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, 2009

or

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

For the transition period from                      to                     

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware		75-2759650
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o     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):

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

Number of shares of common stock, $0.01 par value, outstanding as of April 28, 2009		52,772,669

 

 

ENCORE ACQUISITION COMPANY

INDEX

				Page
		PART I. FINANCIAL INFORMATION
Items 1.		Financial Statements
		Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008		1
		Consolidated Statements of Operations for the three months ended March 31, 2009 and 2008		2
		Consolidated Statement of Equity and Comprehensive Loss for the three months ended March 31, 2009		3
		Consolidated Statements of Cash Flows for the three months ended March 31, 2009 and 2008		4
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		44
Item 4.		Controls and Procedures		45
		PART II. OTHER INFORMATION
Item 1.		Legal Proceedings		45
Item 1A.		Risk Factors		45
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		45
Item 6.		Exhibits		46
EX-10.2
EX-10.3
EX-10.4
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

     Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and our 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. You 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” and elsewhere in our 2008 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 expected. 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.

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 summarized 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 hydrocarbons.
	•		Council of Petroleum Accountants Societies (“COPAS”). A professional organization of petroleum 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 or Unsuccessful Well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production costs.
	•		EAC. Encore Acquisition Company, a publicly traded 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 hydrocarbons in an unproved area, to find a new reservoir in a field previously producing hydrocarbons in another reservoir, or to extend a known reservoir.
	•		FASB. Financial Accounting Standards Board.
	•		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.
	•		GAAP. Accounting principles generally accepted in the United States.
	•		Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which an entity owns a working interest.
	•		Lease Operating Expense (“LOE”). All direct and allocated indirect costs of producing hydrocarbons after the completion of drilling and before the commencement of production. 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.
	•		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 an entity.
	•		Net Production. Production owned by an entity less royalties, net profits interests, and production due others.
	•		Net Profits Interest. An interest that entitles the owner to a specified share of net profits from the production of hydrocarbons.
	•		NYMEX. New York Mercantile Exchange.
	•		Oil. Crude oil, condensate, and NGLs.
	•		Operator. The entity responsible for the exploration, development, and production of a well or lease.
	•		Production Margin. Wellhead revenues less production costs.
	•		Productive Well or Successful Well. A well capable of producing hydrocarbons in commercial quantities, 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.

ENCORE ACQUISITION COMPANY

	•		Proved Reserves. The estimated quantities of hydrocarbons that geological and engineering data demonstrate with reasonable certainty are recoverable in future periods from known reservoirs under existing economic and operating conditions.
	•		Proved Undeveloped Reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage 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 for recompletion. Includes unrealized production response from enhanced recovery techniques that have been proved effective by actual tests in the area and in the same reservoir.
	•		Recompletion. The completion for production from an existing wellbore in another formation from that in which the well has been previously completed.
	•		Reservoir. A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
	•		Royalty. An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
	•		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. Involves maintaining or enhancing reservoir pressure by injecting water, gas, or other substances into the formation in order to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding.
	•		SFAS. Statement of Financial Accounting Standards.
	•		Tertiary Recovery. An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gases are used as the injectant.
	•		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 hydrocarbons on the leased acreage and requires the owner to pay a share of the production and development costs.
	•		Workover. Operations on a producing well to restore or increase production.

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,
		2009				2008
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	23,472			$	2,039
Accounts receivable, net of allowance for doubtful accounts of $381			90,618				129,065
Inventory			33,291				24,798
Derivatives			81,378				349,344
Income taxes receivable			4,448				29,445
Other			5,839				6,239
Total current assets			239,046				540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment			3,653,719				3,538,459
Unproved properties			120,464				124,339
Accumulated depletion, depreciation, and amortization			(840,857	)			(771,564	)
			2,933,326				2,891,234
Other property and equipment			25,480				25,192
Accumulated depreciation			(13,696	)			(12,753	)
			11,784				12,439
Goodwill			60,606				60,606
Derivatives			45,642				38,497
Long-term receivables, net of allowance for doubtful accounts of $7,669 and $7,643, respectively			59,853				60,915
Other			27,671				28,574
Total assets		$	3,377,928			$	3,633,195
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	11,393			$	10,017
Accrued liabilities:
Lease operations expense			24,214				19,108
Development capital			66,654				79,435
Interest			12,473				11,808
Production, ad valorem, and severance taxes			23,872				25,133
Derivatives			8,163				63,476
Oil and natural gas revenues payable			10,462				10,821
Deferred taxes			92,106				105,768
Other			33,892				26,686
Total current liabilities			283,229				352,252
Derivatives			15,635				8,922
Future abandonment cost, net of current portion			47,255				48,058
Deferred taxes			421,787				416,915
Long-term debt			1,132,962				1,319,811
Other			4,521				3,989
Total liabilities			1,905,389				2,149,947
Commitments and contingencies (see Note 15)
Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding			—				—
Common stock, $.01 par value, 144,000,000 shares authorized, 51,819,037 and 51,551,937 issued and outstanding, respectively			518				516
Additional paid-in capital			530,440				525,763
Treasury stock, at cost, 111,353 and 4,753 shares, respectively			(2,945	)			(101	)
Retained earnings			782,089				789,698
Accumulated other comprehensive loss			(2,089	)			(1,748	)
Total EAC stockholders’ equity			1,308,013				1,314,128
Noncontrolling interest			164,526				169,120
Total equity			1,472,539				1,483,248
Total liabilities and equity		$	3,377,928			$	3,633,195

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

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

		Three months ended
		March 31,
		2009				2008
Revenues:
Oil		$	88,289			$	220,534
Natural gas			25,254				48,312
Marketing			806				4,056
Total revenues			114,349				272,902
Expenses:
Production:
Lease operating			44,225				40,350
Production, ad valorem, and severance taxes			11,819				27,452
Depletion, depreciation, and amortization			70,300				49,543
Exploration			11,199				5,488
General and administrative			13,694				9,687
Marketing			739				3,782
Derivative fair value loss (gain)			(48,591	)			65,138
Other operating			6,343				2,506
Total expenses			109,728				203,946
Operating income			4,621				68,956
Other income (expenses):
Interest			(15,963	)			(19,760	)
Other			554				851
Total other expenses			(15,409	)			(18,909	)
Income (loss) before income taxes			(10,788	)			50,047
Income tax benefit (provision)			4,885				(18,733	)
Consolidated net income (loss)			(5,903	)			31,314
Less: net income attributable to noncontrolling interest			(1,653	)			(94	)
Net income (loss) attributable to EAC		$	(7,556	)		$	31,220
Net income (loss) per common share:
Basic		$	(0.15	)		$	0.58
Diluted		$	(0.15	)		$	0.58
Weighted average common shares outstanding:
Basic			51,688				52,799
Diluted			51,688				53,332

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

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

		Issued																												Accumulated
		Shares of								Additional				Shares of																Other
		Common				Common				Paid-in				Treasury				Treasury				Retained				Noncontrolling				Comprehensive				Total
		Stock				Stock				Capital				Stock				Stock				Earnings				Interest				Loss				Equity
Balance at December 31, 2008			51,557			$	516			$	525,763				(5	)		$	(101	)		$	789,698			$	169,120			$	(1,748	)		$	1,483,248
Exercise of stock options and vesting of restricted stock			378				2				72				—				—				—				—				—				74
Purchase of treasury stock			—				—				—				(111	)			(2,945	)			—				—				—				(2,945	)
Cancellation of treasury stock			(5	)			—				(48	)			5				101				(53	)			—				—				—
Non-cash equity-based compensation			—				—				4,613				—				—				—				34				—				4,647
ENP cash distributions to noncontrolling interests			—				—				—				—				—				—				(6,077	)			—				(6,077	)
Other			—				—				40				—				—				—				—				—				40
Components of comprehensive loss:
Net loss			—				—				—				—				—				(7,556	)			1,653				—				(5,903	)
Change in deferred hedge loss on interest rate swaps, net of tax of $169			—				—				—				—				—				—				(204	)			(341	)			(545	)
Total comprehensive loss																																			(6,448	)
Balance at March 31, 2009			51,930			$	518			$	530,440				(111	)		$	(2,945	)		$	782,089			$	164,526			$	(2,089	)		$	1,472,539

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

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

		Three months ended
		March 31,
		2009				2008
Cash flows from operating activities:
Net income (loss) attributable to EAC		$	(7,556	)		$	31,220
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization			70,300				49,543
Non-cash exploration expense			10,991				3,656
Deferred taxes			(8,609	)			14,623
Non-cash equity-based compensation expense			4,080				2,896
Non-cash derivative loss			13,474				62,176
Gain on disposition of assets			(8	)			(23	)
Noncontrolling interest			1,653				94
Other			1,928				2,376
Changes in operating assets and liabilities:
Accounts receivable			58,496				(16,753	)
Current derivatives			266,118				(670	)
Other current assets			7,716				(18,459	)
Long-term derivatives			—				(1,196	)
Other assets			(41	)			(67	)
Accounts payable			5,870				(6,303	)
Other current liabilities			27,371				8,953
Other noncurrent liabilities			(158	)			(339	)
Net cash provided by operating activities			451,625				131,727
Cash flows from investing activities:
Proceeds from disposition of assets			259				184
Purchases of other property and equipment			(458	)			(1,054	)
Acquisition of oil and natural gas properties			(9,484	)			(30,780	)
Development of oil and natural gas properties			(153,092	)			(97,802	)
Net collections from (advances to) working interest partners			1,651				(8,972	)
Net cash used in investing activities			(161,124	)			(138,424	)
Cash flows from financing activities:
Repurchase and retirement of common stock			—				(39,118	)
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases			(2,871	)			684
Proceeds from long-term debt, net of issuance costs			66,000				357,274
Payments on long-term debt			(253,000	)			(303,500	)
ENP cash distributions to noncontrolling interests			(6,077	)			(4,198	)
Payment of commodity derivative contract premiums			(68,626	)			(8,534	)
Change in cash overdrafts			(4,494	)			2,590
Net cash provided by (used in) financing activities			(269,068	)			5,198
Increase (decrease) in cash and cash equivalents			21,433				(1,499	)
Cash and cash equivalents, beginning of period			2,039				1,704
Cash and cash equivalents, end of period		$	23,472			$	205

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

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Description of Business

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

	•		the Cedar Creek Anticline (“CCA”) in the Williston Basin in Montana and North Dakota;
	•		the Permian Basin in West Texas and southeastern New Mexico;
	•		the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and
	•		the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Arkansas and Oklahoma, the North Louisiana Salt Basin, and the East Texas Basin.

Note 2. Basis of Presentation

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

     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, EAC’s financial position as of March 31, 2009 and results of operations and cash flows for the three months ended March 31, 2009 and 2008. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

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

Noncontrolling Interest

     As of March 31, 2009 and December 31, 2008, EAC owned approximately 63 percent 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 indirect wholly owned non-guarantor subsidiary of EAC. GP LLC is ENP’s general partner. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” the financial position, results of operations, and cash flows of ENP are consolidated with those of EAC.

     As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of March 31, 2009 and December 31, 2008 of $164.5 million and $169.1 million, respectively, represents third-party ownership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Net income attributable to noncontrolling interest” for the three months ended March 31, 2009 and 2008 of $1.7 million and $0.1 million, respectively, represents the net income of ENP attributable to third-party owners.

Supplemental Disclosures of Cash Flow Information

     The following table sets forth supplemental disclosures of cash flow information for the periods indicated:

		Three months ended March 31,
		2009				2008
		(In thousands)
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts		$	17,044			$	25,685

Reclassifications

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

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

New Accounting Pronouncements

FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”)

     In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157, “Fair Value Measurements” (“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 FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. FSP FAS 157-2 was prospectively effective for nonfinancial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of FSP FAS 157-2 on January 1, 2009, as it relates to nonfinancial assets and liabilities, did not have a material impact on EAC’s results of operations or financial condition. Please read “Note 6. Fair Value Measurements” for additional discussion.

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

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

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

     In December 2007, the FASB issued SFAS 160, which 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 was prospectively effective for fiscal years beginning on or after December 15, 2008, except for the presentation and disclosure requirements which are retrospective. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition.

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, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), to require enhanced disclosures, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 was effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 on January 1, 2009 required additional disclosures regarding EAC’s derivative instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 5. Derivative Financial Instruments” for additional discussion.

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

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

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

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

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

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

     In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 is prospectively effective for interim reporting periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 will require additional disclosures regarding EAC’s financial instruments; however, it will not impact EAC’s results of operations or financial condition.

Note 3. Inventory

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

		March 31,				December 31,
		2009				2008
		(in thousands)
Materials and supplies		$	24,969			$	15,933
Oil in pipelines			8,322				8,865
Total inventory		$	33,291			$	24,798

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

Note 4. Proved Properties

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

		March 31,				December 31,
		2009				2008
		(in thousands)
Proved leasehold costs		$	1,423,174			$	1,421,859
Wells and related equipment — Completed			2,097,192				1,943,275
Wells and related equipment — In process			133,353				173,325
Total proved properties		$	3,653,719			$	3,538,459

Note 5. Derivative Financial Instruments

Derivative Policy

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

     EAC applies the provisions of SFAS 133, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive loss until such time as the hedged item is recognized in earnings.

     In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Cash flow hedges are marked to market through accumulated other comprehensive loss each period.

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

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

Commodity Derivative Contracts

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

     From time to time, EAC sells floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. 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 (gain)” in the accompanying Consolidated Statements of Operations. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.

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

     The following tables summarize EAC’s open commodity derivative contracts as of March 31, 2009:

Oil Derivative Contracts

		Average				Weighted					Average				Weighted					Average				Weighted
		Daily				Average					Daily				Average					Daily				Average					Asset
		Floor				Floor					Cap				Cap					Swap				Swap					Fair Market
Period		Volume				Price					Volume				Price					Volume				Price					Value
		(Bbls)				(per Bbl)					(Bbls)				(per Bbl)					(Bbls)				(per Bbl)					(in thousands)
Apr. — Dec. 2009 (a)																													$	50,326
			3,130			$	110.00					440			$	97.75					—			$	—
			—				—					—				—					1,000				68.70
2010																														29,759
			880				80.00					440				93.80					—				—
			2,000				75.00					2,500				73.43					—				—
			5,000				60.80					500				65.60					—				—
			1,000				56.00					—				—					2,000				60.84
2011																														15,550
			1,880				80.00					1,440				95.41					—				—
			1,000				70.00					—				—					—				—
																													$	95,635

Natural Gas Derivative Contracts

		Average				Weighted					Average				Weighted					Average				Weighted
		Daily				Average					Daily				Average					Daily				Average					Asset
		Floor				Floor					Cap				Cap					Swap				Swap					Fair Market
Period		Volume				Price					Volume				Price					Volume				Price					Value
		(Mcf)				(per Mcf)					(Mcf)				(per Mcf)					(Mcf)				(per Mcf)					(in thousands)
Apr. — Dec. 2009																													$	20,259
			3,800			$	8.20					3,800			$	9.83					—			$	—
			3,800				7.20					5,000				7.45					—				—
			6,800				6.57					15,000				6.63					—				—
			15,000				5.64					—				—					—				—
2010																														7,747
			3,800				8.20					3,800				9.58					—				—
			4,698				7.26					—				—					902				6.30
2011																														761
			898				6.76					—				—					902				6.70
2012																														575
			898				6.76					—				—					902				6.66
																													$	29,342

     The following table summarizes the fair value of EAC’s commodity derivative contracts as of March 31, 2009:

(in thousands)

Asset Derivatives

Liability Derivatives

Current

Long-Term

Current

Long-Term

Derivatives not designated as

hedging instruments

Balance Sheet

Balance Sheet

Balance Sheet

Balance Sheet

under SFAS 133

Location

Fair Value

Location

Fair Value

Location

Fair Value

Location

Fair Value

Commodity derivative contracts

Derivatives —

Derivatives —

Derivatives —

Derivatives —

current assets

$

81,378

long-term assets

$

45,642

current liabilities

$

36

long-term liabilities

$

2,007

     As of March 31, 2009, EAC had $16.6 million of deferred premiums payable, of which $11.6 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $5.0 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate

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

to various oil and natural gas floor contracts and are payable on a monthly basis from April 2009 to January 2011. EAC recorded these premiums at their net present value at the time the contracts were entered into and accretes that value to the eventual settlement price by recording interest expense each period.

     Counterparty Risk. At March 31, 2009, EAC had committed greater than 10 percent (in terms of fair market value) of either its oil or natural gas derivative contracts to the following counterparties:

		Percentage of				Percentage of
		Oil Derivative				Natural Gas Derivative
		Contracts				Contracts
Counterparty		Committed				Committed
BNP Paribas			53	%			18	%
Calyon			24	%			40	%
JP Morgan			7	%			18	%
Wachovia Bank			3	%			23	%

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

Interest Rate Swaps

     ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit facility to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swaps as of March 31, 2009, all of which were entered into with Bank of America, N.A.:

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

     The following table summarizes the fair value of EAC’s interest rate swaps as of March 31, 2009:

(in thousands)

Liability Derivatives

Current

Long-Term

Derivatives designated as

Balance Sheet

Balance Sheet

hedging instruments under SFAS 133

Location

Fair Value

Location

Fair Value

Interest rate swaps

Derivatives —

Derivatives —

current liabilities

$

3,143

long-term liabilities

$

2,043

     The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred loss recorded in accumulated other comprehensive loss due to the fluctuation of interest rates.

Current Period Impact

     EAC recognized derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not

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

designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:

		Three months ended
		March 31,
		2009				2008
		(in thousands)
Ineffectiveness		$	89			$	(381	)
Mark-to-market loss			202,782				45,614
Premium amortization			77,955				15,513
Settlements			(329,417	)			4,392
Total derivative fair value loss (gain)		$	(48,591	)		$	65,138

     In March 2009, EAC elected to monetize certain of its 2009 oil derivative contracts representing approximately 77 percent of its consolidated 2009 oil derivative contracts. EAC received proceeds of approximately $190.4 million from these settlements, which were used to reduce outstanding borrowings under EAC’s revolving credit facility.

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

						Amount of Loss (Gain) Recognized
						In Income
Derivatives Not Designated as		Location of Loss (Gain)				Three Months Ended March 31,
Hedges Under SFAS 133		Recognized In Income				2009				2008
						(in thousands)
Commodity derivative contracts		Derivative fair value loss (gain)				$	(48,680	)		$	65,519

     The following table summarizes the effect of derivative instruments designated as hedges under SFAS 133 on the Consolidated Statements of Operations for the periods indicated:

(in thousands)														Amount of Loss (Gain)
		Amount of Loss (Gain)												Reclassified from												Amount of Loss (Gain)
		Recognized in OCI								Location of Loss				Accumulated OCI into												Recognized In Income
		(Effective Portion)								(Gain) Reclassified				Income (Effective Portion)												as Ineffective
		Three months ended								from Accumulated				Three months ended								Location of Loss (Gain)				Three months ended
Derivatives Designated as		March 31,								OCI into Income				March 31,								Recognized in Income				March 31,
Hedges Under SFAS 133		2009				2008				(Effective Portion)				2009				2008				as Ineffective				2009				2008
Interest rate swaps		$	715			$	1,568			Interest expense				$	881			$	(18	)		Derivative fair value loss (gain)				$	(89	)		$	(381	)
Commodity derivative contracts			—				—			Oil and natural gas revenues					—				1,429								—				—
Total		$	715			$	1,568							$	881			$	1,411							$	(89	)		$	(381	)

Accumulated Other Comprehensive Loss

     At March 31, 2009 and December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $2.1 million and $1.7 million, respectively. During the twelve months ending March 31, 2010, EAC expects to reclassify $3.1 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense and $1.1 million of deferred income taxes to income tax benefit.

Note 6. Fair Value Measurements

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

•

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

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

	•		Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.
	•		Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

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

	•		Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.
	•		Level 3 — Fair values of oil and natural gas floors and caps were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets.

     The following table sets forth EAC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009:

						Fair Value Measurements at Reporting Date Using
						Quoted Prices in
						Active Markets for				Significant Other				Significant
		Asset (Liability) at				Identical Assets				Observable Inputs				Unobservable Inputs
Description		March 31, 2009				(Level 1)				(Level 2)				(Level 3)
		(in thousands)
Oil derivative contracts — swaps		$	2,467			$	—			$	2,467			$	—
Oil derivative contracts — floors and caps			93,168				—				—				93,168
Natural gas derivative contracts — swaps			707				—				707				—
Natural gas derivative contracts — floors and caps			28,635				—				—				28,635
Interest rate swaps			(5,186	)			—				(5,186	)			—
Total		$	119,791			$	—			$	(2,012	)		$	121,803

     The following table summarizes the changes in the fair value of EAC’s Level 3 financial assets and liabilities for the three months ended March 31, 2009:

		Fair Value Measurements Using Significant
		Unobservable Inputs (Level 3)
		Oil Derivative				Natural Gas
		Contracts —				Derivative Contracts —
		Floors and Caps				Floors and Caps				Total
						(in thousands)
Balance at January 1, 2009		$	337,335			$	12,741			$	350,076
Total gains (losses):
Included in earnings			39,008				21,607				60,615
Purchases, issuances, and settlements			(283,175	)			(5,713	)			(288,888	)
Balance at March 31, 2009		$	93,168			$	28,635			$	121,803
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		$	39,008			$	21,607			$	60,615

     Since EAC does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 financial assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. All fair values have been adjusted for non-performance risk, resulting in a reduction of the net commodity derivative asset of approximately $2.0 million as of March 31, 2009.

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

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

•

Level 3 — Fair value of goodwill is determined using the estimated price EAC would receive to sell the reportable units. These inputs are not readily available in public markets. Fair values of other intangibles and asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets.

     The following table sets forth EAC’s nonfinancial assets and liabilities that were accounted for at fair value on a nonrecurring basis as of March 31, 2009:

						Fair Value Measurements Using
						Quoted Prices in
						Active Markets for				Significant Other				Significant
		Asset (Liability) at				Identical Assets				Observable Inputs				Unobservable Inputs				Total Gains
Description		March 31, 2009				(Level 1)				(Level 2)				(Level 3)				(Losses)
		(in thousands)
Goodwill		$	60,606			$	—			$	—			$	60,606			$	—
Other intangibles, net			3,575				—				—				3,575				—
Asset retirement obligations			(48,762	)			—				—				(48,762	)			—
Total		$	15,419			$	—			$	—			$	15,419			$	—

Note 7. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in EAC’s asset retirement obligations for the three months ended March 31, 2009 (in thousands):

Future abandonment liability at January 1, 2009		$	49,569
Wells drilled			165
Accretion of discount			598
Plugging and abandonment costs incurred			(158	)
Revision of previous estimates			(1,412	)
Future abandonment liability at March 31, 2009		$	48,762

     As of March 31, 2009, $47.3 million of EAC’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $1.5 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.4 million of the future abandonment liability represents the estimated cost for decommissioning ENP’s Elk Basin natural gas processing plant. ENP expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant.

     As of March 31, 2009 and December 31, 2008, EAC held $9.2 million in escrow, which is to be released only for reimbursement of actual plugging and abandonment costs incurred on its Bell Creek properties, which is included in other long-term assets in the accompanying Consolidated Balance Sheets.

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

Note 8. Long-Term Debt

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

		Maturity				March 31,				December 31,
		Date				2009				2008
						(in thousands)
Revolving credit facilities			3/7/2012			$	538,000			$	725,000
6.25% Senior Subordinated Notes			4/15/2014				150,000				150,000
6.0% Senior Subordinated Notes, net of unamortized discount of $3,834 and $3,960, respectively			7/15/2015				296,166				296,040
7.25% Senior Subordinated Notes, net of unamortized discount of $1,204 and $1,229, respectively			12/1/2017				148,796				148,771
Total						$	1,132,962			$	1,319,811

Encore Acquisition Company Senior Secured Credit Agreement

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

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base of the EAC Credit Agreement was reaffirmed at $1.1 billion before an adjustment of $200 million solely as a result of the monetization of certain of EAC’s 2009 oil derivative contracts during the first quarter of 2009. As of March 31, 2009, the borrowing base was $900 million and there were $353 million of outstanding borrowings and $547 million of borrowing capacity under the EAC Credit Agreement. As of March 31, 2009, EAC was in compliance with all covenants of the EAC Credit Agreement.

     Eurodollar loans under the EAC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the EAC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

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