March 31, 2008, EAC had a net receivable from ExxonMobil of $61.1 million, of which $12.2 million is included in “Accounts receivable, net” and $48.9 million is included in “Long-term receivables” on the accompanying Consolidated Balance Sheet based on when EAC expects repayment. At December 31, 2007, EAC had a net receivable from ExxonMobil of $51.7 million, of which $12.3 million is included in “Accounts receivable, net” and $39.4 million is included in “Long-term receivables” on the accompanying Consolidated Balance Sheet. As of March 31, 2008, EAC had only two re-entry wells to drill in order to fulfill its commitment under the joint development agreement at a minimum cost of $1.0 million per well.

Note 17. Related Party Transactions

     EAC paid $0.6 million to affiliates of Exterran Holdings, Inc., the successor of Hanover Compressor Company (“Hanover”), during the three months ended March 31, 2007 for compressors and field compression services. Mr. I. Jon Brumley, EAC’s Chairman of the Board, served as a director of Hanover until August 2007.

     EAC received $40.6 million and $1.4 million from affiliates of Tesoro Corporation (“Tesoro”) during the three months ended March 31, 2008 and 2007, respectively, related to gross production sold from wells operated by Encore Operating. Mr. John V. Genova, a member of the Board, is employed by Tesoro.

     See “Note 18. ENP” for a discussion of related party transactions with ENP.

Note 18. ENP

     In September 2007, ENP completed its IPO of 9,000,000 common units, representing a 37.4 percent limited partner interest, at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units of ENP, representing an additional 2.9 percent of limited partner interest. The net proceeds of approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million, were used to repay in full the $126.4 million of outstanding indebtedness under ENP’s subordinated credit agreement with a wholly owned guarantor subsidiary of EAC and to reduce outstanding borrowings under the OLLC Credit Agreement.

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

     In connection with the closing of the IPO, EAC, ENP, and certain of their respective subsidiaries entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) and an amended and restated administrative services agreement (the “Administrative Services Agreement”), each as more fully described below. In addition, prior to the IPO, GP LLC approved a long-term incentive plan (the “ENP Plan”), as more fully described below.

Contribution, Conveyance and Assumption Agreement

     EAC entered into the Contribution Agreement with ENP, GP LLC, OLLC, Encore Operating, and Encore Partners LP Holdings LLC. At the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:

• Encore Operating transferred certain assets in the Permian Basin to ENP in exchange for 4,043,478 common units; and

• EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities, and title defects, as well as defects relating to retained assets and liabilities, occurring or existing before the closing.

     These transfers and distributions were made in a series of steps outlined in the Contribution Agreement.

     In connection with the issuance of the common units by ENP in exchange for the Permian Basin assets, the IPO, and the exercise of the underwriters’ over-allotment option to purchase additional common units, GP LLC exchanged such number of common units for general partner units as was necessary to enable it to maintain its two percent general partner interest in ENP. GP LLC received the common units through capital contributions of common units owned by EAC and its subsidiaries.

Administrative Services Agreement

     EAC entered into the Administrative Services Agreement with ENP, GP LLC, OLLC, and Encore Operating, whereby Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by ENP. Initially, Encore Operating received an administrative fee of $1.75 per BOE of ENP’s production for such services and reimbursement of actual third-party expenses incurred on ENP’s behalf. The administrative fee increases by the same percentage as the COPAS overhead charges discussed below. Effective April 1, 2008, the administrative fee increased to $1.84 per BOE.

     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 of a well. Most joint operating agreements provide for an annual increase or decrease in the COPAS overhead rate for drilling and producing wells. The rate change, which occurs annually in April, is based on the change in average weekly earnings as measured by an index published by the United States Department of Labor, Bureau of Labor Statistics. The COPAS overhead cost is charged to all non-operating interest owners under a joint operating agreement each month.

     ENP also reimburses EAC for any additional state income, franchise, or similar tax paid 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 paid had it not been included in a combined group with EAC.

     ENP does not have any employees. The employees supporting the operation of ENP are employees of EAC or its subsidiaries. Accordingly, EAC recognizes all employee-related expenses and liabilities in its consolidated financial statements. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. ENP also pays its share of expenses that are directly chargeable to wells under joint operating agreements. 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.

Purchase and Investment Agreement

     On December 27, 2007, OLLC entered into a purchase and investment agreement with Encore Operating, whereby OLLC acquired certain oil and natural gas properties and related assets in the Permian and Williston Basins from Encore Operating.

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

The transaction closed on February 7, 2008, but was effective as of January 1, 2008.

     The consideration for the acquisition consisted of approximately $125.4 million in cash and 6,884,776 common units representing limited partner interests in ENP. ENP funded the cash portion of the purchase price through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale to reduce outstanding borrowings under the EAC Credit Agreement.

Long-Term Incentive Plan

     The ENP Plan 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 Encore Operating, 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 total number of shares of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of March 31, 2008, there were 1,125,000 units available for issuance 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.

     In October 2007, ENP issued 20,000 phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan. In February 2008, ENP issued 5,000 phantom units to a new 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. These phantom units are classified as liability awards. Accordingly, ENP determines the fair value of these awards at each reporting period, based on the closing unit price of ENP, and recognizes the current portion of the liability as a component of “Other current liabilities” and the long-term portion of the liability as a component of “Other noncurrent liabilities” in the accompanying Consolidated Balance Sheets. As of March 31, 2008 and December 31, 2007, the total liability was approximately $104,000 and $31,000, respectively. For liability awards, the fair value of the award, which determines the measurement of the liability on the balance sheet, is remeasured each reporting period until the award is settled. Changes in the fair value of the liability award from period to period are recorded as increases or decreases in compensation expense, over the remaining service period. The phantom units vest in four equal installments on October 29, 2008, 2009, 2010, and 2011. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding. During the three months ended March 31, 2008, ENP recognized total compensation expense of approximately $72,000 for the phantom units, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

     To satisfy common unit awards under the ENP Plan, ENP will issue new common units, acquire common units in the open market, or use common units already owned by EAC and its affiliates. There have been no additional issuances or forfeitures of awards under the ENP Plan.

Management Incentive Units (“MIUs”)

     In May 2007, the board of directors of GP LLC issued 550,000 MIUs to the executive officers of GP LLC. MIUs are a limited partner interest in ENP that entitles the holder to quarterly distributions to the extent paid to ENP’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in ENP’s distribution rate to common unitholders. MIUs are convertible into ENP common units upon the occurrence of certain events and to increasing conversion rates upon the achievement of 10 percent compounding increases in ENP’s distribution rate to common unitholders. MIUs are subject to a maximum limit on the aggregate number of common units issuable to, and the aggregate distributions payable to, holders of MIUs as follows:

• the holders of MIUs are not entitled to receive, in the aggregate, common units upon conversion of the MIUs that exceed a maximum limit of 5.1 percent of ENP’s then-outstanding units; and

• the holders of MIUs are not entitled to receive, in the aggregate, distributions of ENP’s available cash in an amount that exceeds a maximum limit of 5.1 percent of all such distributions to all unitholders at the time of any such distribution.

     The holders of MIUs do not have any voting rights with respect to the MIUs.

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

     The MIUs vest in three equal installments. The first installment vested upon the closing of the IPO, and the subsequent vesting will occur on September 17, 2008 and 2009. For the three months ended March 31, 2008, ENP recognized total non-cash compensation expense for the MIUs of $1.1 million, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of March 31, 2008, ENP had $3.7 million of total unrecognized compensation cost related to unvested MIUs, which is expected to be recognized over a weighted average period of 0.6 years. For the second and third quarters of 2008, the expense will be approximately $1.1 million per quarter, and for the fourth quarter of 2008 through the third quarter of 2009, the expense will be approximately $0.4 million per quarter. There have been no additional issuances or forfeitures of MIUs.

Distributions

     On January 21, 2008, ENP announced a cash distribution for the fourth quarter of 2007 to unitholders of record as of the close of business on February 6, 2008 at a rate of $0.3875 per unit. Approximately $9.8 million was paid on February 14, 2008, $5.6 million of which was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

Note 19. 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 related to operating and development costs are 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. Summary of Significant Accounting Policies” in EAC’s 2007 Annual Report on Form 10-K. Prior to ENP’s IPO in September 2007, segment reporting was not applicable to EAC.

     The following table provides EAC’s operating segment information required by SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information”.

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

	For the Three Months Ended March 31, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	183,339		$	37,195		$	—		$	220,534
Natural gas		41,310			7,002			—			48,312
Marketing		1,197			2,859			—			4,056
Total revenues		225,846			47,056			—			272,902
Expenses:
Production:
Lease operations		34,292			6,058			—			40,350
Production, ad valorem, and severance taxes		22,654			4,798			—			27,452
Depletion, depreciation, and amortization		40,423			9,120			—			49,543
Exploration		5,459			29			—			5,488
General and administrative		7,770			2,922			(1,005	)		9,687
Marketing		1,389			2,393			—			3,782
Derivative fair value loss		49,551			15,587			—			65,138
Other operating		2,155			351			—			2,506
Total expenses		163,693			41,258			(1,005	)		203,946
Operating income		62,153			5,798			1,005			68,956
Other income (expenses):
Interest		(18,120	)		(1,640	)		—			(19,760	)
Other		1,839			17			(1,005	)		851
Total other income (expenses)		(16,281	)		(1,623	)		(1,005	)		(18,909	)
Income before income taxes and minority interest		45,872			4,175			—			50,047
Income tax provision		(18,643	)		(90	)		—			(18,733	)
Minority interest in income of consolidated partnership		(94	)		—			—			(94	)
Net income		27,135			4,085			—			31,220
Amortization of deferred loss on commodity derivative contracts, net of tax		879			—			—			879
Change in deferred hedge loss on interest rate swaps, net of tax		397			(1,568	)		—			(1,171	)
Comprehensive income	$	28,411		$	2,517		$	—		$	30,928
Segment assets (as of March 31, 2008)	$	2,423,748		$	484,906		$	(819	)	$	2,907,835

Note 20. Subsequent Events

     On May 6, 2008, ENP announced a cash distribution for the first quarter of 2008 to unitholders of record as of the close of business on May 9, 2008 at a rate of $0.5755 per unit. Approximately $19.2 million is expected to be paid on or about May 15, 2008, $12.3 million of which is expected to be paid to EAC and its subsidiaries and will have no impact on EAC’s consolidated cash.

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ENCORE ACQUISITION COMPANY

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 stated in the forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” in our 2007 Annual Report onForm 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 2007 Annual Report onForm 10-K.

Introduction

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

• First Quarter 2008 Highlights

• Results of Operations — Comparison of Quarter Ended March 31, 2008 to Quarter Ended March 31, 2007

• Capital Commitments, Capital Resources, and Liquidity

• Critical Accounting Policies and Estimates

• New Accounting Pronouncements

First Quarter 2008 Highlights

     Our financial and operating results for the first quarter of 2008 included the following:

• Our oil and natural gas revenues increased 133 percent to $268.8 million as compared to $115.6 million in the first quarter of 2007 as a result of increased production volumes and higher average realized prices.

• Our average realized oil price, including the effects of commodity derivative contracts, increased $44.73 per Bbl to $88.08 per Bbl as compared to $43.35 per Bbl in the first quarter of 2007. Our average realized natural gas price, including the effects of commodity derivative contracts, increased $2.88 per Mcf to $8.28 per Mcf as compared to $5.40 per Mcf in the first quarter of 2007.

• Production volumes increased 18 percent to 38,196 BOE/D as compared to 32,489 BOE/D for the first quarter of 2007, primarily as a result of our Big Horn Basin acquisition in March 2007, our Williston Basin acquisition in April 2007, and our development programs. Oil represented 72 percent and 65 percent of our total production volumes in the first quarter of 2008 and 2007, respectively.

• We invested $132.0 million in oil and natural gas activities. Of this amount, we invested $101.2 million in development, exploitation, and exploration activities, which yielded 74 gross (17.9 net) productive wells, and $30.8 million related to acquisitions.

• On February 7, 2008, we completed the sale of certain oil and natural gas properties and related assets in the Permian and Williston Basins to ENP. The sale was effective as of January 1, 2008. The consideration for the sale consisted of approximately $125.4 million in cash and 6,884,776 common units representing limited partner interests in ENP.

• Our production margin (defined as oil and natural gas revenues less production expenses) for the first quarter of 2008 increased by $128.5 million (177 percent) to $201.0 million in the first quarter of 2008 as compared to $72.6 million in the first quarter of 2007. Total oil and natural gas revenues per BOE increased by 96 percent while total production expenses per BOE increased by only 33 percent. On a per BOE basis, our production margin increased 133 percent to $57.84 per BOE for the first quarter of 2008 as compared to $24.81 per BOE for the first quarter of 2007.

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ENCORE ACQUISITION COMPANY

Results of Operations

Comparison of Quarter Ended March 31, 2008 to Quarter Ended March 31, 2007

     Oil and natural gas revenues.The following table illustrates the components of oil and natural gas revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Three months ended March 31,						Increase / (Decrease)
	2008			2007			$			%
Revenues (in thousands):
Oil wellhead	$	221,963		$	93,447		$	128,516
Oil hedges		(1,429	)		(10,824	)		9,395
Total oil revenues	$	220,534		$	82,623		$	137,911			167%
Natural gas wellhead	$	48,312		$	35,551		$	12,761
Natural gas hedges		—			(2,573	)		2,573
Total natural gas revenues	$	48,312		$	32,978		$	15,334			46%
Combined wellhead	$	270,275		$	128,998		$	141,277
Combined hedges		(1,429	)		(13,397	)		11,968
Total combined oil and natural gas revenues	$	268,846		$	115,601		$	153,245			133%
Average realized prices:
Oil wellhead ($/Bbl)	$	88.65		$	49.03		$	39.62
Oil hedges ($/Bbl)		(0.57	)		(5.68	)		5.11
Total oil revenues ($/Bbl)	$	88.08		$	43.35		$	44.73			103%
Natural gas wellhead ($/Mcf)	$	8.28		$	5.82		$	2.46
Natural gas hedges ($/Mcf)		—			(0.42	)		0.42
Total natural gas revenues ($/Mcf)	$	8.28		$	5.40		$	2.88			53%
Combined wellhead ($/BOE)	$	77.76		$	44.11		$	33.65
Combined hedges ($/BOE)		(0.41	)		(4.58	)		4.17
Total combined oil and natural gas revenues ($/BOE)	$	77.35		$	39.53		$	37.82			96%
Total production volumes:
Oil (MBbls)		2,504			1,906			598			31%
Natural gas (MMcf)		5,831			6,109			(278	)		-5%
Combined (MBOE)		3,476			2,924			552			19%
Average daily production volumes:
Oil (Bbls/D)		27,516			21,177			6,339			30%
Natural gas (Mcf/D)		64,081			67,876			(3,795	)		-6%
Combined (BOE/D)		38,196			32,489			5,707			18%
Average NYMEX prices:
Oil (per Bbl)	$	97.74		$	58.33		$	39.41			68%
Natural gas (per Mcf)	$	8.02		$	6.77		$	1.25			18%

     Oil revenues increased $137.9 million from $82.6 million in the first quarter of 2007 to $220.5 million in the first quarter of 2008 as a result of an increase in oil production volumes of 598 MBbls, which contributed approximately $29.3 million in additional oil revenues, and an increase in our average realized oil price. The increase in oil production volumes was primarily the result of our Big Horn Basin acquisition in March 2007, our Williston Basin acquisition in April 2007, and our development programs.

     Our average realized oil price increased $44.73 per Bbl as a result of an increase in our wellhead price and a decrease in the effects of commodity derivative contracts that were previously designated as hedges. Our higher average oil wellhead price increased oil revenues by $99.2 million, or $39.62 per Bbl, and the decrease in the effects of commodity derivative contracts that were previously designated as hedges, increased oil revenues by $9.4 million, or $5.11 per Bbl. Our average oil wellhead price increased as a result of increases in the overall market price for oil, as reflected in the increase in the average NYMEX price

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ENCORE ACQUISITION COMPANY

from $58.33 per Bbl in the first quarter of 2007 to $97.74 per Bbl in the first quarter of 2008.

     Our oil wellhead revenue was reduced by $12.9 million and $4.1 million in the first quarter of 2008 and 2007, respectively, for NPI payments related to our CCA properties.

     Natural gas revenues increased $15.3 million from $33.0 million in the first quarter of 2007 to $48.3 million in the first quarter of 2008 as a result of an increase in our average realized natural gas price, partially offset by a decrease in production volumes of 278 MMcf, which reduced natural gas revenues by approximately $1.6 million. The decrease in natural gas production volumes was primarily the result of our Mid-Continent disposition in June 2007.

     Our average realized natural gas price increased $2.88 per Mcf as a result of an increase in our wellhead price and a decrease in the effects of commodity derivative contracts that were previously designated as hedges. Our higher average natural gas wellhead price increased natural gas revenues by $14.4 million, or $2.46 per Mcf, and the decrease in the effects of commodity derivative contracts that were previously designated as hedges, increased natural gas revenues by $2.6 million, or $0.42 per Mcf. Our average natural gas wellhead price increased as a result of increases in the overall market price for natural gas, as reflected in the increase in the average NYMEX price from $6.77 per Mcf in the first quarter of 2007 to $8.02 per Mcf in the first quarter of 2008.

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

	Three months ended March 31,
	2008			2007
Oil wellhead ($/Bbl)	$	88.65		$	49.03
Average NYMEX ($/Bbl)	$	97.74		$	58.33
Differential to NYMEX	$	(9.09	)	$	(9.30	)
Oil wellhead to NYMEX percentage		91	%		84	%
Natural gas wellhead ($/Mcf)	$	8.28		$	5.82
Average NYMEX ($/Mcf)	$	8.02		$	6.77
Differential to NYMEX	$	0.26		$	(0.95	)
Natural gas wellhead to NYMEX percentage		103	%		86	%

     Our oil wellhead price as a percentage of the average NYMEX price tightened to 91 percent in the first quarter of 2008 as compared to 84 percent in the first quarter of 2007. We expect our oil wellhead differentials to remain approximately constant in the second quarter of 2008 as compared to the first quarter of 2008.

     Our natural gas wellhead price as a percentage of the average NYMEX price improved to 103 percent in the first quarter of 2008 as compared to 86 percent in the first quarter of 2007. The differential improved because of efforts to reduce natural gas transportation and gathering costs. We expect our natural gas wellhead differentials to remain approximately constant or to widen slightly in the second quarter of 2008 as compared to the first quarter of 2008.

     Marketing revenues and expenses.In 2007, we discontinued purchasing oil from third party companies as market conditions changed and historical pipeline space was realized. Implementing this change allowed us to focus on the marketing of our own oil production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead.

     In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.

     The following table summarizes our marketing activities for the periods indicated:

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ENCORE ACQUISITION COMPANY

	Three months ended March 31,						Increase / (Decrease)
	2008			2007			$			%
	($ in thousands, except per BOE amounts)
Marketing revenues	$	4,056		$	14,941		$	(10,885	)		-73	%
Marketing expenses		(3,782	)		(15,011	)		11,229			-75	%
Marketing gain (loss)	$	274		$	(70	)	$	344			-491	%
Marketing revenues per BOE	$	1.17		$	5.11		$	(3.94	)		-77	%
Marketing expenses per BOE		(1.09	)		(5.13	)		4.04			-79	%
Marketing gain (loss) per BOE	$	0.08		$	(0.02	)	$	0.10			-500	%

     Expenses.The following table summarizes our expenses, excluding marketing expenses shown above, for the periods indicated:

	Three months ended March 31,					Increase / (Decrease)
	2008		2007			$			%
Expenses (in thousands):
Production:
Lease operations	$	40,350	$	30,520		$	9,830
Production, ad valorem, and severance taxes		27,452		12,515			14,937
Total production expenses		67,802		43,035			24,767			58	%
Other:
Depletion, depreciation, and amortization		49,543		35,028			14,515
Exploration		5,488		11,521			(6,033	)
General and administrative		9,687		7,360			2,327
Derivative fair value loss		65,138		45,614			19,524
Other operating		2,506		2,565			(59	)
Total operating		200,164		145,123			55,041			38	%
Interest		19,760		16,287			3,473
Income tax provision (benefit)		18,733		(16,019	)		34,752
Total expenses	$	238,657	$	145,391		$	93,266			64	%
Expenses (per BOE):
Production:
Lease operations	$	11.61	$	10.44		$	1.17
Production, ad valorem, and severance taxes		7.90		4.28			3.62
Total production expenses		19.51		14.72			4.79			33	%
Other:
Depletion, depreciation, and amortization		14.25		11.98			2.27
Exploration		1.58		3.94			(2.36	)
General and administrative		2.79		2.52			0.27
Derivative fair value loss		18.74		15.60			3.14
Other operating		0.72		0.88			(0.16	)
Total operating		57.59		49.64			7.95			16	%
Interest		5.68		5.57			0.11
Income tax provision (benefit)		5.39		(5.48	)		10.87
Total expenses	$	68.66	$	49.73		$	18.93			38	%

     Production expenses.Total production expenses increased $24.8 million from $43.0 million in the first quarter of 2007 to $67.8 million in the first quarter of 2008 as a result of an increase in total production volumes and a $4.79 increase in production expenses per BOE.

     Production expense attributable to LOE increased $9.8 million from $30.5 million in the first quarter of 2007 to $40.4 million in the first quarter of 2008 as a result of an increase in production volumes, which contributed approximately $5.8 million of additional LOE, and a $1.17 increase in the average per BOE rate, which contributed approximately $4.1 million of

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additional LOE. The increase in our average LOE per BOE rate was attributable to:

• increases in prices paid to oilfield service companies and suppliers;

• increased operational activity to maximize production; and

• higher salary levels for engineers and other technical professionals.

     Production expense attributable to production, ad valorem, and severance taxes (“production taxes”) increased $14.9 million from $12.5 million in the first quarter of 2007 to $27.5 million in the first quarter of 2008 primarily due to higher wellhead revenues. As a percentage of oil and natural gas revenues (excluding the effects of commodity derivative contracts), production taxes increased to 10.2 percent in the first quarter of 2008 as compared to 9.7 percent in the first quarter of 2007 primarily as a result of higher rates in the states where the properties associated with our Big Horn Basin acquisition in March 2007 and our Williston Basin acquisition in April 2007 are located. The effect of commodity derivative contracts is excluded from oil and natural gas revenues in the calculation of these percentages because this method more closely reflects the method used to calculate actual production taxes paid to taxing authorities.

     Depletion, depreciation, and amortization (“DD&A”) expense.DD&A expense increased $14.5 million from $35.0 million in the first quarter of 2007 to $49.5 million in the first quarter of 2008 as a result of a $2.27 increase in the per BOE rate, which contributed approximately $7.9 million of additional DD&A expense, and an increase in production volumes, which contributed approximately $6.6 million of additional DD&A expense. The increase in our average DD&A per BOE rate was attributable to:

• higher cost basis of the properties associated with our Big Horn Basin acquisition in March 2007 and our Williston Basin acquisition in April 2007;

• development of proved undeveloped reserves; and

• higher finding, development, and acquisition costs resulting from increases in rig rates, oilfield services costs, and acquisition costs.

     Exploration expense.Exploration expense decreased $6.0 million from $11.5 million in the first quarter of 2007 to $5.5 million in the first quarter of 2008. During the first quarter of 2008, we expensed two exploratory dry holes totaling $0.6 million. During the first quarter of 2007, we expensed three exploratory dry holes totaling $8.5 million. Impairment of unproved acreage through the normal course of evaluation in the first quarter of 2008 increased $1.9 million from $2.2 million in the first quarter of 2007 to $4.1 million in the first quarter of 2008 as we continue to expand our acreage positions in certain areas and refine our estimated success rate. The following table details our exploration expenses for the periods indicated:

	Three months ended March 31,				Increase /
	2008		2007		(Decrease)
	(in thousands)
Dry holes	$	622	$	8,480	$	(7,858	)
Geological and seismic		378		631		(253	)
Delay rentals		346		178		168
Impairment of unproved acreage		4,142		2,232		1,910
Total	$	5,488	$	11,521	$	(6,033	)

     With the current commodity price environment, we believe exploration programs can provide a rate of return comparable to property acquisitions in certain areas. We seek to acquire undeveloped acreage and/or enter into drilling arrangements to explore in areas that complement our portfolio of properties. In keeping with our exploitation focus, the exploration projects could expand existing fields or set up multi-well exploitation projects, if successful.

     G&A expense.G&A expense increased $2.3 million from $7.4 million in the first quarter of 2007 to $9.7 million in the first quarter of 2008 primarily due to:

• $1.1 million of non-cash unit-based compensation expense related to ENP’s MIUs;

• increased staffing to manage our larger asset base;

• public entity expenses of ENP;

• higher activity levels; and

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• increased personnel costs due to intense competition for human resources within the industry.

     Derivative fair value loss.During the first quarter of 2008, we recorded a $65.1 million derivative fair value loss as compared to $45.6 million in the first quarter of 2007, the components of which were as follows:

	Three months ended March 31,						Increase /
	2008			2007			(Decrease)
	(in thousands)
Mark-to-market loss on commodity derivative contracts	$	46,779		$	47,445		$	(666	)
Premium amortization		15,513			6,364			9,149
Change in fair value of interest rate swaps prior to designation		(381	)		—			(381	)
Settlements on commodity derivative contracts		3,227			(8,195	)		11,422
Total derivative fair value loss	$	65,138		$	45,614		$	19,524

     Interest expense.Interest expense increased $3.5 million from $16.3 million in the first quarter of 2007 to $19.8 million in the first quarter of 2008, primarily due to additional debt used to finance our Big Horn Basin acquisition in March 2007 and our Williston Basin acquisition in April 2007. The weighted average interest rate for all long-term debt was 6.4 percent for the first quarter of 2008 as compared to 6.9 percent for the first quarter of 2007.

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

	Three months ended March 31,				Increase /
	2008		2007		(Decrease)
	(in thousands)
6.25% Notes	$	2,430	$	2,425	$	5
6.0% Notes		4,635		4,627		8
7.25% Notes		2,748		2,746		2
Revolving credit facilities		8,390		5,627		2,763
Other		1,557		862		695
Total	$	19,760	$	16,287	$	3,473

     Minority interest.As of March 31, 2008, public unitholders in ENP had a limited partner interest of approximately 31.5 percent. We include ENP’s results of operations in our consolidated financial statements and show the public ownership as minority interest. Minority interest expense was approximately $0.1 million for the first quarter of 2008.

     Income taxes.During the first quarter of 2008, we recorded an income tax provision of $18.7 million as compared to an income tax benefit of $16.0 million in the first quarter of 2007. During the first quarter of 2008, we had income before income taxes and minority interest of $50.0 million while we had a loss before income taxes of $45.4 million in the first quarter of 2007. Our effective tax rate increased to 37.5 percent in the first quarter of 2008 as compared to 35.2 percent in the first quarter of 2007, primarily due to a permanent rate adjustment for ENP’s MIUs and permanent timing adjustments that will not reverse in future periods.

Capital Commitments, Capital Resources, and Liquidity

     Capital commitments.Our primary needs for cash are:

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

• Acquisitions of oil and natural gas properties and leasehold acreage;

• Funding of necessary 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 during the periods indicated:

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	Three months ended March 31,
	2008		2007
	(in thousands)
Development and exploitation	$	57,372	$	63,498
Exploration		43,826		31,218
Total	$	101,198	$	94,716

     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 first quarter of 2008 yielded 48 gross (11.6 net) successful wells and 1 gross (0.9 net) 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 first quarter of 2008 yielded 26 gross (6.3 net) successful wells and 2 gross (0.5 net) dry holes.

     As of April 23, 2008, we were operating 9 drilling rigs, including 6 rigs related to our West Texas joint development agreement with ExxonMobil.

     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 during the periods indicated:

	Three months ended March 31,
	2008		2007
	(in thousands)
Acquisitions of proved property	$	14,781	$	395,976
Acquisitions of leasehold acreage		15,999		3,255
Total	$	30,780	$	399,231

     On March 7, 2007, Encore Operating and OLLC acquired oil and natural gas properties in the Big Horn Basin, including the Elk Basin field and the Gooseberry field. OLLC paid approximately $330.7 million, including transaction costs of approximately $1.1 million, for the Elk Basin field and Encore Operating paid $62.9 million, including transaction costs of approximately $0.2 million, for the Gooseberry field. The total purchase price allocated to proved properties was approximately $395.6 million.

     During the first quarter of 2008 and 2007, our capital expenditures for leasehold acreage totaled $16.0 million and $3.3 million, all of which related to the acquisition of unproved acreage in various areas.

     Funding of necessary working capital.As of March 31, 2008 and December 31, 2007, our working capital (defined as total current assets less total current liabilities) was negative $16.0 million and negative $16.2 million, respectively. For the remainder of 2008, we expect working capital to remain negative, primarily due to the fair values of our commodity derivative contracts (the settlements of which will be offset by cash flows from the sale of production mitigated against price risk under those contracts) and deferred commodity derivative contract premiums. 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 significant 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. Assuming relatively stable commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for the remainder of 2008.

     The Board has approved a capital budget of $445 million for 2008. The level of these and other future expenditures is 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 borrowings under our revolving credit facility.

     Off-balance sheet arrangements.We have no investments in unconsolidated entities or persons that could materially affect

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our liquidity or availability of capital resources. Other than those described below under “Contractual obligations” and undrawn letters of credit related to our revolving credit facilities, we do not have any off-balance sheet arrangements that are material to our financial position or results of operations.

     Contractual obligations.The following table illustrates our contractual obligations and commitments at March 31, 2008:

	Payments Due by Period
			Nine Months Ended		Years Ended		Years Ended
Contractual Obligations			December 31,		December 31,		December 31,
and Commitments	Total		2008		2009 — 2010		2011 — 2012		Thereafter
	(in thousands)
6.25% Notes (a)	$	210,938	$	9,375	$	18,750	$	18,750	$	164,063
6.0% Notes (a)		435,000		9,000		36,000		36,000		354,000
7.25% Notes (a)		258,750		10,875		21,750		21,750		204,375
Revolving credit facilities (a)		695,636		22,143		59,048		614,445		—
Commodity derivative contracts (b)		47,915		21,089		26,826		—		—
Interest rate swaps		1,222		351		871		—		—
Development commitments (c)		106,048		79,445		26,603		—		—
Operating leases and commitments (d)		17,696		2,825		6,507		5,757		2,607
Asset retirement obligations (e)		155,837		692		1,844		1,844		151,457
Total	$	1,929,042	$	155,795	$	198,199	$	698,546	$	876,502

(a)	Amounts include principal and projected interest payments. Please read Note 9 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 that were valued as of March 31, 2008. With the exception of $70.6 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)	Development commitments include: authorized purchases for work in process of $68.8 million; future minimum payments for drilling rig operations of $35.2 million; and $2.0 million for minimum capital obligations associated with the remaining 2 commitment wells to be drilled under our joint development agreement with ExxonMobil. Also at March 31, 2008, we had approximately $81.5 million of authorized purchases not placed to 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.
(d)	Operating leases and commitments include office space and equipment obligations that have non-cancelable lease terms in excess of one year of $16.5 million and future minimum payments for other operating commitments of $1.2 million.
(e)	Asset retirement obligations represent 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 8 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. In addition, we have identified new markets to the west and a portion of our crude oil is being moved that direction through the Rocky Mountain Pipeline. 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 currently oversubscribed and have been subject to apportionment since December 2005, we were allocated sufficient pipeline capacity to move our equity crude oil production effective January 1, 2007. Enbridge Pipeline North Dakota completed an expansion of their pipeline in January 2008. The expansion has provided a small degree of stability to oil differentials by effectively moving the total Rockies area pipeline takeaway closer to a balancing point with increasing production volumes. In spite of the increase in capacity, the Enbridge Pipeline North Dakota continues to run at 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

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mentioned pipelines, or 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.

     We expect the differential between the NYMEX price of crude oil and the wellhead price we receive to remain approximately constant in the second quarter of 2008 as compared to the $9.09 per Bbl differential we realized in the first quarter of 2008. 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. Natural gas differentials are expected to remain approximately constant or to slightly widen in the second quarter of 2008 as compared to the $0.26 per Mcf differential we realized in the first quarter of 2008. We cannot accurately predict future crude oil and natural gas differentials. Increases in the differential between the NYMEX 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 $116.7 million from $15.1 million for the first quarter of 2007 to $131.7 million for the first quarter of 2008, primarily due to an increase in our production margin, partially offset by increased settlements on our commodity derivative contracts as a result of increases in oil and natural gas prices and an increase in accounts receivable as a result of increased oil and natural gas sales.

     Cash flows from investing activities. Cash used in investing activities decreased $414.8 million from $553.3 million in the first quarter of 2007 to $138.4 million in the first quarter of 2008, primarily due to a $407.8 million decrease in amounts paid for the acquisition of oil and natural gas properties. Encore Operating and OLLC paid approximately $393.1 million in conjunction with the Big Horn Basin acquisition in March 2007. During the first quarter of 2008, we advanced $9.0 million (net of collections) to ExxonMobil for their portion of costs incurred drilling the commitment wells under the joint development agreement as compared to $13.4 million in the first quarter of 2007.

     Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments. In the past, we have repaid large balances on our revolving credit facilities with proceeds from the issuance of senior subordinated notes in order to extend the maturity date of the debt and fix the interest rate.

     During the first quarter of 2008, we received net cash of $5.2 million from financing activities, including net borrowings on our revolving credit facilities of $53.8 million. Net borrowings on our revolving credit facilities resulted in a net increase in outstanding borrowings under our revolving credit facilities from $526 million at December 31, 2007 to $580 million at March 31, 2008.

     In December 2007, we announced that the Board had approved a new share repurchase program authorizing the purchase of up to $50 million of our common stock. As of March 31, 2008, we had repurchased and retired 1,174,691 shares of our outstanding common stock for approximately $39.1 million, or an average price of $33.30 per share, under the share repurchase program.

     During the first quarter of 2007, we received net cash of $538.1 million from financing activities, including net borrowings on our revolving credit facilities of $531.8 million. Borrowings of $393.1 million were used to finance the Big Horn Basin acquisition and net borrowings of $41 million were deposited on the Williston Basin acquisition.

     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 our level of capital expenditures. We may use other sources of capital, including the issuance of additional debt or equity securities, to fund acquisitions and to maintain our financial flexibility.

     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 quarter of 2008, realized oil and natural gas prices increased by approximately 103 percent and 53 percent, respectively, as compared to the first quarter of 2007. Realized oil and natural gas prices fluctuate widely in response to changing market forces. For the first quarter of 2008, approximately 72 percent of our production was oil. As we previously discussed, our oil and natural gas wellhead differentials during the first quarter of 2008 tightened as compared to the first quarter of 2007, favorably impacting the prices we received for our production. To the extent

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oil and natural gas prices decline or we experience a significant widening of our wellhead differentials, our earnings, cash flows from operations, and availability under our revolving credit facility may be adversely impacted. Prolonged periods of lower oil and natural gas prices or sustained wider wellhead differentials could cause us to not be in compliance with financial covenants under our revolving credit facility and thereby affect our liquidity.

     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.

     Revolving credit facilities.Our principal source of short-term liquidity is our revolving credit facility.

     Encore Acquisition Company Senior Secured Credit Agreement

     On March 7, 2007, we entered into a five-year amended and restated credit agreement with a bank syndicate including Bank of America, N.A. and other lenders. Effective February 7, 2008, we amended the credit agreement (as amended, the “EAC Credit Agreement”) to, among other things, provide that certain negative covenants in the EAC Credit Agreement restricting hedge transactions do not apply to any oil and natural gas hedge transaction that is a floor or put transaction not requiring any future payments or delivery by us or any of our restricted subsidiaries. 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 our account 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. As of March 31, 2008, the borrowing base was $870 million.

     The EAC Credit Agreement matures on March 7, 2012. Our obligations under the EAC Credit Agreement are secured by a first-priority security interest in our restricted subsidiaries’ proved oil and natural gas reserves and in our equity interests in our restricted subsidiaries. In addition, our obligations under the EAC Credit Agreement are guaranteed by our restricted subsidiaries.

     Loans under the EAC Credit Agreement are subject to varying rates of interest based on (i) the total amount outstanding in relation to the borrowing base and (ii) 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 Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.000	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.250	%		0.000	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.500	%		0.250	%
Greater than or equal to .90 to 1		1.750	%		0.500	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (ii) the federal funds effective rate plus 0.5 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 that include, among others:

• 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;

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• 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; and

• a requirement that we maintain a ratio of consolidated EBITDA (as defined in the EAC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.

     The EAC Credit Agreement contains customary events of default. 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.

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

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .50 to 1		0.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		0.300	%
Greater than or equal to .75 to 1 but less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.375	%

     On March 31, 2008 and May 2, 2008, there were $415 million of outstanding borrowings and $435 million of borrowing capacity under the EAC Credit Agreement. As of March 31, 2008 and May 2, 2008, we had $20 million outstanding letters of credit, all of which related to our joint development agreement with ExxonMobil.

     Encore Energy Partners Operating LLC Credit Agreement

     OLLC is a party to a five-year credit agreement dated March 7, 2007 with a bank syndicate including Bank of America, N.A. and other lenders. On August 22, 2007, OLLC amended its credit agreement (as amended, the “OLLC Credit Agreement”), which revised certain financial covenants. 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 $300 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 March 31, 2008, the borrowing base was $240 million.

     The OLLC Credit Agreement matures on March 7, 2012. OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s proved oil and natural gas reserves and in OLLC’s equity interests in its restricted subsidiaries. In addition, OLLC’s 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 the same provisions as the EAC Credit Agreement.

     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 that include, among others:

• 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 its restricted subsidiaries, subject to permitted exceptions;

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

• a requirement that OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;

• a requirement that OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and

• a requirement that OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA (as defined in the OLLC Credit Agreement) of not more than 3.5 to 1.0.

     The OLLC Credit Agreement contains customary events of default. 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.

     OLLC incurs a commitment fee on the unused portion of the OLLC Credit Agreement based on the same provisions as the EAC Credit Agreement.

     On March 31, 2008 and May 2, 2008, there were $165 million and $160 million of outstanding borrowings, respectively, and $74.9 million and $79.9 million of borrowing capacity, respectively, under the OLLC Credit Agreement. As of March 31, 2008 and May 2, 2008, ENP had approximately $0.1 million outstanding letters in credit.

     Please read Note 9 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.

     Debt covenants.At March 31, 2008, we and ENP were in compliance with all debt covenants.

     Current capitalization.At March 31, 2008, we had total assets of $2.9 billion and total capitalization of $2.1 billion, of which 45 percent was represented by stockholders’ equity and 55 percent by long-term debt. At December 31, 2007, we had total assets of $2.8 billion and total capitalization of $2.1 billion, of which 46 percent was represented by stockholders’ equity and 54 percent by long-term debt. The percentages of our capitalization represented by stockholders’ equity and long-term debt could vary in the future if debt 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 2007 Annual Report on Form 10-K for more 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.”

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The information included in “Quantitative and Qualitative Disclosures about Market Risk” in our 2007 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 outstanding commodity derivative contracts as of March 31, 2008 are discussed in Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of March 31, 2008, the unrealized loss on commodity derivative contracts that were previously designated as hedges was approximately $0.9 million and is included in AOCL in our Consolidated Balance Sheet. As of March 31, 2008, the fair market value of our oil and natural gas commodity derivative contracts was a net liability of approximately $14.8 million and $9.0 million, respectively. Based on our open commodity derivative positions at March 31, 2008, a $1.00 increase in the respective NYMEX prices for oil and natural gas would increase our net derivative fair value liability by approximately $15.1 million, while a $1.00 decrease in the respective NYMEX prices for oil and natural gas would decrease our net derivative fair value liability by approximately $15.1 million. These amounts exclude deferred premiums of $70.6 million at March 31, 2008 that are not subject to changes in commodity prices.

Interest Rate Sensitivity

     At March 31, 2008, we had total long-term debt of $1.2 billion, which is recorded net of discount of $5.6 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, and $150 million bears interest at a fixed rate of 7.25 percent. The remaining long-term debt balance of $580 million is outstanding borrowings on our revolving credit facilities and is subject to floating market rates of interest that are linked to LIBOR.

     At this level of floating rate debt, if LIBOR increased one percent, we would incur an additional $5.8 million of interest expense per year on our revolving credit facilities, and if LIBOR decreased one percent, we would incur $5.8 million less. Additionally, if LIBOR increased one percent, we estimate the fair value of our fixed rate debt at March 31, 2008 would decrease from approximately $551.8 million to approximately $518.5 million, and if LIBOR decreased one percent, we estimate the fair value would increase to approximately $587.9 million.

     In the first quarter of 2008, as a result of the increase in debt levels, ENP entered into interest rate swaps whereby it swapped $100 million of floating rate debt on the OLLC Credit Agreement to a weighted average fixed rate of 3.06 percent and an expected margin of 1.25 percent. As of March 31, 2008, the unrealized loss on interest rate swaps was approximately $1.2 million and is included in AOCL in our Consolidated Balance Sheet. As of March 31, 2008, the fair market value of ENP’s interest rate swaps was a net liability of $1.2 million. If LIBOR increased one percent, we estimate the fair value of ENP’s interest rate swaps at March 31, 2008 would be an asset of approximately $1.5 million, and if LIBOR decreased one percent, we estimate the liability would increase by approximately $2.7 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 management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of March 31, 2008. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2008 to ensure that information required to be disclosed in our reports filed or submitted 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 first quarter of 2008 that have 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 results of operations or financial position.

Item 1A. Risk Factors

     In addition to the other information set forth in this Report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2007 Annual Report on Form 10-K, which could materially affect our business, financial condition, and/or future results. The risks described in our 2007 Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition, and/or results of operations.

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

Issuer Purchases of Equity Securities

     In December 2007, we announced that the Board had approved a new share repurchase program authorizing the purchase of up to $50 million of our common stock. The following table summarizes purchases of our common stock during the first quarter of 2008:

					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
January		325,200	$	31.34		325,200
February (a)		630,884	$	33.36		602,691
March		246,800	$	35.79		246,800
Total		1,202,884	$	33.31		1,174,691	$	10,881,107

(a) Certain employees surrendered 28,193 shares of common stock to pay income tax withholding obligations in conjunction with vesting of restricted stock awards.

Item 6. Exhibits

Exhibits

3.1	Second Amended and Restated Certificate of Incorporation of Encore Acquisition Company (incorporated by reference from EAC’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, filed with the SEC on November 7, 2001).
3.1.2	Certificate of Amendment to Second Amended and Restated Certificate of Incorporation of Encore Acquisition Company (incorporated by reference from EAC’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, filed with the SEC on May 5, 2005).
3.2	Second Amended and Restated Bylaws of Encore Acquisition Company (incorporated by reference from EAC’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, filed with the SEC on November 7, 2001).
4.1	First Supplemental Indenture, dated as of January 2, 2008, among EAC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, with respect to the 6.25% Senior Subordinated Notes due 2014 (incorporated by reference from Exhibit 4.2.3 to EAC’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).
4.2	First Supplemental Indenture, dated as of January 2, 2008, among EAC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, with respect to the 6.0% Senior Subordinated Notes due 2015 (incorporated by reference from Exhibit 4.3.3 to EAC’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

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4.3	Second Supplemental Indenture, dated as of January 2, 2008, among EAC, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, with respect to the 7.25% Senior Subordinated Notes due 2017 (incorporated by reference from Exhibit 4.4.4 to EAC’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).
10.1	First Amendment to Amended and Restated Credit Agreement, dated as of January 31, 2008, by and among Encore Acquisition Company, Encore Operating, L.P., Bank of America, N.A., as administrative agent and L/C issuer, and the lenders party thereto (incorporated by reference from Exhibit 10.1 to EAC’s Current Report on Form 8-K, filed with the SEC on February 8, 2008).
10.2*+	Form of Stock Option Agreement — Nonqualified.
10.3*+	Form of Stock Option Agreement — Incentive.
10.4*+	Form of Restricted Stock Award — Executive.
10.5*	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, dated as of May 10, 2007.
31.1*	Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer).
31.2*	Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer).
32.1*	Section 1350 Certification (Principal Executive Officer).
32.2*	Section 1350 Certification (Principal Financial Officer).
99.1*	Statement showing computation of ratios of earnings (loss) to fixed charges.

*	Filed herewith.
+	Management contract or compensatory plan, contract, or arrangement.

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SIGNATURE

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

	ENCORE ACQUISITION COMPANY
Date: May 8, 2008	/s/ Andrea Hunter
	Andrea Hunter
	Vice President, Controller, and Principal Accounting Officer

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