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

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

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)

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.

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

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 October 27, 2009		55,541,823

 

 

ENCORE ACQUISITION COMPANY

INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008			1
Consolidated Statements of Operations for the three and nine months ended September 30, 2009 and 2008			2
Consolidated Statement of Equity and Comprehensive Loss for the nine months ended September 30, 2009			3
Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008			4
Notes to Consolidated Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			43
Item 3. Quantitative and Qualitative Disclosures About Market Risk			62
Item 4. Controls and Procedures			63
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			64
Item 1A. Risk Factors			64
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			64
Item 6. Exhibits			64
EX-10.1
EX-10.2
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 United States Securities and Exchange Commission (“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.

 i

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.

	•		ASC. FASB Accounting Standards Codification.
	•		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 nine 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.
	•		Production Taxes. Production expense attributable to production, ad valorem, and severance taxes.
	•		Productive Well or Successful Well. A well capable of producing hydrocarbons in commercial quantities, including natural

ENCORE ACQUISITION COMPANY

			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 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.
	•		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 par value amounts)

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

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

ENCORE ACQUISITION COMPANY

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

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

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

ENCORE ACQUISITION COMPANY

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

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

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

ENCORE ACQUISITION COMPANY

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

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

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

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Description of Business

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

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

Note 2. Basis of Presentation

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

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

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

Noncontrolling Interest

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

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

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

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

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

Supplemental Disclosures of Non-cash Investing and Financing Activities

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

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

Allowance for Doubtful Accounts

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

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

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

Reclassifications

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

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

FASB Launches Accounting Standards Codification

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

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

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

New Accounting Pronouncements

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Note 3. Acquisitions

Acquisitions from EXCO

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

CO2 Supply Agreement

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

Note 4. Inventory

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

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

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

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

Note 5. Proved Properties

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

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

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

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

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

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

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

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

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

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

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

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

Derivative Policy

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

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

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

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

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

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

Commodity Derivative Contracts

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

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

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

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

Oil Derivative Contracts

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

Natural Gas Derivative Contracts

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

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

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

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

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

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

Interest Rate Swaps

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

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