exv99w5

Exhibit 99.5

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): January 25, 2010

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)


Delaware	001-16295	75-2759650

(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)


777 Main Street, Suite 1400, Fort Worth, Texas		76102

(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (817) 877-9955

Not applicable

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

On January 1, 2009, Encore Acquisition Company (together with its subsidiaries, “EAC”) adopted new guidance issued by the Financial Accounting Standards Board on the accounting for noncontrolling interests and new guidance relating to the treatment of equity-based payment transactions in the calculation of earnings per share.

In August 2009, Encore Operating, L.P. (“Encore Operating”), a wholly owned subsidiary of EAC, sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota to Encore Energy Partners LP (together with its subsidiaries, “ENP”). In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana to ENP. In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres, to ENP. Because these assets were sold to an affiliate, the dispositions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby ENP recorded the assets and liabilities of the acquired properties at Encore Operating’s carrying value and ENP’s historical financial information was recast to include the acquired properties for all periods presented. EAC has recast segment information in its consolidated financial statements to reflect these transactions.

Accordingly, EAC has recast certain information included in its 2008 Annual Report on Form 10-K (the “2008 Annual Report”) filed with the United States Securities and Exchange Commission (“SEC”) on February 24, 2009 as follows:

	•		Item 6. Selected Financial Data;

	•		Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations; and

	•		Item 8. Financial Statements and Supplementary Data.

The recast financial information is filed as Exhibits 99.1, 99.2, and 99.3 to this Current Report on Form 8-K (the “Report”) and is incorporated herein by reference. Except with respect to the limited matters described above, the recast information included in this Report has not been updated to reflect events subsequent to the filing of the 2008 Annual Report. This Report should be read in conjunction with the portions of the 2008 Annual Report that have not been recast herein, as well as in conjunction with EAC’s other filings with the SEC.

All references in this Report to “EAC,” “we,” “us,” “our,” and similar terms refer to Encore Acquisition Company and its subsidiaries.

Cautionary Statement Regarding Forward-Looking Statements

Certain information included or incorporated by reference in this Report and other materials filed with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements. 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. In particular, forward-looking statements relate to, among other things, the following:

	•		items of income and expense (including, without limitation, lease operating expense, production taxes, depletion, depreciation, and amortization expense, general and administrative expense, and effective income tax rates);

	•		expected capital expenditures and the focus of our capital program;

	•		areas of future growth;

	•		our development and exploitation programs;

	•		future secondary development and tertiary recovery potential;

	•		anticipated prices for oil and natural gas and expectations regarding differentials between wellhead prices and benchmark prices (including, without limitation, the effects of the worldwide economic recession);

	•		projected results of operations;

	•		timing and amount of future production of oil and natural gas;

	•		availability of pipeline capacity;

	•		expected commodity derivative positions and payments related thereto (including the ability of counterparties to fulfill obligations);

	•		expectations regarding working capital, cash flow, and liquidity;

	•		projected borrowings or repayments under our revolving credit facility (and the ability of lenders to fund their commitments); and

	•		the marketing of our oil and natural gas production.

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 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.

Item 9.01 Financial Statements and Exhibits

(d) Exhibits


99.1		Selected Financial Data.

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

99.3		Financial Statements and Supplementary Data.

Exhibit 99.1

ENCORE ACQUISITION COMPANY

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data shown below as of December 31, 2008 and 2007 and for the years ended December 31, 2008, 2007, and 2006 (collectively, the “Recast Financial Statements”) was derived from our recast audited consolidated financial statements. The selected historical financial data shown below as of December 31, 2006, 2005, and 2004 and for the years ended December 31, 2005 and 2004 was derived from recast unaudited consolidated financial statements. The following recast selected financial and operating data should be read in conjunction with our recast “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Recast Financial Statements included as Exhibits 99.2 and 99.3, respectively, to this Current Report on Form 8-K.


	Year Ended December 31, (a)
	2008			2007			2006			2005			2004
	(in thousands, except per share and per unit amounts)
Consolidated Statements of Operations Data:
Revenues (b):
Oil	$	897,443		$	562,817		$	346,974		$	307,959		$	220,649
Natural gas		227,479			150,107			146,325			149,365			77,884
Marketing (c)		10,496			42,021			147,563			—			—

Total revenues		1,135,418			754,945			640,862			457,324			298,533


Expenses:
Production:
Lease operating (d)		175,115			143,426			98,194			69,744			47,807
Production, ad valorem, and severance taxes		110,644			74,585			49,780			45,601			30,313
Depletion, depreciation, and amortization		228,252			183,980			113,463			85,627			48,522
Impairment of long-lived assets (e)		59,526			—			—			—			—
Exploration		39,207			27,726			30,519			14,443			3,935
General and administrative (d)		48,421			39,124			23,194			17,268			12,059
Marketing (c)		9,570			40,549			148,571			—			—
Derivative fair value loss (gain) (f)		(346,236	)		112,483			(24,388	)		5,290			5,011
Loss on early redemption of debt (g)		—			—			—			19,477			—
Provision for doubtful accounts		1,984			5,816			1,970			231			—
Other operating		12,975			17,066			8,053			9,254			5,028

Total expenses		339,458			644,755			449,356			266,935			152,675


Operating income		795,960			110,190			191,506			190,389			145,858


Other income (expenses):
Interest		(73,173	)		(88,704	)		(45,131	)		(34,055	)		(23,459	)
Other		3,898			2,667			1,429			1,039			240

Total other expenses		(69,275	)		(86,037	)		(43,702	)		(33,016	)		(23,219	)


Income before income taxes		726,685			24,153			147,804			157,373			122,639
Income tax provision		(241,621	)		(14,476	)		(55,406	)		(53,948	)		(40,492	)

Consolidated net income		485,064			9,677			92,398			103,425			82,147
Less: net loss (income) attributable to noncontrolling interest		(54,252	)		7,478			—			—			—

Net income attributable to EAC stockholders	$	430,812		$	17,155		$	92,398		$	103,425		$	82,147


Net income per common share:
Basic	$	8.10		$	0.32		$	1.75		$	2.10		$	1.73	(h)
Diluted	$	8.01		$	0.31		$	1.74		$	2.07		$	1.71	(h)

Weighted average common shares outstanding:
Basic		52,270			53,170			51,865			48,682			47,090	(h)
Diluted		52,866			53,629			52,356			49,303			47,522	(h)

Total Production Volumes:
Oil (Bbls)		10,050			9,545			7,335			6,871			6,679
Natural gas (Mcf)		26,374			23,963			23,456			21,059			14,089
Combined (BOE)		14,446			13,539			11,244			10,381			9,027
Average Realized Prices:
Oil ($/Bbl)	$	89.30		$	58.96		$	47.30		$	44.82		$	33.04
Natural gas ($/Mcf)		8.63			6.26			6.24			7.09			5.53
Combined ($/BOE)		77.87			52.66			43.87			44.05			33.07
Average Costs per BOE:
Lease operating (d)	$	12.12		$	10.59		$	8.73		$	6.72		$	5.30
Production, ad valorem, and severance taxes		7.66			5.51			4.43			4.39			3.36
Depletion, depreciation, and amortization		15.80			13.59			10.09			8.25			5.38
Impairment of long-lived assets (e)		4.12			—			—			—			—
Exploration		2.71			2.05			2.71			1.39			0.44
General and administrative (d)		3.35			2.89			2.06			1.67			1.33
Derivative fair value loss (gain) (f)		(23.97	)		8.31			(2.17	)		0.51			0.56
Provision for doubtful accounts		0.14			0.43			0.18			0.02			—
Other operating		0.90			1.26			0.72			0.89			0.56
Marketing, net of revenues (c)		(0.06	)		(0.11	)		0.09			—			—

Consolidated Statements of Cash Flows Data:
Cash provided by (used in):
Operating activities	$	663,237		$	319,707		$	297,333		$	292,269		$	171,821
Investing activities		(728,346	)		(929,556	)		(397,430	)		(573,560	)		(433,470	)
Financing activities		65,444			610,790			99,206			281,842			262,321

ENCORE ACQUISITION COMPANY


	As of December 31, (a)
	2008		2007			2006			2005			2004
	(in thousands)
Proved Reserves:
Oil (Bbls)		134,452		188,587			153,434			148,387			134,048
Natural gas (Mcf)		307,520		256,447			306,764			283,865			234,030
Combined (BOE)		185,705		231,328			204,561			195,698			173,053
Consolidated Balance Sheets Data:
Working capital	$	188,678	$	(16,220	)	$	(40,745	)	$	(56,838	)	$	(15,566	)
Total assets		3,633,195		2,784,561			2,006,900			1,705,705			1,123,400
Long-term debt		1,319,811		1,120,236			661,696			673,189			379,000
Equity		1,483,248		1,070,689			816,865			546,781			473,575


(a)		We acquired certain oil and natural gas properties and related assets in the Big Horn and Williston Basins in March 2007 and April 2007, respectively. We also acquired Crusader Energy Corporation in October 2005 and Cortez Oil & Gas, Inc. in April 2004. The operating results of these acquisitions are included with ours from the date of acquisition forward. We disposed of certain oil and natural gas properties and related assets in the Mid-Continent in June 2007. The operating results of this disposition are included with ours through the date of disposition.

(b)		For 2008, 2007, 2006, 2005, and 2004, we reduced oil and natural gas revenues for net profits interests owned by others by $56.5 million, $32.5 million, $23.4 million, $21.2 million, and $12.6 million, respectively.

(c)		In 2006, we began purchasing third-party oil Bbls from a counterparty other than to whom the Bbls were sold for aggregation and sale with our own equity production in various markets. These purchases assisted us in marketing our production by decreasing our dependence on individual markets. These activities allowed us to aggregate larger volumes, facilitated our efforts to maximize the prices we received for production, provided for a greater allocation of future pipeline capacity in the event of curtailments, and enabled us to reach other markets. In 2007, we discontinued purchasing oil from third party companies as market conditions changed and pipeline space was gained. Implementing this change allowed us to focus on the marketing of our own oil production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets. Marketing expenses include pipeline tariffs, storage, truck facility fees, and tank bottom costs used to support the sale of equity crude, the revenues of which are included in our oil revenues instead of marketing revenues.

(d)		On January 1, 2006, we adopted new guidance issued by the FASB in the “Compensation — Stock Compensation” topic of the FASC. Due to the adoption, non-cash equity-based compensation expense for 2005 and 2004 has been reclassified to allocate the amount to the same respective income statement lines as the respective employees’ cash compensation. This resulted in increases in LOE of $1.3 million and $0.7 million during 2005 and 2004, respectively, increases in general and administrative expense of $2.6 million and $1.1 million during 2005 and 2004, respectively.

(e)		During 2008, circumstances indicated that the carrying amounts of certain oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, may not be recoverable. We compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

(f)		During July 2006, we elected to discontinue hedge accounting prospectively for all of our remaining commodity derivative contracts which were previously accounted for as hedges. From that point forward, mark-to-market gains or losses on commodity derivative contracts are recorded in “Derivative fair value loss (gain)” while in periods prior to that point, only the ineffective portions of commodity derivative contracts which were designated as hedges were recorded in “Derivative fair value loss (gain).”

(g)		In 2005, we recorded a $19.5 million loss on early redemption of debt related to the redemption premium and the expensing of unamortized debt issuance costs of our 8 3/8% Senior Subordinated Notes due 2012. We redeemed all $150 million of such notes with proceeds received from the issuance of $300 million of our 6.0% Senior Subordinated Notes due 2015.

(h)		Adjusted for the effects of the 3-for-2 stock split in July 2005.

Exhibit 99.2

ENCORE ACQUISITION COMPANY

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On January 1, 2009, Encore Acquisition Company (together with its subsidiaries, “EAC”) adopted new guidance issued by the Financial Accounting Standards Board (the “FASB”) on the accounting for noncontrolling interests and new guidance relating to the treatment of equity-based payment transactions in the calculation of earnings per share.

The following recast discussion and analysis of our consolidated financial condition and results of operations should be read in conjunction with our recast consolidated financial statements and notes and supplementary data thereto as of December 31, 2008 and 2007 and for the years ended December 31, 2008, 2007, and 2006 (collectively, the “Recast Financial Statements”) included as Exhibit 99.3 to this Current Report on Form 8-K. The following recast discussion and analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Actual results could differ materially from those discussed in the forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under “Cautionary Statement Regarding Forward-Looking Statements” included in this Current Report on Form 8-K and “Item 1A. Risk Factors” included in our 2008 Annual Report.

Introduction

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

	•		Overview of Business

	•		2008 Highlights

	•		Recent Developments

	•		2009 Outlook

	•		Results of Operations

	—		Comparison of 2008 to 2007

	—		Comparison of 2007 to 2006

	•		Capital Commitments, Capital Resources, and Liquidity

	•		Changes in Prices

	•		Critical Accounting Policies and Estimates

	•		New Accounting Pronouncements

	•		Information Concerning Forward-Looking Statements

Overview of Business

We are a Delaware corporation engaged in the acquisition, development, exploitation, exploration, and production of oil and natural gas reserves from onshore fields in the United States. Our business strategies include:

	•		Maintaining an active development program to maximize existing reserves and production;

	•		Utilizing enhanced oil recovery techniques to maximize existing reserves and production;

	•		Expanding our reserves, production, and development inventory through a disciplined acquisition program;

ENCORE ACQUISITION COMPANY

	•		Exploring for reserves; and

	•		Operating in a cost effective, efficient, and safe manner.

At December 31, 2008, our oil and natural gas properties had estimated total proved reserves of 134.5 MMBbls of oil and 307.5 Bcf of natural gas, based on December 31, 2008 spot market prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. On a BOE basis, our proved reserves were 185.7 MMBOE at December 31, 2008, of which approximately 72 percent was oil and approximately 80 percent was proved developed. Based on 2008 production, our ratio of reserves to production was approximately 12.9 years for total proved reserves and 10.3 years for proved developed reserves as of December 31, 2008.

Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Average NYMEX oil prices strengthened in the first half of 2008 to record levels, but have since experienced a significant deterioration. In addition, our oil wellhead differentials to NYMEX improved in 2008 as we realized 90 percent of the average NYMEX oil price, as compared to 88 percent in 2007. Average NYMEX natural gas prices strengthened in the first half of 2008 to their highest levels since 2005, but have since experienced a significant deterioration. Our natural gas wellhead differentials to NYMEX deteriorated slightly in 2008 as we realized 95 percent of the average NYMEX natural gas price, as compared to 98 percent in 2007. Commodity prices are influenced by many factors that are outside of our control. We cannot accurately predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by entering into commodity derivative contracts for a portion of our forecasted future production. For a discussion of factors that influence commodity prices and risks associated with our commodity derivative contracts, please read “Item 1A. Risk Factors” included in our 2008 Annual Report.

During 2008, we did not make a significant acquisition of proved reserves. Instead, we acquired unproved acreage in our core areas, continued to make significant investments within our core areas to develop proved undeveloped reserves and increase production from proved developed reserves through various recovery techniques, and made significant investments for exploration within our areas of unproved acreage. We continue to believe that a portfolio of long-lived quality assets will position us for future success.

In May 2008, we announced that our Board had authorized our management team to explore a broad range of strategic alternatives to further enhance shareholder value, including, but not limited to, a sale or merger of the company. In conjunction, our Board approved a retention plan for all of our then-current employees, excluding members of our strategic team, providing for the payment of four months of base salary or base rate of pay, as applicable, upon the completion of the strategic alternatives process, subject to continued employment. This bonus was paid in August 2008.

In July 2008, our Board and management team decided that a sale or merger of the company was not currently in the best interest of our shareholders. In conjunction, our Board approved a separate retention plan for all of our then-current employees, excluding our Chairman and Chief Executive Officer, providing for the payment of eight months of base salary or base rate of pay, as applicable, in August 2009, subject to continued employment.

Our 2008 results of operations include approximately $7.6 million of pre-tax expense related to the four-month retention plan and approximately $6.9 million of pre-tax expense related to the eight-month retention plan.

2008 Highlights

Our financial and operating results for 2008 included the following:

	•		Our oil and natural gas revenues increased 58 percent to $1.1 billion as compared to $712.9 million in 2007 as a result of increased production volumes and higher average realized prices.

	•		Our average realized oil price increased 51 percent to $89.30 per Bbl as compared to $58.96 per Bbl in 2007. Our average realized natural gas price increased 38 percent to $8.63 per Mcf as compared to $6.26 per Mcf in 2007.

	•		Our average daily production volumes increased six percent to 39,470 BOE/D as compared to 37,094 BOE/D in 2007. Oil represented 70 percent and 71 percent of our total production volumes in 2008 and 2007, respectively.

	•		Our production margin (defined as oil and natural gas wellhead revenues less production expenses) increased 54 percent to $842.0 million as compared to $548.5 million in 2007. Total oil and natural gas wellhead revenues per BOE increased by 38 percent while total production expenses per BOE increased by 23 percent. On a per BOE basis, our production margin increased 44 percent to $58.29 per BOE as compared to $40.52 per BOE for 2007.

	•		We reported record net income attributable to EAC stockholders for 2008, which increased to $430.8 million ($8.01 per diluted share) from the $17.2 million ($0.31 per diluted share) reported for 2007.

ENCORE ACQUISITION COMPANY

•

We invested $775.9 million in oil and natural gas activities (excluding asset retirement obligations of $0.6 million), of which $618.5 million was invested in development, exploitation, and exploration activities, yielding 282 gross (104.8 net) productive wells, and $157.4 million was invested in acquisitions, primarily of unproved acreage.

Recent Developments

In January 2009, we sold certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres to ENP. The sales price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million).

2009 Outlook

For 2009, the Board has approved a $310 million capital budget for oil and natural gas related activities, excluding proved property acquisitions. We expect to fund our 2009 capital expenditures within cash flows from operations and use the additional cash flows from operations to reduce our debt levels. The following table represents the components of our 2009 capital budget (in thousands):


Drilling	$	215,000
Improved oil recovery, workovers		60,000
Land, seismic, and other		35,000

Total	$	310,000

The prices we receive for our oil and natural gas production are largely based on current market prices, which are beyond our control. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects based on management’s outlook of future commodity prices. If NYMEX prices continue trend downward, we may further reevaluate our capital projects. Since the end of 2008, oil NYMEX prices have declined from $44.60 per Bbl to below $39.00 per Bbl in mid-February 2009 and natural gas NYMEX prices have declined from $5.62 per Mcf to below $4.25 per Mcf over the same period. The price risk on a significant portion of our forecasted oil and natural gas production for 2009 is mitigated using commodity derivative contracts. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” for additional information regarding our commodity derivative contracts. We intend to continue to enter into commodity derivative transactions to mitigate the impact of price volatility on our oil and natural gas revenues. Significant factors that will impact near-term commodity prices include the following:

	•		the duration and severity of the worldwide economic recession;

	•		political developments in Iraq, Iran, Venezuela, Nigeria, and other oil-producing countries;

	•		the extent to which members of OPEC and other oil exporting nations are able to manage oil supply through export quotas;

	•		Russia’s increasing position as a major supplier of natural gas to world markets;

	•		the level of economic growth in China, India, and other developing countries;

	•		concerns that major oil fields throughout the world have reached peak production;

	•		the level of interest rates;

	•		oilfield service costs;

	•		the potential for terrorist activity; and

	•		the value of the U.S. dollar relative to other currencies.

We expect to continue to pursue asset acquisitions, but expect to confront intense competition for these assets from third parties.

First Quarter 2009 Outlook

We expect our total average daily production volumes to be approximately 39,900 to 41,100 BOE/D in the first quarter of 2009, net of average daily net profits production volumes of approximately 900 to 1,100 BOE/D. We expect our oil wellhead differentials as a percentage of NYMEX to widen in the first quarter of 2009 to a negative 22 percent as compared to the negative 20 percent differential we realized in the fourth quarter of 2008. We expect our natural gas wellhead differentials as a percentage of NYMEX to improve in the first quarter of 2009 to a positive three percent as compared to the negative 14 percent differential we realized in the fourth quarter of 2008.

ENCORE ACQUISITION COMPANY

Results of Operations

Comparison of 2008 to 2007

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


	Year Ended December 31,						*Increase*
	2008			2007			$		%
Revenues (in thousands):
Oil wellhead	$	900,300		$	606,112		$	294,188
Oil commodity derivative contracts		(2,857	)		(43,295	)		40,438

Total oil revenues	$	897,443		$	562,817		$	334,626		59	%


Natural gas wellhead	$	227,479		$	160,399		$	67,080
Natural gas commodity derivative contracts		—			(10,292	)		10,292

Total natural gas revenues	$	227,479		$	150,107		$	77,372		52	%


Combined wellhead	$	1,127,779		$	766,511		$	361,268
Combined commodity derivative contracts		(2,857	)		(53,587	)		50,730

Total combined oil and natural gas revenues	$	1,124,922		$	712,924		$	411,998		58	%


Average realized prices:
Oil wellhead ($/Bbl)	$	89.58		$	63.50		$	26.08
Oil commodity derivative contracts ($/Bbl)		(0.28	)		(4.54	)		4.26

Total oil revenues ($/Bbl)	$	89.30		$	58.96		$	30.34		51	%


Natural gas wellhead ($/Mcf)	$	8.63		$	6.69		$	1.94
Natural gas commodity derivative contracts ($/Mcf)		—			(0.43	)		0.43

Total natural gas revenues ($/Mcf)	$	8.63		$	6.26		$	2.37		38	%


Combined wellhead ($/BOE)	$	78.07		$	56.62		$	21.45
Combined commodity derivative contracts ($/BOE)		(0.20	)		(3.96	)		3.76

Total combined oil and natural gas revenues ($/BOE)	$	77.87		$	52.66		$	25.21		48	%


Total production volumes:
Oil (MBbls)		10,050			9,545			505		5	%
Natural gas (MMcf)		26,374			23,963			2,411		10	%
Combined (MBOE)		14,446			13,539			907		7	%

Average daily production volumes:
Oil (Bbl/D)		27,459			26,152			1,307		5	%
Natural gas (Mcf/D)		72,060			65,651			6,409		10	%
Combined (BOE/D)		39,470			37,094			2,376		6	%

Average NYMEX prices:
Oil (per Bbl)	$	99.75		$	72.45		$	27.30		38	%
Natural gas (per Mcf)	$	9.04		$	6.86		$	2.18		32	%

Oil revenues increased 59 percent from $562.8 million in 2007 to $897.4 million in 2008 as a result of an increase in our average realized oil price and an increase in oil production volumes of 505 MBbls. The increase in oil production volumes contributed approximately $32.1 million in additional oil revenues and was primarily the result of a full year of production from our Big Horn Basin acquisition in March 2007 and our Williston Basin acquisition in April 2007, as well as our development program in the Bakken.

ENCORE ACQUISITION COMPANY

Our average realized oil price increased $30.34 per Bbl from 2007 to 2008 primarily as a result of an increase in our average realized oil wellhead price, which increased oil revenues by approximately $262.1 million, or $26.08 per Bbl. Our average realized oil wellhead price increased primarily as a result of the increase in the average NYMEX price from $72.45 per Bbl in 2007 to $99.75 per Bbl in 2008.

During July 2006, we elected to discontinue hedge accounting prospectively for all remaining commodity derivative contracts which were previously accounted for as hedges. While this change had no effect on our cash flows, results of operations are affected by mark-to-market gains and losses, which fluctuate with the changes in oil and natural gas prices. As a result, oil revenues for 2008 included amortization of net losses on certain commodity derivative contracts that were previously designated as hedges of approximately $2.9 million, or $0.28 per Bbl, while 2007 included approximately $43.3 million, or $4.54 per Bbl, of net losses.

Our average daily production volumes were decreased by 1,530 BOE/D and 1,466 BOE/D in 2008 and 2007, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by $55.3 million and $31.9 million in 2008 and 2007, respectively.

Natural gas revenues increased 52 percent from $150.1 million in 2007 to $227.5 million in 2008 as a result of an increase in our average realized natural gas price and an increase in natural gas production volumes of 2,411 MMcf. The increase in natural gas production volumes contributed approximately $16.1 million in additional natural gas revenues and was primarily the result of our development program in our Permian Basin and Mid-Continent regions.

Our average realized natural gas price increased $2.37 per Mcf from 2007 to 2008 primarily as a result of an increase in our average realized natural gas wellhead price, which increased natural gas revenues by approximately $50.9 million, or $1.94 per Mcf. Our average realized natural gas wellhead price increased primarily as a result of the increase in the average NYMEX price from $6.86 per Mcf in 2007 to $9.04 per Mcf in 2008. In addition, as a result of our discontinuance of hedge accounting in July 2006, natural gas revenues for 2007 included amortization of net losses on certain commodity derivative contracts that were previously designated as hedges of approximately $10.3 million, or $0.43 per Mcf.

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


	Year Ended December 31,
	2008			2007
Oil wellhead ($/Bbl)	$	89.58		$	63.50
Average NYMEX ($/Bbl)	$	99.75		$	72.45
Differential to NYMEX	$	(10.17	)	$	(8.95	)
Oil wellhead to NYMEX percentage		90	%		88	%

Natural gas wellhead ($/Mcf)	$	8.63		$	6.69
Average NYMEX ($/Mcf)	$	9.04		$	6.86
Differential to NYMEX	$	(0.41	)	$	(0.17	)
Natural gas wellhead to NYMEX percentage		95	%		98	%

Our oil wellhead price as a percentage of the average NYMEX price was 90 percent in 2008 as compared to 88 percent in 2007. Our natural gas wellhead price as a percentage of the average NYMEX price was 95 percent in 2008 as compared to 98 percent in 2007.

Marketing revenues and expenses. In 2007, we discontinued purchasing oil from third party companies as market conditions changed and pipeline space was gained. Implementing this change allowed us to focus on the marketing of our own oil production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets. Marketing expenses include pipeline tariffs, storage, truck facility fees, and tank bottom costs used to support the sale of oil production, the revenues of which are included in our oil revenues instead of marketing revenues. The following table summarizes our marketing activities for the periods indicated:

ENCORE ACQUISITION COMPANY


	Year ended December 31,				*Decrease*
	2008		2007		$			%
	($ in thousands, except per BOE amounts)
Marketing revenues	$	10,496	$	42,021	$	(31,525	)		-75	%
Marketing expenses		9,570		40,549		(30,979	)		-76	%

Marketing gain	$	926	$	1,472	$	(546	)		-37	%


Marketing revenues per BOE	$	0.72	$	3.10	$	(2.38	)		-77	%
Marketing expenses per BOE		0.66		2.99		(2.33	)		-78	%

Marketing gain, per BOE	$	0.06	$	0.11	$	(0.05	)		-45	%

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


	Year Ended December 31,					*Increase / (Decrease)*
	2008			2007		$			%
Expenses (in thousands):
Production:
Lease operations	$	175,115		$	143,426	$	31,689
Production, ad valorem, and severance taxes		110,644			74,585		36,059

Total production expenses		285,759			218,011		67,748			31	%
Other:
Depletion, depreciation, and amortization		228,252			183,980		44,272
Impairment of long-lived assets		59,526			—		59,526
Exploration		39,207			27,726		11,481
General and administrative		48,421			39,124		9,297
Derivative fair value loss (gain)		(346,236	)		112,483		(458,719	)
Provision for doubtful accounts		1,984			5,816		(3,832	)
Other operating		12,975			17,066		(4,091	)

Total operating		329,888			604,206		(274,318	)		-45	%
Interest		73,173			88,704		(15,531	)
Income tax provision		241,621			14,476		227,145

Total expenses	$	644,682		$	707,386	$	(62,704	)		-9	%


Expenses (per BOE):
Production:
Lease operations	$	12.12		$	10.59	$	1.53
Production, ad valorem, and severance taxes		7.66			5.51		2.15

Total production expenses		19.78			16.10		3.68			23	%
Other:
Depletion, depreciation, and amortization		15.80			13.59		2.21
Impairment of long-lived assets		4.12			—		4.12
Exploration		2.71			2.05		0.66
General and administrative		3.35			2.89		0.46
Derivative fair value loss (gain)		(23.97	)		8.31		(32.28	)
Provision for doubtful accounts		0.14			0.43		(0.29	)
Other operating		0.90			1.26		(0.36	)

Total operating		22.83			44.63		(21.80	)		-49	%
Interest		5.07			6.55		(1.48	)
Income tax provision		16.73			1.07		15.66

Total expenses	$	44.63		$	52.25	$	(7.62	)		-15	%

Production expenses. Total production expenses increased 31 percent from $218.0 million in 2007 to $285.8 million in 2008 as a result of higher total production volumes and an increase in the per BOE rate.

Production expense attributable to LOE increased $31.7 million from $143.4 million in 2007 to $175.1 million in 2008 as a result

ENCORE ACQUISITION COMPANY

of a $1.53 increase in the average per BOE rate, which contributed approximately $22.1 million of additional LOE, and an increase in production volumes, which contributed approximately $9.6 million of additional LOE. The increase in our average LOE per BOE rate was attributable to:

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

	•		increases in natural gas prices resulting in higher electricity costs and gas plant fuel costs;

	•		higher compensation levels for engineers and other technical professionals; and

	•		an increase of (1) approximately $4.7 million ($0.32 per BOE) for retention bonuses paid in August 2008 and (2) approximately $4.1 million ($0.28 per BOE) for retention bonuses to be paid in August 2009, related to our strategic alternatives process.

Production expense attributable to production, ad valorem, and severance taxes (“production taxes”) increased $36.1 million from $74.6 million in 2007 to $110.6 million in 2008 primarily due to higher wellhead revenues. As a percentage of oil and natural gas wellhead revenues, production taxes remained approximately constant at 9.8 percent in 2008 as compared to 9.7 percent in 2007.

DD&A expense. DD&A expense increased $44.3 million from $184.0 million in 2007 to $228.3 million in 2008 as a result of a $2.21 increase in the per BOE rate, which contributed approximately $32.0 million of additional DD&A expense, and an increase in production volumes, which contributed approximately $12.3 million of additional DD&A expense. The increase in our average DD&A per BOE rate was attributable to higher costs incurred resulting from increases in rig rates, pipe costs, and acquisition costs and the decrease in our total proved reserves to 185.7 MMBOE as of December 31, 2008 as compared to 231.3 MMBOE as of December 31, 2007.

Impairment of long-lived assets. During 2008, circumstances indicated that the carrying amounts of certain oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, may not be recoverable. We compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

Exploration expense. Exploration expense increased $11.5 million from $27.7 million in 2007 to $39.2 million in 2008. During 2008, we expensed 8 exploratory dry holes totaling $14.7 million. During 2007, we expensed 5 exploratory dry holes totaling $14.7 million. Impairment of unproved acreage increased $9.4 million from $10.8 million in 2007 to $20.2 million in 2008, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table illustrates the components of exploration expenses for the periods indicated:


	Year Ended December 31,
	2008		2007		*Increase*
			(in thousands)
Dry holes	$	14,683	$	14,673	$	10
Geological and seismic		2,851		1,455		1,396
Delay rentals		1,482		784		698
Impairment of unproved acreage		20,191		10,814		9,377

Total	$	39,207	$	27,726	$	11,481

G&A expense. G&A expense increased $9.3 million from $39.1 million in 2007 to $48.4 million in 2008, primarily due to:

	•		a full year of ENP public entity expenses;

	•		higher activity levels;

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

	•		an increase of (1) approximately $2.9 million for retention bonuses paid in August 2008 and (2) approximately $2.8 million for retention bonuses to be paid in August 2009, related to our strategic alternatives process;

	•		partially offset by a $3.1 million decrease in non-cash equity-based compensation.

Derivative fair value loss (gain). During 2008, we recorded a $346.2 million derivative fair value gain as compared to a $112.5 million derivative fair value loss in 2007, the components of which were as follows:

ENCORE ACQUISITION COMPANY


	Year Ended December 31,					*Increase /*
	2008			2007		*(Decrease)*
				(in thousands)
Ineffectiveness on designated derivative contracts	$	372		$	—	$	372
Mark-to-market loss (gain) on derivative contracts		(365,495	)		36,272		(401,767	)
Premium amortization		62,352			41,051		21,301
Settlements on commodity derivative contracts		(43,465	)		35,160		(78,625	)

Total derivative fair value loss (gain)	$	(346,236	)	$	112,483	$	(458,719	)

The change in our derivative fair value loss (gain) was a result of the addition of commodity derivative contracts in the first part of 2008 when prices were high and the significant decrease in prices during the end of 2008, which favorably impacted the fair values of those contracts.

During 2009, 2010, and 2011, we expect to make payments for deferred premiums of commodity derivative contracts of $67.0 million, $15.7 million, and $0.9 million, respectively.

Provision for doubtful accounts. In 2008 and 2007, we recorded a provision for doubtful accounts of $2.0 million and $5.8 million, respectively, for the payout allowance related to the ExxonMobil joint development agreement.

Other operating expense. Other operating expense decreased $4.1 million from $17.1 million in 2007 to $13.0 million in 2008, primarily due to a $7.4 million loss on the sale of certain Mid-Continent properties in 2007, partially offset by a $3.4 million increase during 2008 in third-party transportation costs to move our production to markets outside the immediate area of production.

Interest expense. Interest expense decreased $15.5 million from $88.7 million in 2007 to $73.2 million in 2008, primarily due to (1) the use of net proceeds from our Mid-Continent asset disposition and ENP’s IPO to reduce weighted average outstanding borrowings on our revolving credit facilities, (2) a reduction in LIBOR, and (3) our use of interest rate swaps to fix the rate on a portion of outstanding borrowings on ENP’s revolving credit facility. The weighted average interest rate for all long-term debt for 2008 was 5.6 percent as compared to 6.9 percent for 2007.

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


	Year Ended December 31,				*Increase /*
	2008		2007		*(Decrease)*
	(in thousands)
6.25% Notes	$	9,727	$	9,705	$	22
6.0% Notes		18,550		18,517		33
7.25% Notes		10,996		10,988		8
Revolving credit facilities		31,038		46,085		(15,047	)
Other		2,862		3,409		(547	)

Total	$	73,173	$	88,704	$	(15,531	)

Income taxes. In 2008, we recorded an income tax provision of $241.6 million as compared to $14.5 million in 2007. In 2008, we had income before income taxes of $726.7 million as compared to $24.2 million in 2007. Our effective tax rate decreased to 33.2 percent in 2008 as compared to 59.9 percent in 2007 primarily due to the 2007 recognition of non-deductible deferred compensation.

Noncontrolling interest. As of December 31, 2008, public unitholders owned approximately 37 percent of ENP’s common units. We consolidate ENP’s results of operations in our consolidated financial statements and show the public ownership as noncontrolling interest. Net income attributable to noncontrolling interest was approximately $54.3 million for 2008 as compared to a loss of $7.5 million for 2007.

Comparison of 2007 to 2006

ENCORE ACQUISITION COMPANY


	Year Ended December 31,						*Increase / (Decrease)*
	2007			2006			$			%
Revenues (in thousands):
Oil wellhead	$	606,112		$	399,180		$	206,932
Oil commodity derivative contracts		(43,295	)		(52,206	)		8,911

Total oil revenues	$	562,817		$	346,974		$	215,843			62	%


Natural gas wellhead	$	160,399		$	154,458		$	5,941
Natural gas commodity derivative contracts		(10,292	)		(8,133	)		(2,159	)

Total natural gas revenues	$	150,107		$	146,325		$	3,782			3	%


Combined wellhead	$	766,511		$	553,638		$	212,873
Combined commodity derivative contracts		(53,587	)		(60,339	)		6,752

Total combined oil and natural gas revenues	$	712,924		$	493,299		$	219,625			45	%


Average realized prices:
Oil wellhead ($/Bbl)	$	63.50		$	54.42		$	9.08
Oil commodity derivative contracts ($/Bbl)		(4.54	)		(7.12	)		2.58

Total oil revenues ($/Bbl)	$	58.96		$	47.30		$	11.66			25	%


Natural gas wellhead ($/Mcf)	$	6.69		$	6.59		$	0.10
Natural gas commodity derivative contracts ($/Mcf)		(0.43	)		(0.35	)		(0.08	)

Total natural gas revenues ($/Mcf)	$	6.26		$	6.24		$	0.02			0	%


Combined wellhead ($/BOE)	$	56.62		$	49.24		$	7.38
Combined commodity derivative contracts ($/BOE)		(3.96	)		(5.37	)		1.41

Total combined oil and natural gas revenues ($/BOE)	$	52.66		$	43.87		$	8.79			20	%


Total production volumes:
Oil (MBbls)		9,545			7,335			2,210			30	%
Natural gas (MMcf)		23,963			23,456			507			2	%
Combined (MBOE)		13,539			11,244			2,295			20	%

Average daily production volumes:
Oil (Bbl/D)		26,152			20,096			6,056			30	%
Natural gas (Mcf/D)		65,651			64,262			1,389			2	%
Combined (BOE/D)		37,094			30,807			6,287			20	%

Average NYMEX prices:
Oil (per Bbl)	$	72.45		$	66.26		$	6.19			9	%
Natural gas (per Mcf)	$	6.86		$	7.17		$	(0.31	)		-4	%

Oil revenues increased $215.8 million from $347.0 million in 2006 to $562.8 million in 2007, primarily due to an increase in oil production volumes and an increase in our average realized oil price. Our production volumes increased 2,210 MBbls from 2007 to 2008, which contributed approximately $120.3 million in additional oil revenues. The increase in production volumes was the result of our Big Horn Basin acquisition in March 2007, our Williston Basin acquisition in April 2007, and our development program.

Our average realized oil price increased $11.66 per Bbl primarily as a result of an increase in our average realized wellhead price, which increased oil revenues by $86.7 million, or $9.08 per Bbl. Our average realized oil wellhead price increased primarily as a result of the increase in the average NYMEX price from $66.26 per Bbl in 2006 to $72.45 per Bbl in 2007. In addition, as a result of our discontinuance of hedge accounting in July 2006, oil revenues for 2007 included amortization of net losses of certain commodity derivative contracts that were previously designated as hedges of approximately $43.3 million, or $4.54 per Bbl, while 2006 included approximately $52.2 million, or $7.12 per Bbl, of net losses.

Our oil wellhead revenue was reduced by $31.9 million and $22.8 million in 2007 and 2006, respectively, for net profits interests related to our CCA properties.

ENCORE ACQUISITION COMPANY

Natural gas revenues increased $3.8 million from $146.3 million in 2006 to $150.1 million in 2007, primarily due to an increase in production volumes of 507 MMcf, which contributed approximately $3.3 million in additional natural gas revenues. The increase in natural gas production volumes was the result of our West Texas joint development agreement with ExxonMobil and our development program in the Mid-Continent area, partially offset by natural gas production sold in conjunction with our Mid-Continent asset disposition in 2007.

Our average realized natural gas price increased $0.02 per Mcf primarily as a result of an increase in our wellhead price, which increased natural gas revenues by $2.6 million, or $0.10 per Mcf. Our average natural gas wellhead price increased as a result of the tightening of our natural gas differential despite decreases in the overall market price for natural gas, as reflected in the decrease in the average NYMEX price from $7.17 per Mcf in 2006 to $6.86 per Mcf in 2007. In addition, as a result of our discontinuance of hedge accounting in July 2006, natural gas revenues for 2007 included amortization of net losses of certain commodity derivative contracts that were previously designated as hedges of approximately $10.3 million, or $0.43 per Mcf, while 2006 included approximately $8.1 million, or $0.35 per Mcf, of net losses.


	Year Ended December 31,
	2007			2006
Oil wellhead ($/Bbl)	$	63.50		$	54.42
Average NYMEX ($/Bbl)	$	72.45		$	66.26
Differential to NYMEX	$	(8.95	)	$	(11.84	)
Oil wellhead to NYMEX percentage		88	%		82	%

Natural gas wellhead ($/Mcf)	$	6.69		$	6.59
Average NYMEX ($/Mcf)	$	6.86		$	7.17
Differential to NYMEX	$	(0.17	)	$	(0.58	)
Natural gas wellhead to NYMEX percentage		98	%		92	%

Our oil wellhead price as a percentage of the average NYMEX price tightened to 88 percent in 2007 as compared to 82 percent in 2006. Our natural gas wellhead price as a percentage of the average NYMEX price improved to 98 percent in 2007 as compared to 92 percent in 2006. The differential improved because of efforts to reduce natural gas transportation and gathering costs.

Marketing revenues and expenses. In 2006, we purchased third-party oil Bbls from counterparties other than to whom the Bbls were sold for aggregation and sale with our own production in various markets. These purchases assisted us in marketing our production by decreasing our dependence on individual markets. These activities allowed us to aggregate larger volumes, facilitated our efforts to maximize the prices we received for production, provided for a greater allocation of future pipeline capacity in the event of curtailments, and enabled us to reach other markets.

In 2007, we discontinued purchasing oil from third party companies as market conditions changed and historical pipeline space was realized. Implementing this change allowed us to focus on the marketing of our own production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.

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

ENCORE ACQUISITION COMPANY


	Year ended December 31,					*Increase / (Decrease)*
	2007		2006			$			%
	($ in thousands, except per BOE amounts)
Marketing revenues	$	42,021	$	147,563		$	(105,542	)		-72	%
Marketing expenses		40,549		148,571			(108,022	)		-73	%

Marketing gain (loss)	$	1,472	$	(1,008	)	$	2,480			-246	%


Marketing revenues per BOE	$	3.10	$	13.12		$	(10.02	)		-76	%
Marketing expenses per BOE		2.99		13.21			(10.22	)		-77	%

Marketing gain (loss), per BOE	$	0.11	$	(0.09	)	$	0.20			-222	%

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


	Year Ended December 31,					*Increase / (Decrease)*
	2007		2006			$			%
Expenses (in thousands):
Production:
Lease operations	$	143,426	$	98,194		$	45,232
Production, ad valorem, and severance taxes		74,585		49,780			24,805

Total production expenses		218,011		147,974			70,037			47	%
Other:
Depletion, depreciation, and amortization		183,980		113,463			70,517
Exploration		27,726		30,519			(2,793	)
General and administrative		39,124		23,194			15,930
Derivative fair value loss (gain)		112,483		(24,388	)		136,871
Provision for doubtful accounts		5,816		1,970			3,846
Other operating		17,066		8,053			9,013

Total operating		604,206		300,785			303,421			101	%
Interest		88,704		45,131			43,573
Income tax provision		14,476		55,406			(40,930	)

Total expenses	$	707,386	$	401,322		$	306,064			76	%


Expenses (per BOE):
Production:
Lease operations	$	10.59	$	8.73		$	1.86
Production, ad valorem, and severance taxes		5.51		4.43			1.08

Total production expenses		16.10		13.16			2.94			22	%
Other:
Depletion, depreciation, and amortization		13.59		10.09			3.50
Exploration		2.05		2.71			(0.66	)
General and administrative		2.89		2.06			0.83
Derivative fair value loss (gain)		8.31		(2.17	)		10.48
Provision for doubtful accounts		0.43		0.18			0.25
Other operating		1.26		0.71			0.55

Total operating		44.63		26.74			17.89			67	%
Interest		6.55		4.01			2.54
Income tax provision		1.07		4.93			(3.86	)

Total expenses	$	52.25	$	35.68		$	16.57			46	%

Production expenses. Total production expenses increased $70.0 million from $148.0 million in 2006 to $218.0 million in 2007 due to higher total production volumes and a $2.94 increase in production expenses per BOE. Our production margin increased by $142.8 million (35 percent) to $548.5 million in 2007 as compared to $405.7 million in 2006. Total production expenses per BOE increased by 22 percent while total oil and natural gas wellhead revenues per BOE increased by 15 percent. On a per BOE basis, our production margin increased 12 percent to $40.52 per BOE for 2007 as compared to $36.08 per BOE for 2006.

ENCORE ACQUISITION COMPANY

Production expense attributable to LOE increased $45.2 million from $98.2 million in 2006 to $143.4 million in 2007, primarily as a result of a $1.86 increase in the average per BOE rate, which contributed approximately $25.2 million of additional LOE, and higher production volumes, which contributed approximately $20.0 million of additional LOE. The increase in our average LOE per BOE rate was attributable to:

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

	•		increased operational activity to maximize production;

	•		HPAI expenses at the CCA; and

	•		higher salary levels for engineers and other technical professionals.

Production expense attributable to production taxes increased $24.8 million from $49.8 million in 2006 to $74.6 million in 2007. The increase was primarily due to higher wellhead revenues. As a percentage of oil and natural gas revenues (excluding the effects of commodity derivative contracts), production taxes increased to 9.7 percent in 2007 as compared to 9.0 percent in 2006 as a result of higher rates in the states where the properties associated with our Big Horn Basin and Williston Basin asset acquisitions are located.

DD&A expense. DD&A expense increased $70.5 million from $113.5 million in 2006 to $184.0 million in 2007 due to a $3.50 increase in the per BOE rate and higher production volumes. The per BOE rate increased due to the higher cost basis of the properties associated with our Big Horn Basin and Williston Basin asset acquisitions, development of proved undeveloped reserves, and higher costs incurred resulting from increases in rig rates, oilfield services costs, and acquisition costs. These factors resulted in additional DD&A expense of approximately $47.3 million, while the increase in production volumes resulted in additional DD&A expense of approximately $23.2 million.

Exploration expense. Exploration expense decreased $2.8 million from $30.5 million in 2006 to $27.7 million in 2007. During 2007, we expensed 5 exploratory dry holes totaling $14.7 million. During 2006, we expensed 14 exploratory dry holes totaling $17.3 million. The following table details our exploration expenses for the periods indicated:


	Year Ended December 31,				*Increase /*
	2007		2006		*(Decrease)*
	(in thousands)
Dry holes	$	14,673	$	17,257	$	(2,584	)
Geological and seismic		1,455		1,720		(265	)
Delay rentals		784		670		114
Impairment of unproved acreage		10,814		10,872		(58	)

Total	$	27,726	$	30,519	$	(2,793	)

G&A expense. G&A expense increased $15.9 million from $23.2 million in 2006 to $39.1 million in 2007, primarily due to:

	•		a $6.4 million increase in non-cash equity-based compensation expense;

	•		increased staffing to manage our larger asset base;

	•		higher activity levels; and

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

Derivative fair value loss (gain). During 2007, we recorded a $112.5 million derivative fair value loss as compared to a $24.4 million derivative fair value gain in 2006, the components of which were as follows:


	Year Ended December 31,					*Increase /*
	2007		2006			*(Decrease)*
	(in thousands)
Ineffectiveness on designated cash flow hedges	$	—	$	1,748		$	(1,748	)
Mark-to-market loss (gain) on commodity derivative contracts		36,272		(31,205	)		67,477
Premium amortization		41,051		13,926			27,125
Settlements on commodity derivative contracts		35,160		(8,857	)		44,017

Total derivative fair value loss (gain)	$	112,483	$	(24,388	)	$	136,871

ENCORE ACQUISITION COMPANY

Provision for doubtful accounts. Provision for doubtful accounts increased $3.8 million from $2.0 million in 2006 to $5.8 million in 2007, primarily due to an increase in the payout allowance related to the ExxonMobil joint development agreement.

Other operating expense. Other operating expense increased $9.0 million from $8.1 million in 2006 to $17.1 million in 2007, primarily due to a $7.4 million loss on the sale of certain Mid-Continent properties and increases in third-party transportation costs attributable to moving our CCA production into markets outside the immediate area of production.

Interest expense. Interest expense increased $43.6 million from $45.1 million in 2006 to $88.7 million in 2007, primarily due to additional debt used to finance the Big Horn Basin and Williston Basin asset acquisitions. The weighted average interest rate for all long-term debt for 2007 was 6.9 percent as compared to 6.1 percent for 2006.

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


	Year Ended December 31,				*Increase /*
	2007		2006		*(Decrease)*
	(in thousands)
6.25% Notes	$	9,705	$	9,684	$	21
6.0% Notes		18,517		18,418		99
7.25% Notes		10,988		10,984		4
Revolving credit facilities		46,085		3,609		42,476
Other		3,409		2,436		973

Total	$	88,704	$	45,131	$	43,573

Income taxes. During 2007, we recorded an income tax provision of $14.5 million as compared to $55.4 million in 2006. Our effective tax rate increased to 59.9 percent in 2007 as compared to 37.5 percent in 2006 primarily due to a permanent rate adjustment for ENP’s management incentive units, a state rate adjustment due to larger apportionment of future taxable income to states with higher tax rates, and permanent timing adjustments that will not reverse in future periods.

Noncontrolling interest. As of December 31, 2007, public unitholders in ENP had a limited partner interest of approximately 40 percent. We consolidate ENP in our consolidated financial statements and show the ownership by the public as a noncontrolling interest. Net loss attributable to noncontrolling interest was $7.5 million for 2007.

Capital Commitments, Capital Resources, and Liquidity

Capital commitments. Our primary needs for cash are:

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

	•		Acquisitions of oil and natural gas properties;

	•		Funding of necessary working capital; and

	•		Contractual obligations.

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


	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Development and exploitation	$	362,111	$	270,016	$	253,484
Exploration		256,437		97,453		95,205

Total	$	618,548	$	367,469	$	348,689

Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for 2008 yielded 186 gross (73.4 net) successful wells and 5 gross (3.1 net) dry holes. Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for 2008 yielded 96 gross (31.4 net) successful wells and 8 gross (3.8

ENCORE ACQUISITION COMPANY

net) dry holes. Please read “Items 1 and 2. Business and Properties – Development Results” included in our 2008 Annual Report for a description of the areas in which we drilled wells during 2008.

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


	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Acquisitions of proved property	$	28,729	$	787,988	$	4,486
Acquisitions of leasehold acreage		128,635		52,306		24,462

Total	$	157,364	$	840,294	$	28,948

In March 2007, Encore Operating and OLLC acquired oil and natural gas properties in the Big Horn Basin, including properties in the Elk Basin and the Gooseberry fields for approximately $393.6 million. In April 2007, we acquired oil and natural gas properties in the Williston Basin for approximately $392.1 million.

During 2008, our capital expenditures for leasehold acreage costs totaled $128.6 million, $45.2 million of which related to the exercise of preferential rights in the Haynesville area and the remainder of which related to the acquisition of unproved acreage in various areas. During 2007, our capital expenditures for leasehold acreage costs totaled $52.3 million, $16.1 million of which related to the Williston Basin asset acquisition and the remainder of which related to the acquisition of unproved acreage in various areas. During 2006, our capital expenditures for leasehold acreage costs totaled $24.5 million, all of which related to the acquisition of unproved acreage in various areas.

Funding of necessary working capital. As of December 31, 2008 and 2007, our working capital (defined as total current assets less total current liabilities) was $188.7 million and negative $16.2 million, respectively. The increase in 2008 as compared to 2007 was primarily attributable to a decrease in commodity prices at December 31, 2008 as compared to December 31, 2007, which positively impacted the fair value of our outstanding commodity derivative contracts.

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

The Board approved a capital budget of $310 million for 2009, excluding proved property acquisitions. The level of these and other future expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and borrowings under our revolving credit facility.

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

ENCORE ACQUISITION COMPANY

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


Contractual Obligations			Payments Due by Period
and Commitments	Maturity Date		Total		2009		2010 - 2011		2012 - 2013		Thereafter
			(in thousands)
6.25% Notes (a)		4/15/2014	$	201,563	$	9,375	$	18,750	$	18,750	$	154,688
6.0% Notes (a)		7/15/2015		426,000		18,000		36,000		36,000		336,000
7.25% Notes (a)		12/1/2017		247,875		10,875		21,750		21,750		193,500
Revolving credit facilities (a)		3/7/2012		789,626		19,885		39,770		729,971		—
Commodity derivative contracts (b)				—		—		—		—		—
Interest rate swaps				4,342		1,269		3,071		2		—
Capital lease obligations				1,747		466		932		349		—
Development commitments (c)				134,860		134,860		—		—		—
Operating leases and commitments (d)				17,493		3,952		7,577		5,964		—
Asset retirement obligations (e)				178,889		1,511		3,022		3,022		171,334

Total			$	2,002,395	$	200,193	$	130,872	$	815,808	$	855,522


(a)		Includes principal and projected interest payments. Please read Note 8 of our Recast Financial Statements for additional information regarding our long-term debt.

(b)		At December 31, 2008, our commodity derivative contracts were in a net asset position. With the exception of $67.6 million of deferred premiums on commodity derivative contracts, the ultimate settlement amounts of our commodity derivative contracts are unknown because they are subject to continuing market risk. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” included in our 2008 Annual Report and Notes 13 and 14 of our Recast Financial Statements for additional information regarding our commodity derivative contracts.

(c)		Development commitments include: authorized purchases for work in process of $116.7 million and future minimum payments for drilling rig operations of $18.1 million. Also at December 31, 2008, we had $178.2 million of authorized purchases not placed to vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and are expected to be made unless circumstances change.

(d)		Operating leases and commitments include office space and equipment obligations that have non-cancelable lease terms in excess of one year of $16.8 million and future minimum payments for other operating commitments of $0.7 million. Please read Note 4 of our Recast Financial Statements for additional information regarding our operating leases.

(e)		Asset retirement obligations represent the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 5 of our Recast Financial Statements for additional information regarding our asset retirement obligations.

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

The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and have been subject to apportionment since December 2005, we were allocated sufficient pipeline capacity to move our crude oil production effective January 1, 2007. Enbridge completed an expansion, which moved the total Rockies area pipeline takeaway closer to a balancing point with increasing production volumes and thereby provided greater stability to oil differentials in the area. In spite of the increase in capacity, the Enbridge Pipeline continues to run at full capacity and is scheduled to complete an additional expansion by the beginning of 2010. However, further restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot accurately predict future crude oil and natural gas differentials. Increases in the percentage differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows. The following table illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices by quarter for 2008, as well as our expected differentials for the first quarter of 2009:

ENCORE ACQUISITION COMPANY


	Actual												Forecast
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			First Quarter
	of 2008			of 2008			of 2008			of 2008			of 2009
Oil wellhead to NYMEX percentage		91	%		94	%		91	%		80	%		78	%
Natural gas wellhead to NYMEX percentage		103	%		102	%		93	%		86	%		103	%

Capital resources

Cash flows from operating activities. Cash provided by operating activities increased $343.5 million from $319.7 million in 2007 to $663.2 million in 2008, primarily due to an increase in our production margin, partially offset by increased settlements on our commodity derivative contracts as a result of higher commodity prices in the first half of 2008.

Cash provided by operating activities increased $22.4 million from $297.3 million in 2006 to $319.7 million in 2007, primarily due to an increase in our production margin, partially offset by increased settlements on our commodity derivative contracts as a result of increases in oil prices and an increase in accounts receivable as a result of increased oil and natural gas production.

Cash flows from investing activities. Cash used in investing activities decreased $201.3 million from $929.6 million in 2007 to $728.3 million in 2008, primarily due to a $706.0 million decrease in amounts paid for acquisitions of oil and natural gas properties and a $283.7 million decrease in proceeds received for the disposition of assets, partially offset by a $225.1 million increase in development of oil and natural gas properties. In 2007, we paid approximately $393.6 million in conjunction with the Big Horn Basin asset acquisition and approximately $392.1 million in conjunction with the Williston Basin asset acquisition. In 2007, we also completed the sale of certain oil and natural gas properties in the Mid-Continent for net proceeds of approximately $294.8 million. During 2008, we advanced $24.8 million (net of collections) to ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement as compared to advancements of $29.5 million (net of collections) in 2007.

Cash used in investing activities increased $532.2 million from $397.4 million in 2006 to $929.6 million in 2007, primarily due to a $818.4 million increase in amounts paid for acquisitions of oil and natural gas properties, primarily our Big Horn Basin and Williston Basin asset acquisitions, partially offset by a $286.4 million increase in proceeds received for the disposition of assets, primarily our Mid-Continent asset disposition. During 2007, we advanced $29.5 million (net of collections) to ExxonMobil for their portion of costs incurred drilling the commitment wells under the joint development agreement as compared to advancements of $22.4 million (net of collections) in 2006.

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

During 2008, we received net cash of $65.4 million from financing activities, including net borrowings on our revolving credit facilities of $199 million, which resulted in an increase in outstanding borrowings under our revolving credit facilities from $526 million at December 31, 2007 to $725 million at December 31, 2008.

In December 2007, we announced that the Board approved a share repurchase program authorizing us to repurchase up to $50 million of our common stock. During 2008, we completed the share repurchase program by repurchasing and retiring 1,397,721 shares of our outstanding common stock at an average price of approximately $35.77 per share.

In October 2008, we announced that the Board authorized a new share repurchase program of up to $40 million of our common stock. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. The share repurchase program will be funded using our available cash. As of December 31, 2008, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the new share repurchase program.

During 2007, we received net cash of $610.8 million from financing activities, including net borrowings on our revolving credit facilities of $444.8 million and net proceeds of $193.5 million from ENP’s issuance of common units. Net borrowings on our revolving credit facilities were primarily due to borrowings used to finance our Big Horn Basin and Williston Basin asset acquisitions, which were partially offset by repayments from the net proceeds received from the Mid-Continent asset disposition and ENP’s issuance of common units.

ENCORE ACQUISITION COMPANY

During 2006, we received net cash of $99.2 million from financing activities. In April 2006, we received net proceeds of $127.1 million from a public offering of 4,000,000 shares of our common stock, which were used to (1) reduce outstanding borrowings under our revolving credit facility, (2) invest in oil and natural gas activities, and (3) pay general corporate expenses.

Liquidity. Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our revolving credit facility. We also have the ability to adjust our capital expenditures. We may use other sources of capital, including the issuance of additional debt or equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures for the foreseeable future. However, should commodity prices continue to decline or the capital markets remain tight, the borrowing capacity under our revolving credit facilities could be adversely affected. We are currently in a process of redetermining the borrowing base under our revolving credit facilities. We expect that the banks will reaffirm our current borrowing base but we recognize that this process could result in a reduction. In the event of a reduction in the borrowing base under our revolving credit facilities, we do not believe it will result in any required prepayments of indebtedness given our relatively low levels of borrowings under those facilities in relation to the existing borrowing base.

Internally generated cash flows. Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During 2008, our average realized oil and natural gas prices increased by 51 percent and 38 percent, respectively, as compared to 2007. Realized oil and natural gas prices fluctuate widely in response to changing market forces. In 2008, approximately 70 percent of our production was oil. As previously discussed, our oil wellhead differentials during 2008 improved as compared to 2007, favorably impacting the prices we received for our oil production. To the extent oil and natural gas prices continue to decline from levels in mid. February 2009 or we experience a significant widening of our differentials, earnings, cash flows from operations, and availability under our revolving credit facility may be adversely impacted. Prolonged periods of low oil and natural gas prices or sustained wider differentials could cause us to not be in compliance with financial covenants under our revolving credit facility and thereby affect our liquidity. However, we have protected a significant portion of our forecasted production for 2009 against declining commodity prices. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” included in our 2008 Annual Report and Notes 13 and 14 of our Recast Financial Statements for additional information regarding our commodity derivative contracts.

Revolving credit facilities. Our principal source of short-term liquidity is our revolving credit facility. The syndicate of lenders underwriting our facility includes 30 banking and other financial institutions, and the syndicate of lenders underwriting ENP’s facility includes 13 banking and other financial institutions, both after taking into consideration recent mergers and acquisitions within the financial services industry. None of the lenders are underwriting more than eight percent of the respective total commitments. We believe the large number of lenders, the relatively small percentage participation of each, and the relatively high level of availability under each facility provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

Certain of the lenders underwriting our facility are also counterparties to our commodity derivative contracts. At December 31, 2008, we had committed greater than 10 percent of either our outstanding oil or natural gas commodity derivative contracts to the following counterparties:


	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed
BNP Paribas		22	%		24	%
Calyon		15	%		31	%
Fortis		11	%		—
UBS		16	%		—
Wachovia		11	%		38	%

Encore Acquisition Company Senior Secured Credit Agreement

In March 2007, we entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective February 7, 2008, we amended the EAC Credit Agreement to, among other things, provide that certain negative covenants in the EAC Credit Agreement restricting hedge transactions do not apply to any oil and natural gas hedge transaction that is a floor or put

ENCORE ACQUISITION COMPANY

transaction not requiring any future payments or delivery by us or any of our restricted subsidiaries. Effective May 22, 2008, we amended the EAC Credit Agreement to, among other things, increase the interest rate margins applicable to loans made under the EAC Credit Agreement, as set forth in the table below, and increase the borrowing base to $1.1 billion. The EAC Credit Agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for our account or the account of any of our restricted subsidiaries.

The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the EAC Credit Agreement was redetermined with no change. As of December 31, 2008, the borrowing base was $1.1 billion. We are currently in a process of redetermining the borrowing base under the EAC Credit Agreement which could result in a reduction to the borrowing base.

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

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


	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.250	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.500	%		0.250	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.750	%		0.500	%
Greater than or equal to .90 to 1		2.000	%		0.750	%

The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5 percent.

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

The EAC Credit Agreement contains covenants that include, among others:

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

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

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

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

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

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

	•		a requirement that we maintain a ratio of consolidated current assets (as defined in the EAC Credit Agreement) to consolidated current liabilities (as defined in the EAC Credit Agreement) of not less than 1.0 to 1.0; and

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

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

ENCORE ACQUISITION COMPANY

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


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

On December 31, 2008, there were $575 million of outstanding borrowings and $525 million of borrowing capacity under the EAC Credit Agreement. On February 18, 2009, there were $543 million of outstanding borrowings and $557 million of borrowing capacity under the EAC Credit Agreement.

Encore Energy Partners Operating LLC Credit Agreement

OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. On August 22, 2007, OLLC amended its credit agreement to revise certain financial covenants. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the OLLC Credit Agreement was redetermined with no change. As of December 31, 2008, the borrowing base was $240 million. We are currently in a process of redetermining the borrowing base under the OLLC Credit Agreement which could result in a reduction to the borrowing base.

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

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


	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.000	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.250	%		0.000	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.500	%		0.250	%
Greater than or equal to .90 to 1		1.750	%		0.500	%

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

The OLLC Credit Agreement contains covenants that include, among others:

•

a prohibition against incurring debt, subject to permitted exceptions;

ENCORE ACQUISITION COMPANY

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

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

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

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

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

	•		a requirement that ENP and OLLC maintain a ratio of consolidated current assets (as defined in the OLLC Credit Agreement) to consolidated current liabilities (as defined in the OLLC Credit Agreement) of not less than 1.0 to 1.0;

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

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

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

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

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


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

On December 31, 2008, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement. On February 18, 2009, there were $201 million of outstanding borrowings and $39 million of borrowing capacity under the OLLC Credit Agreement.

Please read Note 8 of our Recast Financial Statements for additional information regarding our long-term debt.

Indentures governing our senior subordinated notes. We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the 6.25% Notes, the 6.0% Notes, and the 7.25% Notes (collectively, the “Notes”). The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:

	•		incur additional indebtedness;

	•		pay dividends on our capital stock or redeem, repurchase, or retire our capital stock or subordinated indebtedness;

	•		make investments;

	•		incur liens;

	•		create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans, or transfer property to us;

	•		engage in transactions with our affiliates;

	•		sell assets, including capital stock of our subsidiaries;

	•		consolidate, merge, or transfer assets;

	•		a requirement that we maintain a current ratio (as defined in the indentures) of not less than 1.0 to 1.0; and

	•		a requirement that we maintain a ratio of consolidated EBITDA (as defined in the indentures) to consolidated interest expense of not less than 2.5 to 1.0.

If we experience a change of control (as defined in the indentures), subject to certain conditions, we must give holders of the Notes the opportunity to sell to us their Notes at 101 percent of the principal amount, plus accrued and unpaid interest.

ENCORE ACQUISITION COMPANY

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

Capitalization. At December 31, 2008, we had total assets of $3.6 billion and total capitalization of $2.6 billion, of which 50 percent was represented by stockholders’ equity and 50 percent by long-term debt. At December 31, 2007, we had total assets of $2.8 billion and total capitalization of $2.1 billion, of which 46 percent was represented by stockholders’ equity and 54 percent by long-term debt. The percentages of our capitalization represented by stockholders’ equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Changes in Prices

Our oil and natural gas revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms are affected by changes in oil and natural gas prices, which fluctuate significantly. The following table illustrates our average oil and natural gas prices for the periods presented. Our average realized prices for 2008, 2007, and 2006 were decreased by $0.20, $3.96, and $5.37 per BOE, respectively, as a result of commodity derivative contracts, which were previously designated as hedges.


	Year Ended December 31,
	2008		2007		2006
Average realized prices:
Oil ($/Bbl)	$	89.30	$	58.96	$	47.30
Natural gas ($/Mcf)		8.63		6.26		6.24
Combined ($/BOE)		77.87		52.66		43.87
Average wellhead prices:
Oil ($/Bbl)	$	89.58	$	63.50	$	54.42
Natural gas ($/Mcf)		8.63		6.69		6.59
Combined ($/BOE)		78.07		56.62		49.24

Increases in oil and natural gas prices may be accompanied by or result in: (1) increased development costs, as the demand for drilling operations increases; (2) increased severance taxes, as we are subject to higher severance taxes due to the increased value of oil and natural gas extracted from our wells; (3) increased LOE, as the demand for services related to the operation of our wells increases; and (4) increased electricity costs. Decreases in oil and natural gas prices may be accompanied by or result in: (1) decreased development costs, as the demand for drilling operations decreases; (2) decreased severance taxes, as we are subject to lower severance taxes due to the decreased value of oil and natural gas extracted from our wells; (3) decreased LOE, as the demand for services related to the operation of our wells decreases; (4) decreased electricity costs; (5) impairment of oil and natural gas properties; and (6) decreased revenues and cash flows. We believe our risk management program and available borrowing capacity under our revolving credit facility provide means for us to manage commodity price risks.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures. Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or different estimates that could have been selected, could have a material impact on our consolidated results of operations or financial condition. Management has identified the following critical accounting policies and estimates.

Oil and Natural Gas Properties

Successful efforts method. We use the successful efforts method of accounting for oil and natural gas properties under SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in the period in which the determination is made. If an exploratory well finds reserves but they cannot be classified as proved, we continue to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the

ENCORE ACQUISITION COMPANY

reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed in the period in which the determination is made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the costs would be charged to expense.

DD&A expense is directly affected by our reserve estimates. Significant revisions to reserve estimates can be and are made by our reserve engineers each year. Mostly these are the result of changes in price, but as reserve quantities are estimates, they can also change as more or better information is collected, especially in the case of estimates in newer fields. Downward revisions have the effect of increasing our DD&A rate, while upward revisions have the effect of decreasing our DD&A rate. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa. DD&A expense associated with lease and well equipment and intangible drilling costs is based upon proved developed reserves, while DD&A expense for capitalized leasehold costs is based upon total proved reserves. As a result, changes in the classification of our reserves could have a material impact on our DD&A expense.

Miller & Lents estimates our reserves annually at December 31. This results in a new DD&A rate which we use for the preceding fourth quarter after adjusting for fourth quarter production. We internally estimate reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Internal costs directly associated with the development of proved properties are capitalized as a cost of the property and are classified accordingly in our consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to BOE at the rate of six Mcf of natural gas to one Bbl of oil.

The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), we assess the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces our net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. We use prices consistent with the prices used in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment. During 2008, events and circumstances indicated that a portion of our oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, might be impaired. As a result, we completed an impairment assessment and recorded a $59.5 million impairment charge. Our estimates of undiscounted cash flows indicated that the remaining carrying amounts of our oil and natural gas properties are expected to be recovered. Nonetheless, if oil and natural gas prices continue to decline, it is reasonably possible that our estimates of undiscounted cash flows may change in the near term resulting in the need to record an additional write down of our oil and natural gas properties to fair value.

Unproved properties, the majority of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of the unproved properties’ costs which we believe will not be transferred to proved properties over the life of the lease. One of the primary factors in determining what portion will not be transferred to proved properties is the relative proportion of the unproved properties on which

ENCORE ACQUISITION COMPANY

proved reserves have been found in the past. Since the wells drilled on unproved acreage are inherently exploratory in nature, actual results could vary from estimates especially in newer areas in which we do not have a long history of drilling.

Oil and natural gas reserves. Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Miller & Lents prepares a reserve and economic evaluation of all of our properties on a well-by-well basis. Assumptions used by Miller & Lents in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. The accuracy of reserve estimates is a function of the:

	•		quality and quantity of available data;

	•		interpretation of that data;

	•		accuracy of various mandated economic assumptions; and

	•		judgment of the independent reserve engineer.

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. We may not be able to develop proved reserves within the periods estimated. Furthermore, prices and costs may not remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, the property’s fair value, and our DD&A rate.

Asset retirement obligations. In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” we recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of our oil and natural gas properties. The liability is recorded at its discounted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed.

The fair value of the liability associated with the asset retirement obligation is determined using significant assumptions, including estimates of the plugging and abandonment costs, annual expected inflation of these costs, the productive life of the asset, and our credit-adjusted risk-free interest rate used to discount the expected future cash flows. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the obligation are recorded with an offsetting change to the carrying amount of the related oil and natural gas properties, resulting in prospective changes to DD&A and accretion expense. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas properties, the costs to ultimately retire these assets may vary significantly from our estimates.

Goodwill and Other Intangible Assets

We account for goodwill and other intangible assets under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill and other intangible assets with indefinite useful lives are assessed for impairment annually on December 31 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. We have determined that we have two reporting units: EAC Standalone and ENP. If indicators of impairment are determined to exist, an impairment charge would be recognized for the amount by which the carrying value of an indefinite lived intangible asset exceeds its implied fair value.

We utilize both a market capitalization and an income approach to determine the fair value of our reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. Our analysis concluded that there was no impairment of goodwill as of December 31, 2008. Prices for oil and natural gas have deteriorated sharply in recent months and significant uncertainty remains on how prices for these commodities will behave in the future. Any additional decreases in the prices of oil and natural gas or any negative reserve adjustments from the December 31, 2008 assessment could change our estimates of the fair value of our reporting units and could result in an impairment charge.

Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, we evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

ENCORE ACQUISITION COMPANY

We allocate the purchase price paid for the acquisition of a business to the assets and liabilities acquired based on the estimated fair values of those assets and liabilities. Estimates of fair value are based upon, among other things, reserve estimates, anticipated future prices and costs, and expected net cash flows to be generated. These estimates are often highly subjective and may have a material impact on the amounts recorded for acquired assets and liabilities.

Net Profits Interests

A major portion of our acreage position in the CCA is subject to net profits interests ranging from one percent to 50 percent. The holders of these net profits interests are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been subtracted from net revenue. The net profits calculations are contractually defined. In general, net profits are determined after considering costs associated with production, overhead, interest, and development. The amounts of reserves and production attributable to net profits interests are deducted from our reserves and production data, and our revenues are reported net of net profits interests. The reserves and production attributed to the net profits interests are calculated by dividing estimated future net profits interests (in the case of reserves) or prior period actual net profits interests (in the case of production) by commodity prices at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributed to the net profits interests and will have an inverse effect on our oil and natural gas revenues, production, reserves, and net income.

Oil and Natural Gas Revenue Recognition

Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties and net profits interests. Royalties, net profits interests, and severance taxes are incurred based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded as expense. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than our proportionate share of natural gas production. If our overproduced imbalance position (i.e., we have cumulatively been over-allocated production) is greater than our share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint interest owners in our properties, or oil in pipelines that has not been delivered to the purchaser.

Income Taxes

Our effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax paying companies. Our effective tax rate is affected by changes in the allocation of property, payroll, and revenues between states in which we own property as rates vary from state to state. Our deferred taxes are calculated using rates we expect to be in effect when they reverse. As the mix of property, payroll, and revenues varies by state, our estimated tax rate changes. Due to the size of our gross deferred tax balances, a small change in our estimated future tax rate can have a material effect on earnings.

Derivatives

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

We apply the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) and its amendments, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative does not 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 recorded in accumulated other comprehensive income until such time as the hedged item is recognized in earnings.

To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting

ENCORE ACQUISITION COMPANY

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 income each period.

We have elected to designate our 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 income in stockholders’ equity 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 immediately in earnings. While management does not anticipate changing the designation of our interest rate swaps as hedges, factors beyond our control can preclude the use of hedge accounting.

We have elected to not designate our current portfolio of commodity derivative contracts as hedges and therefore, changes in fair value of these instruments are recognized in earnings each period.

Please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” included in our 2008 Annual Report for discussion regarding our sensitivity analysis for financial instruments.

New Accounting Pronouncements

SFAS No. 157, “Fair Value Measurements” (“SFAS 157”)

In September 2006, the FASB issued SFAS 157, which: (1) standardizes the definition of fair value; (2) establishes a framework for measuring fair value in GAAP; and (3) expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not require any new fair value measurements. SFAS 157 was prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, our asset retirement obligations and indefinite lived assets. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities, did not have a material impact on our results of operations or financial condition. We do not expect the adoption of SFAS 157 on January 1, 2009, as it relates to all instruments within the scope of FSP FAS 157-2, to have a material impact on our results of operations or financial condition.

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

In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 also allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 was effective for fiscal years beginning after November 15, 2007. We did not elect the fair value option for eligible instruments and therefore, the adoption of SFAS 159 on January 1, 2008 did not impact our results of operations or financial condition. We will assess the impact of electing the fair value option for any eligible instruments acquired in the future. Electing the fair value option for such instruments could have a material impact on our future results of operations or financial condition.

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

In April 2007, the FASB issued FSP FIN 39-1, which amends FIN No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 was effective for fiscal years beginning after November 15, 2007. The adoption of FSP FIN 39-1 on January 1, 2008 did not impact our results of operations or financial condition.

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

ENCORE ACQUISITION COMPANY

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. SFAS 141R is prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. We currently do not have any pending acquisitions that would fall within the scope of SFAS 141R. Future acquisitions could have an impact on our results of operations and financial condition.

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 is effective for fiscal years beginning on or after December 15, 2008. 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 at amounts that include the amounts attributable to both the parent and the noncontrolling interest and the disclosure of consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of operations and gains and losses 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 our results of operations and financial condition. The retrospective application of SFAS 160 resulted in the reclassification of approximately $169.1 million and $122.5 million from “Minority interest in consolidated partnership” to “Noncontrolling interest” at December 31, 2008 and 2007, respectively, on our Consolidated Balance Sheets included in our Recast Financial Statements.

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 133, to require enhanced disclosures about: (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 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding our derivative instruments; however, it will not impact our results of operations or financial condition.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”)

In May 2008, the FASB issued SFAS 162, which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS 162 was effective November 15, 2008. The adoption of SFAS 162 did not impact our results of operations or financial condition.

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

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.” FSP EITF 03-6-1 is retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. The adoption of FSP EITF 03-6-1 on January 1, 2009 did not have a material impact on our results of operations or financial condition. All periods presented in our Recast Financial Statements have been restated to reflect the adoption of FSP EITF 03-6-1. The retrospective application of FSP EITF 03-6-1 reduced our basic earnings per common share by $0.14 and $0.03 for 2008 and 2006 and reduced our diluted earnings per share by $0.06, $0.01, and $0.01 for 2008, 2007, and 2006, respectively. The adoption of FSP EITF 03-6-1 did not have an impact on our basic earnings per share for 2007.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Encore Acquisition Company:

We have audited the accompanying consolidated balance sheets of Encore Acquisition Company (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encore Acquisition Company at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 9 to the consolidated financial statements, effective January 1, 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.”

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2009 expressed an unqualified opinion thereon.



	/s/ Ernst & Young LLP

Fort Worth, Texas
February 24, 2009, except for the matters related to the retrospective adoptions of SFAS No. 160 and FSP EITF 03-6-1 and the reorganization of operating segments described in Notes 2, 11 and 18 as to which the date is January 25, 2010

ENCORE ACQUISITION COMPANY

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


	December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	2,039		$	1,704
Accounts receivable, net of allowance for doubtful accounts of $381 and $0, respectively		129,065			134,880
Inventory		24,798			16,257
Derivatives		349,344			9,722
Deferred taxes		—			20,420
Income taxes receivable		29,445			2,661
Other		6,239			2,866

Total current assets		540,930			188,510


Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		3,538,459			2,845,776
Unproved properties		124,339			63,352
Accumulated depletion, depreciation, and amortization		(771,564	)		(489,004	)

		2,891,234			2,420,124

Other property and equipment		25,192			21,750
Accumulated depreciation		(12,753	)		(10,733	)

		12,439			11,017


Goodwill		60,606			60,606
Derivatives		38,497			34,579
Long-term receivables, net of allowance for doubtful accounts of $7,643 and $6,045, respectively		60,915			40,945
Other		28,574			28,780

Total assets	$	3,633,195		$	2,784,561


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	10,017		$	21,548
Accrued liabilities:
Lease operating		19,108			15,057
Development capital		79,435			48,359
Interest		11,808			12,795
Production, ad valorem, and severance taxes		25,133			24,694
Marketing		3,594			8,721
Derivatives		63,476			39,337
Oil and natural gas revenues payable		10,821			13,076
Deferred taxes		105,768			—
Other		23,092			21,143

Total current liabilities		352,252			204,730

Derivatives		8,922			47,091
Future abandonment cost, net of current portion		48,058			27,371
Deferred taxes		416,915			312,914
Long-term debt		1,319,811			1,120,236
Other		3,989			1,530

Total liabilities		2,149,947			1,713,872


Commitments and contingencies (see Note 4)

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, 51,551,937 and 53,303,464 issued and outstanding, respectively		516			534
Additional paid-in capital		525,763			538,620
Treasury stock, at cost, of 4,753 and 17,690 shares, respectively		(101	)		(590	)
Retained earnings		789,698			411,377
Accumulated other comprehensive loss		(1,748	)		(1,786	)

Total EAC stockholders’ equity		1,314,128			948,155
Noncontrolling interest		169,120			122,534

Total equity		1,483,248			1,070,689

Total liabilities and equity	$	3,633,195		$	2,784,561

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)


	Year Ended December 31,
	2008			2007			2006
Revenues:
Oil	$	897,443		$	562,817		$	346,974
Natural gas		227,479			150,107			146,325
Marketing		10,496			42,021			147,563

Total revenues		1,135,418			754,945			640,862


Expenses:
Production:
Lease operating		175,115			143,426			98,194
Production, ad valorem, and severance taxes		110,644			74,585			49,780
Depletion, depreciation, and amortization		228,252			183,980			113,463
Impairment of long-lived assets		59,526			—			—
Exploration		39,207			27,726			30,519
General and administrative		48,421			39,124			23,194
Marketing		9,570			40,549			148,571
Derivative fair value loss (gain)		(346,236	)		112,483			(24,388	)
Provision for doubtful accounts		1,984			5,816			1,970
Other operating		12,975			17,066			8,053

Total expenses		339,458			644,755			449,356


Operating income		795,960			110,190			191,506


Other income (expenses):
Interest		(73,173	)		(88,704	)		(45,131	)
Other		3,898			2,667			1,429

Total other expenses		(69,275	)		(86,037	)		(43,702	)


Income before income taxes		726,685			24,153			147,804
Income tax provision		(241,621	)		(14,476	)		(55,406	)

Consolidated net income		485,064			9,677			92,398
Less: net loss (income) attributable to noncontrolling interest		(54,252	)		7,478			—

Net income attributable to EAC stockholders	$	430,812		$	17,155		$	92,398


Net income per common share:
Basic	$	8.10		$	0.32		$	1.75
Diluted	$	8.01		$	0.31		$	1.74

Weighted average common shares outstanding:
Basic		52,270			53,170			51,865
Diluted		52,866			53,629			52,356

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

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME
(in thousands)


	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, 2005		48,785		$	488		$	316,619			(11	)	$	(375	)	$	302,875		$	(72,826	)	$	—		$	546,781
Exercise of stock options and vesting of restricted stock		280			3			3,641			—			—			—			—			—			3,644
Purchase of treasury stock		—			—			—			(25	)		(633	)		—			—			—			(633	)
Cancellation of treasury stock		(18	)		—			(195	)		18			551			(356	)		—			—			—
Issuance of common stock		4,000			40			127,061			—			—			—			—			—			127,101
Non-cash stock-based compensation		—			—			10,075			—			—			—			—			—			10,075
Components of comprehensive income:
Net income		—			—			—			—			—			92,398			—			—			92,398
Change in deferred hedge gain/loss, net of tax of $22,365		—			—			—			—			—			—			37,499			—			37,499

Total comprehensive income																										129,897

Balance at December 31, 2006		53,047			531			457,201			(18	)		(457	)		394,917			(35,327	)		—			816,865
Exercise of stock options and vesting of restricted stock		313			3			1,587			—			—			—			—			—			1,590
Purchase of treasury stock		—			—			—			(39	)		(1,136	)		—			—			—			(1,136	)
Cancellation of treasury stock		(39	)		—			(338	)		39			1,003			(665	)		—			—			—
Non-cash equity-based compensation		—			—			14,632			—			—			—			—			2,627			17,259
ENP issuance of common units, net of offering costs		—			—			(12,088	)		—			—			—			—			205,549			193,461
ENP cash distributions to noncontrolling interests		—			—			—			—			—			(30	)		—			(538	)		(568	)
Adjustment to reflect gain on ENP issuance of common units		—			—			77,626			—			—			—			—			(77,626	)		—
Components of comprehensive income:
Net income		—			—			—			—			—			17,155			—			(7,478	)		9,677
Amortization of deferred hedge losses, net of tax of $20,047		—			—			—			—			—			—			33,541			—			33,541

Total comprehensive income																										43,218

Balance at December 31, 2007		53,321			534			538,620			(18	)		(590	)		411,377			(1,786	)		122,534			1,070,689
Exercise of stock options and vesting of restricted stock		300			2			2,620			—			—			—			—			—			2,622
Repurchase and retirement of common stock		(2,018	)		(20	)		(19,279	)		—			—			(47,871	)		—			—			(67,170	)
Purchase of treasury stock		—			—			—			(33	)		(1,055	)		—			—			—			(1,055	)
Cancellation of treasury stock		(46	)		—			(465	)		46			1,544			(1,079	)		—			—			—
Non-cash equity-based compensation		—			—			14,505			—			—			—			—			1,697			16,202
ENP issuance of common units		—			—			—			—			—			—			—			5,748			5,748
ENP cash distributions to noncontrolling interests		—			—			—			—			—			(3,541	)		—			(24,004	)		(27,545	)
Adjustment to reflect gain on ENP issuance of common units		—			—			3,458			—			—			—			—			(3,458	)		—
Economic uniformity adjustment related to conversion of management incentive units		—			—			(13,920	)		—			—			—			—			13,920			—
Other		—			—			224			—			—			—			—			—			224
Components of comprehensive income:
Net income		—			—			—			—			—			430,812			—			54,252			485,064
Change in deferred hedge loss on interest rate swaps, net of tax of $957		—			—			—			—			—			—			(1,748	)		(1,569	)		(3,317	)
Amortization of deferred loss on commodity derivative contracts, net of tax of $1,071		—			—			—			—			—			—			1,786			—			1,786

Total comprehensive income																										483,533

Balance at December 31, 2008		51,557		$	516		$	525,763			(5	)	$	(101	)	$	789,698		$	(1,748	)	$	169,120		$	1,483,248

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

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


	Year Ended December 31,
	2008			2007			2006
Cash flows from operating activities:
Consolidated net income	$	485,064		$	9,677		$	92,398
Adjustments to reconcile consolidated net income to net cash provided by operating activities:
Depletion, depreciation, and amortization		228,252			183,980			113,463
Impairment of long-lived assets		59,526			—			—
Non-cash exploration expense		34,874			25,487			28,128
Deferred taxes		232,614			12,588			51,220
Non-cash equity-based compensation expense		14,115			15,997			8,980
Non-cash derivative loss (gain)		(299,914	)		130,910			(10,434	)
Loss (gain) on disposition of assets		(3,623	)		7,409			(297	)
Provision for doubtful accounts		1,984			5,816			1,970
Other		6,479			10,182			7,577
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(8,488	)		(48,647	)		(2,275	)
Current derivatives		(13,681	)		(17,430	)		—
Other current assets		(35,495	)		3,108			(4,945	)
Long-term derivatives		(8,601	)		(35,750	)		—
Other assets		(2,174	)		(1,214	)		(365	)
Accounts payable		(11,468	)		4,461			1,833
Other current liabilities		(14,351	)		14,788			10,080
Other noncurrent liabilities		(1,876	)		(1,655	)		—

Net cash provided by operating activities		663,237			319,707			297,333


Cash flows from investing activities:
Proceeds from disposition of assets		4,235			287,928			1,522
Purchases of other property and equipment		(4,208	)		(3,519	)		(4,290	)
Acquisition of oil and natural gas properties		(142,559	)		(848,545	)		(30,119	)
Development of oil and natural gas properties		(560,997	)		(335,897	)		(340,582	)
Net advances to working interest partners		(24,817	)		(29,523	)		(22,425	)
Other		—			—			(1,536	)

Net cash used in investing activities		(728,346	)		(929,556	)		(397,430	)


Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs		—			—			127,101
Proceeds from issuance of ENP common units, net of issuance costs		—			193,461			—
Repurchase and retirement of common stock		(67,170	)		—			—
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		1,567			454			3,011
Proceeds from long-term debt, net of issuance costs		1,370,339			1,479,259			281,853
Payments on long-term debt		(1,172,500	)		(1,034,428	)		(294,000	)
Payment of commodity derivative contract premiums		(39,184	)		(26,195	)		(7,848	)
ENP cash distributions to noncontrolling interests		(27,545	)		(568	)		—
Change in cash overdrafts		(63	)		(1,193	)		(10,911	)

Net cash provided by financing activities		65,444			610,790			99,206


Increase (decrease) in cash and cash equivalents		335			941			(891	)
Cash and cash equivalents, beginning of period		1,704			763			1,654

Cash and cash equivalents, end of period	$	2,039		$	1,704		$	763

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

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Description of Business

Encore Acquisition Company (together with its subsidiaries, “EAC”), a Delaware corporation, 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 Oklahoma, the North Louisiana Salt Basin, the East Texas Basin, and the Mississippi Salt Basin.

Note 2. Summary of Significant Accounting Policies

Recast of Consolidated Financial Statements and Notes to Consolidated Financial Statements

On January 1, 2009, EAC adopted new guidance issued by the Financial Accounting Standards Board (the “FASB”) on the accounting for noncontrolling interests and new guidance relating to the treatment of equity-based payment transactions in the calculation of earnings per share. The retrospective application of the new guidance on noncontrolling interests resulted in the reclassification of approximately $169.1 million and $122.5 million from “Minority interest in consolidated partnership” to “Noncontrolling interest” at December 31, 2008 and 2007, respectively, on the accompanying Consolidated Balance Sheets. The retrospective application of the new guidance on earnings per share reduced EAC’s basic earnings per common share by $0.14 and $0.03 for the years ended December 31, 2008 and 2006 and reduced EAC’s diluted earnings per share by $0.06, $0.01, and $0.01 for the years ended December 31, 2008, 2007, and 2006, respectively. The adoption of the revised guidance on earnings per share did not have an impact on EAC’s basic earnings per share for the year ended December 31, 2007.

In August 2009, Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned guarantor subsidiary of EAC, sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) to Encore Energy Partners LP (together with its subsidiaries, “ENP”), a publicly traded Delaware limited partnership, for approximately $186.8 million in cash. In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.2 million in cash. In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash. Because these assets were sold to an affiliate, the dispositions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby ENP recorded the assets and liabilities of the acquired properties at Encore Operating’s carrying value and ENP’s historical financial information was recast to include the acquired properties for all periods presented. Accordingly, EAC’s segment information for ENP in these notes to consolidated financial statements reflect the historical results of ENP combined with those of the Arkoma Basin Assets, the Williston Basin Assets, and the Rockies and Permian Basin Assets for all periods presented.

As a result of the above noted transactions, the consolidated financial statements, notes to consolidated financial statements (including Notes 2, 9, 11, 16, and 18), and unaudited supplementary information have been revised.

Principles of Consolidation

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 February 2007, EAC formed ENP to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. In September 2007, ENP completed its initial public offering (“IPO”). As of December 31, 2008 and 2007, EAC owned approximately 63 percent and 58 percent, respectively, of ENP’s common units, as well as all of the interests of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and ENP’s general partner, which is an indirect wholly owned non-guarantor subsidiary of EAC. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force (“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,

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

and cash flows of ENP are consolidated with those of EAC. EAC elected to account for gains on ENP’s issuance of common units as capital transactions as permitted by Staff Accounting Bulletin (“SAB”) Topic 5H, “Accounting for Sales of Stock by a Subsidiary.” Please read “Note 10. Stockholders’ Equity” for additional discussion.

As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of December 31, 2008 and 2007 of $169.1 million and $122.5 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 2008 of $54.3 million and “Net loss attributable to noncontrolling interest” for 2007 of $7.5 million represents ENP’s results of operations attributable to third-party owners.

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


	Year Ended December 31,
	2008		2007
	(in thousands)
Net income attributable to EAC stockholders	$	430,812	$	17,155

Transfer from (to) noncontrolling interest:
Increase in EAC’s paid-in capital for ENP’s issuance of 10,148,400 common units in public offering		—		77,626
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		—

Net transfer from noncontrolling interest		3,458		77,626

Change from net income attributable to EAC stockholders and transfers from (to) noncontrolling interest	$	434,270	$	94,781

Use of Estimates

Preparing financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses. Actual results could differ materially from those estimates.

Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions used could have a significant impact on reported results in future periods.

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis and considering legal right of offset, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is shown as “Change in cash overdrafts” in the “Financing activities” section of EAC’s Consolidated Statements of Cash Flows.

Supplemental Disclosures of Cash Flow Information

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

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


	Year ended December 31,
	2008		2007		2006
	(In thousands)
Cash paid during the period for:
Interest	$	67,519	$	82,649	$	46,389
Income taxes		33,110		260		464
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts		53,387		20,341		30,319
ENP’s issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties		5,748		—		—

Accounts Receivable

Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest with the exception of the current portion of balances due from ExxonMobil Corporation (“ExxonMobil”) in connection with EAC’s joint development agreement. Please read “Note 4. Commitments and Contingencies” for additional discussion of this agreement. EAC routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. The following table summarizes the changes in allowance for doubtful accounts for the periods indicated:


	Year Ended December 31,
	2008			2007
	(in thousands)
Allowance for doubtful accounts at January 1	$	6,045		$	2,329
Bad debt expense		1,984			5,816
Write off		(5	)		(2,100	)

Allowance for doubtful accounts at December 31	$	8,024		$	6,045

Of the $8.0 million in allowance for doubtful accounts at December 31, 2008, $0.4 million is short-term and $7.6 million is long-term.

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:


	December 31,
	2008		2007
	(in thousands)
Materials and supplies	$	15,933	$	11,030
Oil in pipelines		8,865		5,227

Total inventory	$	24,798	$	16,257

Properties and Equipment

Oil and Natural Gas Properties. EAC uses the successful efforts method of accounting for its oil and natural gas properties under Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in EAC’s Consolidated Statements of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of EAC’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, EAC continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of EAC’s Consolidated Statements of Cash Flows in the period in which the determination is made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the costs would be charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of EAC’s Consolidated Statements of Cash Flows.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Internal costs directly associated with the development of proved properties are capitalized as a cost of the property and are classified accordingly in EAC’s consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.

The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

Miller and Lents, Ltd., EAC’s independent reserve engineer, estimates EAC’s reserves annually on December 31. This results in a new DD&A rate which EAC uses for the preceding fourth quarter after adjusting for fourth quarter production. EAC internally estimates reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), EAC assesses the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces the net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. EAC uses prices consistent with the prices used in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment.

Unproved properties, the majority of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs which EAC believes will not be transferred to proved properties over the remaining life of the lease.

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:

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


	December 31,
	2008		2007
	(in thousands)

Proved leasehold costs	$	1,421,859	$	1,346,516
Wells and related equipment — Completed		1,943,275		1,408,512
Wells and related equipment — In process		173,325		90,748

Total proved properties	$	3,538,459	$	2,845,776

Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is recognized on a straight-line basis over estimated useful lives, which range from three to seven years. Leasehold improvements are capitalized and depreciated over the remaining term of the lease, which is through 2013 for EAC’s corporate headquarters. Gains or losses from the disposal of other property and equipment are recognized in the period realized and included in “Other operating expense” of EAC’s Consolidated Statements of Operations.

Goodwill and Other Intangible Assets

EAC accounts for goodwill and other intangible assets under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill and other intangible assets with indefinite useful lives are tested for impairment annually on December 31 or whenever indicators of impairment exist. If indicators of impairment are determined to exist, an impairment charge would be recognized for the amount by which the carrying value of the asset exceeds its implied fair value. The goodwill test is performed at the reporting unit level. EAC has determined that it has two reporting units: EAC Standalone and ENP. ENP has been allocated $2.6 million of goodwill and the remainder has been allocated to the EAC Standalone segment.

EAC utilizes both a market capitalization and an income approach to determine the fair value of its reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. EAC’s analysis concluded that there was no impairment of goodwill as of December 31, 2008. Prices for oil and natural gas have deteriorated sharply in recent months and significant uncertainty remains on how prices for these commodities will behave in the future. Any additional decreases in the prices of oil and natural gas or any negative reserve adjustments from the December 31, 2008 assessment could change EAC’s estimates of the fair value of its reporting units and could result in an impairment charge.

Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, EAC evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

ENP is a party to a contract allowing it to purchase a certain amount of natural gas at a below market price for use as field fuel. The fair value of this contract, net of related amortization, is included in “Other noncurrent assets” on the accompanying Consolidated Balance Sheets. The gross carrying amount of this contract is $4.2 million and as of December 31, 2008 and 2007, accumulated amortization was $0.6 million and $0.3 million, respectively. During each of 2008 and 2007, ENP recorded $0.3 million of amortization expense related to this contract. The net carrying amount is being amortized on a straight-line basis through July 2019. ENP expects to recognize $0.3 million of amortization expense during each of the next five years related to this contract.

Asset Retirement Obligations

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” EAC recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of EAC’s oil and natural gas properties. The liability is recorded at its discounted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. EAC does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. Please read “Note 5. Asset Retirement Obligations” for additional information.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Equity-Based Compensation

EAC accounts for equity-based compensation according to the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which requires the recognition of compensation expense for equity-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. EAC utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of employee stock options under SFAS 123R. Please read “Note 12. Employee Benefit Plans” for additional discussion of EAC’s employee benefit plans.

SFAS 123R also requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. EAC recognizes compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. Compensation expense associated with awards to employees who are eligible for retirement is fully expensed on the date of grant.

Segment Reporting

EAC operates in only one industry: the oil and natural gas exploration and production industry in the United States. However, EAC is organizationally structured along two reportable segments: EAC Standalone and ENP. EAC’s segments are components of its business for which separate financial information related to operating and development costs are available and regularly evaluated by the chief operating decision maker in deciding how to allocate capital resources to projects and in assessing performance. Please read “Note 18. Segment Information” for additional discussion. Prior to the fourth quarter of 2007, segment reporting was not applicable to EAC.

Major Customers/Concentration of Credit Risk

The following purchasers accounted for 10 percent or greater of the sales of production for the period indicated:


	Percentage of Total Sales of
	Production for the Year Ended
	December 31,
	2008			2007			2006
Consolidated EAC
Eight-Eight Oil		14	%		14	%		(a	)
Tesoro Refining & Marketing Co		12	%		(a	)		(a	)
Shell Trading Company		(a	)		(a	)		15	%
ConocoPhillips		(a	)		(a	)		12	%

ENP
Marathon Oil Corporation		19	%		24	%		(a	)
ConocoPhillips		17	%		10	%		(a	)
Chevron Corporation		(a	)		(a	)		21	%
Sid Richardson Energy		(a	)		(a	)		13	%
Tesoro Refining & Marketing Co		15	%		17	%		(a	)
Trammo Petroleum, Inc.		(a	)		(a	)		14	%
Navajo Refining & Crude Marketing		(a	)		(a	)		16	%

EAC Standalone
Shell Trading Company		(a	)		(a	)		15	%
ConocoPhillips		(a	)		(a	)		10	%
Eight-Eight Oil		23	%		29	%		(a	)
Tesoro Refining & Marketing Co		13	%		(a	)		(a	)


(a)		Less than 10 percent for the period indicated.

Income Taxes

Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between financial

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

statement carrying amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established when necessary to reduce net deferred tax assets to amounts expected to be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.

Oil and Natural Gas Revenue Recognition

Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties and net profits interests. Royalties, net profits interests, and severance taxes are incurred based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable, net” in the accompanying Consolidated Balance Sheets. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded in “Other operating expense” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than EAC’s proportionate share of natural gas production. If EAC’s overproduced imbalance position (i.e., EAC has cumulatively been over-allocated production) is greater than EAC’s share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint owners in EAC’s properties, or oil in pipelines that has not been delivered to the purchaser.

EAC’s net oil inventories in pipelines were 173,119 Bbls and 124,410 Bbls at December 31, 2008 and 2007, respectively. Natural gas imbalances at December 31, 2008 and 2007, were 28,717 million British thermal units (“MMBtu”) and 128,856 MMBtu under-delivered to EAC, respectively.

Marketing Revenues and Expenses

Marketing revenues include the sales of natural gas purchased from third parties as well as pipeline tariffs charged for transportation volumes through EAC’s pipelines. Marketing revenues derived from sales of oil and natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. Marketing expenses include the cost of oil and natural gas volumes purchased from third parties, pipeline tariffs, storage, truck facility fees, and tank bottom costs used to support the sale of oil production. As EAC takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in the Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”

Shipping Costs

Shipping costs in the form of pipeline fees and trucking costs paid to third parties are incurred to transport oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in “Other operating expense” and “Marketing expense,” as applicable, in the accompanying Consolidated Statements of Operations.

Derivatives

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 forward derivative or option 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 No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) and its amendments, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative does not 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 income until such time as the hedged item is recognized in earnings.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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 income 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 income” 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 Consolidated Statements of Operations.

EAC has elected to not 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.

Comprehensive Income

EAC has elected to show comprehensive income as part of its Consolidated Statements of Stockholders’ Equity and Comprehensive Income rather than in its Consolidated Statements of Operations.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, “Income taxes receivable” has been presented separately on the accompanying Consolidated Balance Sheets.

New Accounting Pronouncements

SFAS No. 157, “Fair Value Measurements” (“SFAS 157”)

In September 2006, the FASB issued SFAS 157, which: (1) standardizes the definition of fair value; (2) establishes a framework for measuring fair value in GAAP; and (3) expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not require any new fair value measurements. SFAS 157 was prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). EAC elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. EAC will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities, did not have a material impact on EAC’s results of operations or financial condition. EAC does not expect the adoption of SFAS 157 on January 1, 2009, as it relates to all instruments within the scope of FSP FAS 157-2, to have a material impact on its results of operations or financial condition. Please read “Note 14. Fair Value Measurements” for additional discussion.

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

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

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

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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. SFAS 141R is prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. EAC currently does not have any pending acquisitions that would fall within the scope of SFAS 141R. Future acquisitions could impact EAC’s results of operations and financial condition and the reporting 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 effective for financial statements issued for fiscal years beginning on or after December 15, 2008, except for the presentation and disclosure requirements which were retrospectively effective. 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 at amounts that include the amounts attributable to both the parent and the noncontrolling interest and the disclosure of consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of operations and gains and losses 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 and financial condition. As previously discussed, the retrospective application of SFAS 160 resulted in the reclassification of approximately $169.1 million and $122.5 million from “Minority interest in consolidated partnership” to “Noncontrolling interest” at December 31, 2008 and 2007, respectively, on the accompanying Consolidated Balance Sheets.

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 133, to require enhanced disclosures about: (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 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding EAC’s derivative instruments; however, it will not impact EAC’s results of operations or financial condition.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”)

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

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. 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. As previously discussed, the retrospective application of FSP EITF 03-6-1 reduced EAC’s basic earnings per common share by $0.14 and $0.03 for the years ended December 31, 2008 and 2006 and reduced EAC’s diluted earnings per share by $0.06, $0.01, and $0.01 for the years ended December 31, 2008, 2007, and 2006, respectively. The adoption of FSP EITF 03-6-1 did not have an impact on EAC’s basic earnings per share for the year ended December 31, 2007. Please read “Note 11. EPS” for additional discussion.

Note 3. Acquisitions and Dispositions

Acquisitions

In January 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) to acquire oil and natural gas properties and related assets in the Williston Basin of Montana and North Dakota. The closing of the Williston Basin acquisition occurred in April 2007. The Williston Basin acquisition was treated as a reverse like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended, (the “Code”) and I.R.S. Revenue Procedure 2000-37 with the Mid-Continent disposition discussed below. The total purchase price for the Williston Basin assets was approximately $392.1 million, including transaction costs of approximately $1.3 million.

Also in January 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included oil and natural gas properties and related assets in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas properties and related assets in the Gooseberry field in Park County, Wyoming. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, and the rights and duties under the purchase and sale agreement relating to the Gooseberry assets to Encore Operating. The closing of the Big Horn Basin acquisition occurred in March 2007. The total purchase price for the Big Horn Basin assets was approximately $393.6 million, including transaction costs of approximately $1.3 million.

EAC financed the acquisitions of the Gooseberry assets and Williston Basin assets through borrowings under its revolving credit facility. ENP financed the acquisition of the Elk Basin assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned guarantor subsidiary of EAC, and borrowings under OLLC’s revolving credit facility. Please read “Note 8. Long-Term Debt” for additional discussion of EAC’s long-term debt.

Dispositions

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

Pro Formas

The following unaudited pro forma condensed financial data was derived from the historical financial statements of EAC and from the accounting records of Anadarko to give effect to the Big Horn Basin and Williston Basin asset acquisitions and the Mid-Continent asset disposition as if they had each occurred on January 1, 2006. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Big

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Horn Basin and Williston Basin asset acquisitions and the Mid-Continent asset disposition taken place on January 1, 2006 and is not intended to be a projection of future results.


	Year Ended December 31,
	2007		2006
	(in thousands, except per share amounts)

Pro forma total revenues	$	749,659	$	785,281


Pro forma net income attributable to EAC stockholders	$	20,685	$	100,702


Pro forma net income per common share:
Basic	$	0.38	$	1.91
Diluted	$	0.38	$	1.89

Note 4. Commitments and Contingencies

Litigation

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

Leases

EAC leases office space and equipment that have remaining non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2008 (in thousands):


2009	$	3,603
2010		3,609
2011		3,598
2012		3,358
2013		2,607
Thereafter		—

	$	16,775

EAC’s operating lease rental expense was approximately $5.8 million, $5.5 million, and $4.6 million in 2008, 2007, and 2006, respectively.

ExxonMobil

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

In July 2008, EAC earned the right to participate in all fields by drilling the final well of the 24-well commitment program and is entitled to a 30 percent working interest in future drilling locations. EAC has the right to propose and drill wells for as long as it is engaged in continuous drilling operations.

During 2008 and 2007, EAC advanced $38.0 million and $37.7 million, respectively, to ExxonMobil for its portion of costs incurred drilling wells under the joint development agreement. At December 31, 2008, EAC had a net receivable from ExxonMobil of $79.0 million, of which $11.2 million was included in “Accounts receivable, net” and $67.8 million was included in “Long-term receivables” on the accompanying Consolidated Balance Sheet based on when EAC expects repayment. At December 31, 2007, EAC

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

had a net receivable from ExxonMobil of $51.7 million, of which $12.3 million was included in “Accounts receivable, net” and $39.4 million was included in “Long-term receivables, net” on the accompanying Consolidated Balance Sheet.

Note 5. Asset Retirement Obligations

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. As of December 31, 2008 and 2007, EAC had $9.2 million and $6.7 million, respectively, held in escrow from which funds are released only for reimbursement of plugging and abandonment expenses on its Bell Creek properties, which is included in other long-term assets in the accompanying Consolidated Balance Sheets. The following table summarizes the changes in EAC’s asset retirement obligations for the periods indicated:


	Year Ended December 31,
	2008			2007
	(in thousands)
Future abandonment liability at January 1	$	28,079		$	19,841
Wells drilled		498			145
Acquisition of properties		111			8,251
Disposition of properties		—			(959	)
Accretion of discount		1,361			1,145
Plugging and abandonment costs incurred		(1,756	)		(1,655	)
Revision of previous estimates		21,276			1,311

Future abandonment liability at December 31	$	49,569		$	28,079

As of December 31, 2008, $48.1 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” on the accompanying Consolidated Balance Sheets. Approximately $4.4 million of the future abandonment liability as of December 31, 2008 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.

Note 6. Capitalization of Exploratory Well Costs

EAC follows FSP No. 19-1 “Accounting for Suspended Well Costs” (“FSP 19-1”), which permits the continued capitalization of exploratory well costs if the well found a sufficient quantity of reserves to justify its completion as a producing well and 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.


	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Beginning balance at January 1	$	19,479		$	13,048		$	6,560
Additions to capitalized exploratory well costs pending the determination of proved reserves		28,757			19,479			13,048
Reclassification to proved property and equipment based on the determination of proved reserves		(19,229	)		(9,390	)		(1,457	)
Capitalized exploratory well costs charged to expense		(250	)		(3,658	)		(5,103	)

Total	$	28,757		$	19,479		$	13,048

All capitalized exploratory well costs have been capitalized for less than one year.

Note 7. Other Current Liabilities

Other current liabilities consisted of the following as of the dates indicated:

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


	December 31,
	2008		2007
	(in thousands)
Net profits interests payable	$	995	$	3,996
Income taxes payable		940		2,789
Accrued compensation		16,216		8,431
Current portion of future abandonment liability		1,511		708
Other		3,430		5,219

Total	$	23,092	$	21,143

Note 8. Long-Term Debt

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


	Maturity		December 31,
	Date		2008		2007
			(in thousands)
Revolving credit facilities		3/7/2012	$	725,000	$	526,000
6.25% Senior Subordinated Notes		4/15/2014		150,000		150,000
6.0% Senior Subordinated Notes, net of unamortized discount of $3,960 and $4,440, respectively		7/15/2015		296,040		295,560
7.25% Senior Subordinated Notes, net of unamortized discount of $1,229 and $1,324, respectively		12/1/2017		148,771		148,676

Total			$	1,319,811	$	1,120,236

Senior Subordinated Notes

As of December 31, 2008 certain of EAC’s subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantors may without restriction transfer funds to EAC in the form of cash dividends, loans, and advances. Please read “Note 16. Financial Statements of Subsidiary Guarantors” for additional discussion.

The indentures governing EAC’s senior subordinated notes contain certain affirmative, negative, and financial covenants, which include:

	•		limitations on incurrence of additional debt, restrictions on asset dispositions, and restricted payments;

	•		a requirement that EAC maintain a current ratio (as defined in the indentures) of not less than 1.0 to 1.0; and

	•		a requirement that EAC maintain a ratio of consolidated EBITDA (as defined in the indentures) to consolidated interest expense of not less than 2.5 to 1.0.

As of December 31, 2008, EAC was in compliance with all covenants of its senior subordinated notes.

If EAC experiences a change of control (as defined in the indentures), subject to certain conditions, it must give holders of its senior subordinated notes the opportunity to sell them to EAC at 101 percent of the principal amount, plus accrued and unpaid interest.

Revolving Credit Facilities

Encore Acquisition Company Senior Secured Credit Agreement

In March 2007, EAC entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective February 7, 2008, EAC amended the EAC Credit Agreement to, among other things, provide that certain negative covenants in the EAC Credit Agreement restricting hedge transactions do not apply to any oil and natural gas hedge transaction that is a floor or put transaction not requiring any future payments or delivery by EAC or any of its restricted subsidiaries. Effective May 22, 2008, EAC amended the EAC Credit Agreement to, among other things, increase interest rate margins applicable to loans made under the EAC Credit Agreement, as set forth in the table below, and increase the borrowing base to $1.1 billion. The EAC Credit Agreement

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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 the account of any of its restricted subsidiaries.

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


	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.250	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.500	%		0.250	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.750	%		0.500	%
Greater than or equal to .90 to 1		2.000	%		0.750	%

The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5 percent.

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

The EAC Credit Agreement contains covenants that include, among others:

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

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

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

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

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

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

	•		a requirement that we maintain a ratio of consolidated current assets (as defined in the EAC Credit Agreement) to consolidated current liabilities (as defined in the EAC Credit Agreement) of not less than 1.0 to 1.0; and

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

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

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


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

On December 31, 2008, there were $575 million of outstanding borrowings and $525 million of borrowing capacity under the EAC Credit Agreement. As of December 31, 2008, EAC was in compliance with all covenants of the EAC Credit Agreement.

Encore Energy Partners Operating LLC Credit Agreement

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


	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.000	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.250	%		0.000	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.500	%		0.250	%
Greater than or equal to .90 to 1		1.750	%		0.500	%

The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5 percent.

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

The OLLC Credit Agreement contains covenants that include, among others:

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

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

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

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

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

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

	•		a requirement that ENP and OLLC maintain a ratio of consolidated current assets (as defined in the OLLC Credit Agreement) to consolidated current liabilities (as defined in the OLLC Credit Agreement) of not less than 1.0 to 1.0;

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

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

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

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


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

On December 31, 2008, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement. As of December 31, 2008, OLLC was in compliance with all covenants of the OLLC Credit Agreement.

Long-Term Debt Maturities

The following table illustrates EAC’s long-term debt maturities as of December 31, 2008:


	Payments Due by Period
	Total		2009		2010		2011		2012		2013		Thereafter
	(in thousands)
6.25% Notes	$	150,000	$	—	$	—	$	—	$	—	$	—	$	150,000
6.0% Notes		300,000		—		—		—		—		—		300,000
7.25% Notes		150,000		—		—		—		—		—		150,000
Revolving credit facilities		725,000		—		—		—		725,000		—		—

Total	$	1,325,000	$	—	$	—	$	—	$	725,000	$	—	$	600,000

During 2008, 2007, and 2006, the weighted average interest rate for total indebtedness was 5.6 percent, 6.9 percent, and 6.1 percent, respectively.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 9. Taxes

Income Taxes

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


	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Federal:
Current	$	(7,626	)	$	(1,888	)	$	(3,785	)
Deferred		(222,651	)		(11,229	)		(48,327	)

Total federal		(230,277	)		(13,117	)		(52,112	)


State, net of federal benefit:
Current		(1,381	)		—			(401	)
Deferred		(9,963	)		(1,359	)		(2,893	)

Total state		(11,344	)		(1,359	)		(3,294	)

Income tax provision (a)	$	(241,621	)	$	(14,476	)	$	(55,406	)


(a)		Excludes an excess tax benefit related to stock option exercises and vesting of restricted stock, which was recorded directly to additional paid-in capital, of $2.1 million and $1.3 million during 2008 and 2006, respectively. During 2007, EAC did not recognize an excess tax benefit related to stock option exercises and vesting of restricted stock.

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


	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Income before income taxes	$	726,685		$	24,153		$	147,804

Income taxes at the Federal statutory rate	$	(254,340	)	$	(8,454	)	$	(51,731	)
State income taxes, net of federal benefit		(12,861	)		(716	)		(3,440	)
Enactment of the Texas margin tax		—			—			(1,062	)
Change in estimated future state tax rate		2,113			(495	)		1,208
Nondeductible deferred compensation expense		(1,124	)		(1,963	)		—
Tax on income attributable to noncontrolling interest		18,988			(2,617	)		—
Permanent and other		5,603			(231	)		(381	)

Income tax provision	$	(241,621	)	$	(14,476	)	$	(55,406	)

A Texas franchise tax reform measure signed into law in May 2006 caused the Texas franchise tax to be applicable to numerous types of entities that previously were not subject to the tax, including several of EAC’s subsidiaries. EAC adjusted its net deferred tax balances using the new higher marginal tax rate it expects to be effective when those deferred taxes reverse resulting in a charge of $1.1 million during 2006.

The major components of net current deferred taxes and net long-term deferred taxes were as follows as of the dates indicated:

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


	December 31,
	2008			2007
	(in thousands)
Current:
Assets:
Unrealized hedge loss in accumulated other comprehensive loss	$	222		$	1,071
Derivative fair value loss		—			15,442
Other		2,422			3,907

Total current deferred tax assets		2,644			20,420

Liabilities:
Derivative fair value gain		(108,412	)		—

Total current deferred tax liabilities		(108,412	)		—

Net current deferred tax asset (liability)	$	(105,768	)	$	20,420


Long-term:
Assets:
Alternative minimum tax credits	$	2,300		$	2,676
Unrealized hedge loss in accumulated other comprehensive loss		735			—
Derivative fair value loss		—			10,775
Section 43 credits		8,889			13,227
Net operating loss carryforward		1,439			23,806
Change in accounting method		5,583			—
Asset retirement obligations		17,842			11,266
Deferred equity-based compensation		6,757			6,599
Other		1,556			—

Total long-term deferred tax assets		45,101			68,349

Liabilities:
Derivative fair value gain		(2,711	)		—
Other		—			(11,076	)
Book basis of oil and natural gas properties in excess of tax basis		(459,305	)		(370,187	)

Total current deferred tax liabilities		(462,016	)		(381,263	)

Net long-term deferred tax liability	$	(416,915	)	$	(312,914	)

At December 31, 2008, EAC had state net operating loss (“NOL”) carryforwards, which are available to offset future regular state taxable income, if any. At December 31, 2008, EAC also had federal alternative minimum tax (“AMT”) credits, which are available to reduce future federal regular tax liabilities in excess of AMT. EAC believes it is more likely than not that the NOL carryforwards will offset future taxable income prior to their expiration. The AMT credits have no expiration. Therefore, a valuation allowance against these deferred tax assets is not considered necessary. If unused, these carryforwards and credits will expire as follows:


	Federal		State
Expiration Date	AMT Credits		NOL
	(in thousands)
2012	$	—	$	41
2014		—		299
2024		—		196
2025		—		656
2026		—		152
2027		—		95
Indefinite		2,300		—

	$	2,300	$	1,439

On January 1, 2007, EAC adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. EAC and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, EAC is no longer subject to U.S. federal, state, and local income tax examinations for years prior to 2003.

EAC performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in EAC’s financial statements, including, but not limited to:

	•		a review of documentation of tax positions taken on previous returns including an assessment of whether EAC followed industry practice or the applicable requirements under the tax code;

	•		a review of open tax returns (on a jurisdiction by jurisdiction basis) as well as supporting documentation used to support those tax returns;

	•		a review of the results of past tax examinations;

	•		a review of whether tax returns have been filed in all appropriate jurisdictions;

	•		a review of existing permanent and temporary differences; and

	•		consideration of any tax planning strategies that may have been used to support realization of deferred tax assets.

On the date of adoption of FIN 48 and as of December 31, 2008 and 2007, all of EAC’s tax positions met the “more-likely-than-not” threshold prescribed by FIN 48. As a result, no additional tax expense, interest, or penalties have been accrued. EAC includes interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. For 2008, 2007, and 2006, EAC recorded only a nominal amount of interest and penalties on certain tax positions.

Taxes Other than Income Taxes

Taxes other than income taxes included the following for the periods indicated:


	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Production and severance taxes	$	96,468	$	65,145	$	43,458
Ad valorem taxes		14,176		9,440		6,322
Franchise, payroll, and other taxes		2,479		2,263		1,745

Total	$	113,123	$	76,848	$	51,525

Note 10. Stockholders’ Equity

Public Offering of Common Stock

In April 2006, EAC issued 4,000,000 shares of its common stock at a price of $32.00 per share. The net proceeds of approximately $127.1 million were used to (1) reduce outstanding borrowings under EAC’s revolving credit facility, (2) invest in oil and natural gas activities, and (3) pay general corporate expenses.

Stock Option Exercises and Restricted Stock Vestings

During 2008, 2007, and 2006, employees of EAC exercised 45,616 options, 128,709 options, and 178,174 options, respectively, for which EAC received proceeds of $0.6 million, $1.6 million, and $2.3 million in 2008, 2007, and 2006, respectively. During 2008, 2007, and 2006, employees elected to satisfy minimum tax withholding obligations related to the vesting of restricted stock by directing EAC to withhold 32,946 shares, 38,978 shares, and 24,362 shares of common stock, respectively, which are accounted for as treasury stock until they are formally retired.

Preferred Stock

EAC’s authorized capital stock includes 5,000,000 shares of preferred stock, none of which were issued and outstanding at

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

December 31, 2008 or 2007. EAC does not plan to issue any shares of preferred stock.

Stock Repurchase Programs

In December 2007, EAC announced that the Board approved a share repurchase program authorizing EAC to repurchase up to $50 million of its common stock. During 2008, EAC completed the share repurchase program by repurchasing and retiring 1,397,721 shares of its outstanding common stock at an average price of approximately $35.77 per share.

In October 2008, EAC announced that the Board approved a new share repurchase program authorizing EAC to repurchase up to $40 million of its common stock. As of December 31, 2008, EAC had repurchased and retired 620,265 shares of its outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the new share repurchase program.

Issuance of ENP Common Units

In May 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin of West Texas in exchange for 283,700 common units which were valued at $5.8 million at the time of the acquisition. As a result, EAC’s percentage ownership in ENP went from approximately 67 percent to approximately 66 percent. Additionally, EAC reclassified $3.5 million from “Noncontrolling interest” to “Additional paid-in capital” on the accompanying Consolidated Balance Sheets to recognize gains on the issuance of ENP’s common units.

In December 2008, as a result of the conversion of ENP’s management incentive units into ENP common units, EAC recorded a $13.9 million economic uniformity adjustment by reducing “Additional paid-in capital” and increasing “Noncontrolling interest” in the accompanying Consolidated Balance Sheets.

In September 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit, and in October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units. As a result, EAC’s percentage ownership in ENP went from 100 percent to approximately 58 percent. Additionally, EAC reclassified $77.6 million from “Noncontrolling interest” to “Additional paid-in capital” on the accompanying Consolidated Balance Sheets to recognize gains on the issuance of ENP’s common units.

Rights Plan

In October 2008, the Board declared a dividend of one right for each outstanding share of EAC’s common stock to stockholders of record at the close of business on November 7, 2008. Each right entitles the registered holder to purchase from EAC a unit consisting of one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.01 per share, at a purchase price of $120 per fractional share, subject to adjustment.

The rights will separate from the common stock and a “Distribution Date” will occur, with certain exceptions, upon the earlier of (1) ten days following a public announcement that a person or group of affiliated or associated persons (an “Acquiring Person”) has acquired, or obtained the right to acquire, beneficial ownership of more than 10 percent of EAC’s then-outstanding shares of common stock, or (2) ten business days following the commencement of a tender offer or exchange offer that would result in a person’s becoming an Acquiring Person. In certain circumstances, the Distribution Date may be deferred by the Board. The rights are not exercisable until the Distribution Date and will expire at the close of business on October 28, 2011, unless earlier redeemed or exchanged by EAC.

Note 11. EPS

As discussed in “Note 2. Summary of Significant Accounting Policies,” EAC adopted FSP EITF 03-6-1 on January 1, 2009, and all periods presented have been restated to calculate EPS in accordance with this pronouncement. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that contains nonforfeitable rights to dividends or dividend equivalents paid to common stockholders. For purposes of calculating EPS, unvested restricted stock awards are considered participating securities. EPS is calculated by dividing the common stockholders’ interest in net income, after deducting the interests of participating securities, by the weighted average shares outstanding. For 2008 and 2006, basic EPS decreased by $0.14 and $0.03, respectively, per common share for the adoption of FSP EITF 03-6-1. For 2007, basic EPS was unaffected by the adoption of FSP EITF 03-6-1. For 2008, 2007, and

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

2006, diluted EPS decreased by $0.06, $0.01, and $0.01, respectively, per common share for the adoption of FSP EITF 03-6-1.

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


	Year Ended December 31,
	2008			2007			2006
	(in thousands, except per share amounts)
Basic Earnings Per Share
Numerator:
Undistributed net income — attributable to EAC	$	430,812		$	17,155		$	92,398
Less: participation rights of unvested restricted stock in undistributed earnings		(7,595	)		(291	)		(1,454	)

Basic undistributed net income — attributable to EAC common shares	$	423,217		$	16,864		$	90,944

Denominator:
Basic weighted average shares outstanding		52,270			53,170			51,865

Basic EPS — attributable to EAC common shares	$	8.10		$	0.32		$	1.75


Diluted Earnings Per Share
Numerator:
Undistributed net income — attributable to EAC common shares	$	430,812		$	17,155		$	92,398
Less: participation rights of unvested restricted stock in undistributed earnings		(7,511	)		(289	)		(1,440	)

Diluted undistributed net income — attributable to EAC common shares	$	423,301		$	16,866		$	90,958

Denominator:
Basic weighted average shares outstanding		52,270			53,170			51,865
Effect of dilutive options (a)		596			459			491

Diluted weighted average shares outstanding		52,866			53,629			52,356

Diluted EPS — attributable to EAC common shares	$	8.01		$	0.31		$	1.74


(a)		For 2008, 2007, and 2006, options to purchase 157,614, 121,651, and 103,856 shares of common stock, respectively, were outstanding but excluded from the diluted EPS calculations because their effect would have been antidilutive.

Note 12. Employee Benefit Plans

401(k) Plan

EAC made contributions to its 401(k) plan, which is a voluntary and contributory plan for eligible employees based on a percentage of employee contributions, of $3.6 million, $2.2 million, and $1.1 million during 2008, 2007, and 2006, respectively. EAC’s 401(k) plan does not allow employees to invest in securities of EAC.

Incentive Stock Plans

In May 2008, EAC’s stockholders approved the 2008 Incentive Stock Plan (the “2008 Plan”). No additional awards will be granted under EAC’s 2000 Incentive Stock Plan (the “2000 Plan”) and any previously granted awards outstanding under the 2000 Plan will remain outstanding in accordance with their terms. The purpose of the 2008 Plan is to attract, motivate, and retain selected employees of EAC and to provide EAC with the ability to provide incentives more directly linked to the profitability of the business and increases in shareholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the 2008 Plan. The total number of shares of common stock reserved for issuance pursuant to the 2008 Plan is 2,400,000. No more than 1,600,000 shares of EAC’s common stock will be available for grants of “full value” stock awards, such as restricted stock or stock units. As of December 31, 2008, there were 2,389,000 shares available for issuance under the 2008 Plan. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax withholding, shares subject to options or other awards that expire or are forfeited, and restricted shares that are forfeited will again become available for issuance under the 2008 Plan. The 2008 Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Board. The Board also has a Restricted Stock Award Committee whose sole member is Jon S. Brumley, EAC’s Chief Executive Officer and President. The Restricted Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual basis to non-executive employees at its discretion.

The 2008 Plan contains the following individual limits:

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

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

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

In May 2008, the Board approved certain amendments to the 2000 Plan to ensure compliance with Section 409A of the Code. In particular, the 2000 Plan was amended to allow for the exemption of options from the requirements of Section 409A of the Code by requiring that, upon a change-in-control, options granted or that vest on or after January 1, 2005 be valued at their fair market value as of the date they are cashed out, rather than the highest price per share paid in the 60 days prior to the change-in-control. The amendments to the 2000 Plan did not require stockholder approval under its terms, applicable laws, or the rules of the New York Stock Exchange.

During 2008, 2007, and 2006, EAC recorded non-cash stock-based compensation expense related to its incentive stock plans in the accompanying Consolidated Statements of Operations of $9.0 million, $9.2 million, and $9.0 respectively, and recognized income tax benefits related thereto of $3.4 million, $3.4 million, and $3.2 million, respectively. During 2008, 2007, and 2006, EAC also capitalized $2.3 million, $1.3 million, and $1.1 million, respectively, of non-cash stock-based compensation cost as a component of “Properties and equipment” in the accompanying Consolidated Balance Sheets. Non-cash stock-based compensation expense has been allocated to LOE and general and administrative (“G&A”) expense based on the allocation of the respective employees’ cash compensation.

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

Stock Options. All options have a strike price equal to the fair market value of EAC’s common stock on the grant date, have a ten-year life, and vest over a three-year period. The fair value of options granted was estimated on the grant date using a Black-Scholes option valuation model based on the assumptions noted in the following table. The expected volatility was based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the options. For options granted prior to January 1, 2008, EAC used the “simplified” method prescribed by Staff Accounting Bulletin No. 107, “Valuation of Share-Based Payment Arrangements for Public Companies” to estimate the expected term of the options, which was calculated as the average midpoint between each vesting date and the life of the option. For options granted subsequent to December 31, 2007, EAC determined the expected life of the options based on an analysis of historical exercise and forfeiture behavior as well as expectations about future behavior. The risk-free interest rate is based on the U.S Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the options.


	Year Ended December 31,
	2008			2007			2006
Expected volatility		33.7	%		35.7	%		42.8	%
Expected dividend yield		0.0	%		0.0	%		0.0	%
Expected term (in years)		6.25			6.0			6.0
Risk-free interest rate		3.0	%		4.8	%		4.6	%

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The following table summarizes the changes in EAC’s outstanding options for the periods indicated:


	Year Ended December 31,
	2008									2007					2006
						Weighted
						Average
				Weighted		Remaining		Aggregate					Weighted					Weighted
	Number of			Average		Contractual		Intrinsic		Number of			Average		Number of			Average
	Options			Strike Price		Term		Value		Options			Strike Price		Options			Strike Price
								(in thousands)
Outstanding at beginning of year		1,381,782		$	16.03						1,337,118		$	14.44		1,440,812		$	13.20
Granted		176,170			33.76						200,059			25.73		122,890			31.10
Forfeited or expired		(14,923	)		30.83						(26,686	)		27.15		(48,410	)		24.65
Exercised		(45,616	)		14.11						(128,709	)		12.34		(178,174	)		13.14

Outstanding at end of year		1,497,413			18.02		5.1	$	13,224		1,381,782			16.03		1,337,118			14.44

Exercisable at end of year		1,177,015			14.65		4.2		13,224		1,103,018			13.25		1,076,815			11.90

The weighted average fair value per share of options granted during 2008, 2007, and 2006 was $13.15, $11.16, and $14.96, respectively. The total intrinsic value of options exercised during 2008, 2007, and 2006 was $1.6 million, $2.3 million, and $2.4 million, respectively. During 2008, 2007, and 2006, EAC received proceeds from the exercise of stock options of $0.5 million, $1.6 million, and $2.3 million, respectively. During 2008 and 2006, EAC recognized income tax benefits related to stock options of $0.5 million and $0.9 million, respectively. During 2007, EAC did not recognize any income tax benefits related to stock options. At December 31, 2008, EAC had $1.1 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 1.9 years.

Additional information about options outstanding and exercisable at December 31, 2008 is as follows:


			Weighted				Weighted
	Range of		Number of		Average		Average		Number of
	Strike Prices		Options		Life		Strike		Options
Year of Grant	Per Share		Outstanding		(Years)		Price		Exercisable
2001	$8.33 to $9.33			409,486		2.5	$	8.85		409,486
2002	$8.50 to $12.40			284,085		3.8		11.94		284,085
2003	$11.49 to $13.61			35,965		4.5		12.28		35,965
2004	$17.17 to $19.77			259,075		5.1		17.55		259,075
2005	$	26.55		68,105		6.1		26.55		68,105
2006	$	31.10		92,823		7.1		31.10		61,716
2007	$	25.73		181,174		8.1		25.73		58,583
2008	$	33.76		166,700		9.1		33.76		—

				1,497,413						1,177,015

Restricted Stock. Restricted stock awards vest over varying periods from one to five years, subject to performance-based vesting for certain members of senior management. During 2008, 2007, and 2006, EAC recognized expense related to restricted stock of $7.6 million, $7.6 million, and $7.3 million, respectively. During 2008 and 2006, EAC recognized income tax benefits related to the vesting of restricted stock of $1.6 million and $0.4 million, respectively. During 2007, EAC did not recognize any income tax benefits related to the vesting of restricted stock. The following table summarizes the changes in the number of EAC’s unvested restricted stock awards and their related weighted average grant date fair value for 2008:

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value

Outstanding at January 1, 2008		918,338		$	27.07
Granted		314,086			37.02
Vested		(256,785	)		25.63
Forfeited		(37,232	)		29.59

Outstanding at December 31, 2008		938,407			30.67

During 2008, 2007, and 2006, EAC issued 241,515 shares, 169,453 shares, and 277,162 shares, respectively, of restricted stock to employees and members of the Board, the vesting of which is dependent only on the passage of time and continued employment. The following table illustrates outstanding restricted stock at December 31, 2008 the vesting of which is dependent only on the passage of time and continued employment:


	Year of Vesting
Year of Grant	2009		2010		2011		2012		Total
2004		25,119		—		—		—		25,119
2005		71,483		71,483		—		—		142,966
2006		169,408		60,793		—		—		230,201
2007		75,014		79,183		79,184		4,167		237,548
2008		52,827		52,832		76,836		52,839		235,334

Total		393,851		264,291		156,020		57,006		871,168

During 2008, 2007, and 2006, EAC issued 72,571 shares, 175,180 shares, and 151,447 shares of restricted stock to certain members of senior management, the vesting of which is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures. The performance measures related to the 2007 and 2006 awards were met and therefore, vesting depends only on the passage of time and continued employment. The following table illustrates outstanding restricted stock at December 31, 2008 the vesting of which is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures:


	Year of Vesting
Year of Grant	2009		2010		2011		2012		Total
2008		16,810		16,810		16,810		16,809		67,239

As of December 31, 2008, EAC had $8.2 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 2.7 years. None of EAC’s unvested restricted stock is subject to variable accounting. During 2008, 2007, and 2006, there were 256,785 shares, 184,867 shares, and 101,377 shares, respectively, of restricted stock that vested for which certain employees elected to satisfy minimum tax withholding obligations related thereto by directing EAC to withhold 32,946 shares, 38,978 shares, and 24,362 shares of common stock, respectively. EAC accounts for these shares as treasury stock until they are formally retired and have been reflected as such in the accompanying consolidated financial statements. The total fair value of restricted stock that vested during 2008, 2007, and 2006 was $8.7 million, $5.3 million, and $2.6 million, respectively.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 13. Financial Instruments

The following table sets forth EAC’s book value and estimated fair value of financial instrument assets (liabilities) as of the dates indicated:


	December 31,
	2008						2007
	Book			Fair			Book			Fair
	Value			Value			Value			Value
				(in thousands)
Cash and cash equivalents	$	2,039		$	2,039		$	1,704		$	1,704
Accounts receivable, net		129,065			129,065			134,880			134,880
Plugging bond		824			1,202			777			921
Bell Creek escrow		9,229			9,241			6,701			6,728
Accounts payable		10,017			10,017			(21,548	)		(21,548	)
6.25% Notes		(150,000	)		(101,250	)		(150,000	)		(138,375	)
6.0% Notes		(296,040	)		(194,250	)		(295,560	)		(264,750	)
7.25% Notes		(148,771	)		(94,500	)		(148,676	)		(143,813	)
Revolving credit facilities		(725,000	)		(725,000	)		(526,000	)		(526,000	)
Commodity derivative contracts		387,612			387,612			9,798			9,798
Deferred premiums on commodity derivative contracts		(67,610	)		(67,610	)		(51,926	)		(51,926	)
Interest rate swaps		(4,559	)		(4,559	)		—			—

The book value of cash and cash equivalents, accounts receivable, net, and accounts payable approximate fair value due to the short-term nature of these instruments. The fair values of the Notes were determined using open market quotes. The difference between book value and fair value 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. The plugging bond and Bell Creek escrow are included in “Other assets” on 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 and Bell Creek escrow were determined using open market quotes. Commodity derivative contracts and interest rate swaps are marked-to-market each quarter.

Derivative Financial Instruments

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.

As of December 31, 2008, EAC had $67.6 million of deferred premiums payable of which $5.4 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $62.2 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 January 2009 to January 2010. EAC recorded these premiums at their net present value at the time the contract was entered into and accretes that value to the eventual settlement price by recording interest expense each period.

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

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

Oil Derivative Contracts


	Average		Weighted		Average			Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily			Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price		Value
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)		(in thousands)
2009 (a)																		$	342,063
		11,630	$	110.00		—		$	—		—	$	—		2,000	$	90.46
		8,000		80.00		—			—		440		97.75		500		89.39
		—		—		(5,000	)		50.00		—		—		1,000		68.70
2010																			17,618
		880		80.00		—			—		440		93.80		—		—
		2,000		75.00		—			—		1,000		77.23		—		—
2011																			15,112
		1,880		80.00		—			—		1,440		95.41		—		—
		1,000		70.00		—			—		—		—		—		—

																		$	374,793


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

Natural Gas Derivative Contracts


	Average		Weighted		Average	Weighted	Average		Weighted		Average		Weighted
	Daily		Average		Daily	Average	Daily		Average		Daily		Average		Asset
	Floor		Floor		Short Floor	Short Floor	Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume	Price	Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)	(per Mcf)	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
2009															$	7,281
		3,800	$	8.20	—	$ —		3,800	$	9.83		—	$	—
		3,800		7.20	—	—		—		—		—		—
		1,800		6.76	—	—		—		—		—		—
2010																4,690
		3,800		8.20	—	—		3,800		9.58		902		6.30
		4,698		7.26	—	—		—		—		—		—
2011																424
		898		6.76	—	—		—		—		902		6.70
2012																424
		898		6.76	—	—		—		—		902		6.66

															$	12,819

Interest Rate Swaps. ENP manages interest rate risk with interest rate swaps whereby it swaps floating rate debt under the OLLC Credit Agreement with a weighted average fixed rate. These interest rate swaps were designated as cash flow hedges. The following table summarizes ENP’s open interest rate swaps as of December 31, 2008:


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

As of December 31, 2008, the fair market value of ENP’s interest rate swaps was a net liability of $4.6 million of which, $1.3 million was current and included in the current liabilities line “Derivatives” and $3.3 million was long-term and included in the other

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

liabilities line “Derivatives” in the accompanying Consolidated Balance Sheets. During 2008, settlements of interest rate swaps increased EAC’s consolidated interest expense by approximately $0.2 million.

Current Period Impact. As a result of commodity derivative contracts which were previously designated as hedges, EAC recognized a pre-tax reduction in oil and natural gas revenues of approximately $2.9 million, $53.6 million, and $60.3 million in 2008, 2007, and 2006, respectively. EAC also recognized derivative fair value gains and losses related to: (1) ineffectiveness on designated derivative contracts; (2) changes in the market value of derivative contracts; (3) settlements on commodity derivative contracts; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:


	Year Ended December 31,
	2008			2007		2006
	(in thousands)
Ineffectiveness on designated derivative contracts	$	372		$	—	$	1,748
Mark-to-market loss (gain) derivative contracts		(365,495	)		36,272		(31,205	)
Premium amortization		62,352			41,051		13,926
Settlements on commodity derivative contracts		(43,465	)		35,160		(8,857	)

Total derivative fair value loss (gain)	$	(346,236	)	$	112,483	$	(24,388	)

Counterparty Risk. At December 31, 2008, EAC had committed greater than 10 percent of either its oil or natural gas commodity derivative contracts to the following counterparties:


	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed

BNP Paribas		22	%		24	%
Calyon		15	%		31	%
Fortis		11	%		—
UBS		16	%		—
Wachovia		11	%		38	%

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 separately each derivative financial transaction between the counterparty and EAC, 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.

Accumulated Other Comprehensive Loss. At December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps that are designated as hedges of $1.7 million. At December 31, 2007, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on commodity derivative contracts that were previously designated as hedges of $1.8 million.

EAC expects to reclassify $1.3 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense during 2009. EAC also expects to reclassify $0.2 million of income taxes associated with ENP’s interest rate swaps from accumulated other comprehensive loss to income tax benefit during 2009.

Note 14. Fair Value Measurements

As discussed in “Note 2. Summary of Significant Accounting Policies,” 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:

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

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

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

EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions are 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 December 31, 2008:


				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable Inputs			Unobservable Inputs
Description	December 31, 2008			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	37,458		$	—	$	37,458		$	—
Oil derivative contracts — floors and caps		337,335			—		—			337,335
Natural gas derivative contracts — swaps		78			—		78			—
Natural gas derivative contracts — floors and caps		12,741			—		—			12,741
Interest rate swaps		(4,559	)		—		(4,559	)		—

Total	$	383,053		$	—	$	32,977		$	350,076

The following table summarizes the changes in the fair value of EAC’s Level 3 financial assets and liabilities for 2008:


	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, 2008	$	16,647		$	7,081	$	23,728
Total gains (losses):
Included in earnings		350,584			5,104		355,688
Purchases, issuances, and settlements		(29,896	)		556		(29,340	)

Balance at December 31, 2008	$	337,335		$	12,741	$	350,076


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	$	350,584		$	5,104	$	355,688

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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 reflected in the table above and in the accompanying Consolidated Balance Sheet have been adjusted for non-performance risk, resulting in a reduction of the net asset of approximately $3.4 million as of December 31, 2008.

Note 15. Related Party Transactions

During 2008, 2007, and 2006, EAC received approximately $160.5 million, $85.3 million, and $7.4 million, respectively, from affiliates of Tesoro Corporation (“Tesoro”) related to gross oil and natural gas production sold from wells operated by Encore Operating. Mr. John V. Genova, a member of the Board, served as an employee of Tesoro until May 2008.

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

Note 16. Financial Statements of Subsidiary Guarantors

In February 2007, EAC formed certain non-guarantor subsidiaries in connection with the formation of ENP. Please read “Note 17. ENP” for additional discussion of ENP’s formation and other matters. As of December 31, 2008 and 2007, certain of EAC’s wholly owned subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. In accordance with SEC rules, EAC has prepared condensed consolidating financial statements in order to quantify the financial position, results of operations, and cash flows of the subsidiary guarantors. The following Condensed Consolidating Balance Sheets as of December 31, 2008 and 2007 and Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2008 and 2007 present consolidating financial information for Encore Acquisition Company (“Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. As of December 31, 2008, EAC’s guarantor subsidiaries were:

	•		EAP Properties, Inc.;

	•		EAP Operating, LLC;

	•		Encore Operating; and

	•		Encore Operating Louisiana, LLC.

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

	•		ENP;

	•		OLLC;

	•		GP LLC;

	•		Encore Partners GP Holdings LLC;

	•		Encore Partners LP Holdings LLC;

	•		Encore Energy Partners Finance Corporation; and

	•		Encore Clear Fork Pipeline LLC.

All intercompany investments in, loans due to/from, subsidiary equity, and revenues and expenses between the Parent, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements of EAC. Prior to February 2007, all of EAC’s subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. Therefore, a Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) and a Condensed Consolidating Statement of Cash Flows are not presented for 2006.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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


			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS

Current assets:
Cash and cash equivalents	$	607	$	813		$	619		$	—		$	2,039
Other current assets		29,004		421,392			90,797			(2,302	)		538,891

Total current assets		29,611		422,205			91,416			(2,302	)		540,930


Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,016,937			521,522			—			3,538,459
Unproved properties		—		124,272			67			—			124,339
Accumulated depletion, depreciation, and amortization		—		(670,991	)		(100,573	)		—			(771,564	)

		—		2,470,218			421,016			—			2,891,234


Other property and equipment, net		—		11,877			562			—			12,439
Other assets, net		12,846		129,482			46,264			—			188,592
Investment in subsidiaries		2,976,208		(12,865	)		—			(2,963,343	)		—

Total assets	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195


LIABILITIES AND EQUITY

Current liabilities	$	118,089	$	215,640		$	20,825		$	(2,302	)	$	352,252
Deferred taxes		416,637		—			278			—			416,915
Long-term debt		1,169,811		—			150,000			—			1,319,811
Other liabilities		—		48,000			12,969			—			60,969

Total liabilities		1,704,537		263,640			184,072			(2,302	)		2,149,947


Commitments and contingencies (see Note 4)

Total equity		1,314,128		2,757,277			375,186			(2,963,343	)		1,483,248

Total liabilities and equity	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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


			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS

Current assets:
Cash and cash equivalents	$	1	$	1,700		$	3		$	—		$	1,704
Other current assets		535,221		437,852			21,053			(807,320	)		186,806

Total current assets		535,222		439,552			21,056			(807,320	)		188,510


Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		2,467,606			378,170			—			2,845,776
Unproved properties		—		63,352			—			—			63,352
Accumulated depletion, depreciation, and amortization		—		(451,343	)		(37,661	)		—			(489,004	)

		—		2,079,615			340,509			—			2,420,124


Other property and equipment, net		—		10,610			407			—			11,017
Other assets, net		14,899		121,904			28,107			—			164,910
Investment in subsidiaries		2,090,471		20,611			—			(2,111,082	)		—

Total assets	$	2,640,592	$	2,672,292		$	390,079		$	(2,918,402	)	$	2,784,561


LIABILITIES AND EQUITY

Current liabilities	$	306,787	$	687,351		$	17,885		$	(807,293	)	$	204,730
Deferred taxes		312,914		—			—			—			312,914
Long-term debt		1,072,736		—			47,500			—			1,120,236
Other liabilities		—		49,461			26,531			—			75,992

Total liabilities		1,692,437		736,812			91,916			(807,293	)		1,713,872


Commitments and contingencies (see Note 4)

Total equity		948,155		1,935,480			298,163			(2,111,109	)		1,070,689

Total liabilities and equity	$	2,640,592	$	2,672,292		$	390,079		$	(2,918,402	)	$	2,784,561

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Year Ended December 31, 2008
(in thousands)


				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	749,864		$	147,579		$	—		$	897,443
Natural gas		—			192,942			34,537			—			227,479
Marketing		—			5,172			5,324			—			10,496

Total revenues		—			947,978			187,440			—			1,135,418


Expenses:
Production:
Lease operating		—			146,460			28,655			—			175,115
Production, ad valorem, and severance taxes		—			91,809			18,835			—			110,644
Depletion, depreciation, and amortization		—			190,548			37,704			—			228,252
Impairment of long-lived assets		—			59,526			—			—			59,526
Exploration		—			39,026			181			—			39,207
General and administrative		15,801			24,751			12,135			(4,266	)		48,421
Marketing		—			4,104			5,466			—			9,570
Derivative fair value gain		—			(249,356	)		(96,880	)		—			(346,236	)
Provision for doubtful accounts		—			1,984			—			—			1,984
Other operating		165			11,485			1,325			—			12,975

Total expenses		15,966			320,337			7,421			(4,266	)		339,458


Operating income (loss)		(15,966	)		627,641			180,019			4,266			795,960


Other income (expenses):
Interest		(66,204	)		—			(6,969	)		—			(73,173	)
Equity income from subsidiaries		736,408			51,468			—			(787,876	)		—
Other		98			7,967			99			(4,266	)		3,898

Total other expenses		670,302			59,435			(6,870	)		(792,142	)		(69,275	)


Income before income taxes		654,336			687,076			173,149			(787,876	)		726,685
Income tax provision		(240,986	)		—			(635	)		—			(241,621	)

Consolidated net income		413,350			687,076			172,514			(787,876	)		485,064
Amortization of deferred loss on commodity
derivative contracts, net of tax		(1,071	)		2,857			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(625	)		—			(2,692	)		—			(3,317	)

Comprehensive income	$	411,654		$	689,933		$	169,822		$	(787,876	)	$	483,533

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2007
(in thousands)


				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total

Revenues:
Oil	$	—		$	503,981		$	58,836		$	—		$	562,817
Natural gas		—			137,838			12,269			—			150,107
Marketing		—			33,439			8,582			—			42,021

Total revenues		—			675,258			79,687			—			754,945


Expenses:
Production:
Lease operating		—			129,506			13,920			—			143,426
Production, ad valorem, and severance taxes		—			66,014			8,571			—			74,585
Depletion, depreciation, and amortization		—			157,982			25,998			—			183,980
Exploration		—			27,726			—			—			27,726
General and administrative		15,107			15,354			10,707			(2,044	)		39,124
Marketing		—			33,876			6,673			—			40,549
Derivative fair value loss		—			86,182			26,301			—			112,483
Provision for doubtful accounts		—			5,816			—			—			5,816
Other operating		221			16,083			762			—			17,066

Total expenses		15,328			538,539			92,932			(2,044	)		644,755


Operating income (loss)		(15,328	)		136,719			(13,245	)		2,044			110,190


Other income (expenses):
Interest		(82,825	)		(6,415	)		(12,294	)		12,830			(88,704	)
Equity income (loss) from subsidiaries		123,381			(3,205	)		—			(120,176	)		—
Other		6,405			10,940			196			(14,874	)		2,667

Total other expenses		46,961			1,320			(12,098	)		(122,220	)		(86,037	)


Income (loss) before income taxes		31,633			138,039			(25,343	)		(120,176	)		24,153
Income tax benefit (provision)		(14,478	)		—			2			—			(14,476	)

Consolidated net income (loss)		17,155			138,039			(25,341	)		(120,176	)		9,677
Amortization of deferred loss on commodity derivative contracts, net of tax		(20,047	)		53,588			—			—			33,541

Comprehensive income (loss)	$	(2,892	)	$	191,627		$	(25,341	)	$	(120,176	)	$	43,218

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2008
(in thousands)


				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	629,345		$	(81,882	)	$	115,774		$	—		$	663,237


Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(142,471	)		(88	)		—			(142,559	)
Development of oil and natural gas properties		—			(543,399	)		(17,598	)		—			(560,997	)
Investments in subsidiaries		(681,766	)		—			—			681,766			—
Other		—			(24,475	)		(315	)		—			(24,790	)

Net cash used in investing activities		(681,766	)		(710,345	)		(18,001	)		681,766			(728,346	)


Cash flows from financing activities:
Repurchase of common stock		(67,170	)		—			—			—			(67,170	)
Proceeds from long-term debt, net of issuance costs		1,127,029			—			243,310			—			1,370,339
Payments on long-term debt		(1,031,500	)		—			(141,000	)		—			(1,172,500	)
Net equity distributions		—			806,460			(124,694	)		(681,766	)		—
Other		24,668			(15,120	)		(74,773	)		—			(65,225	)

Net cash provided by (used in) financing activities		53,027			791,340			(97,157	)		(681,766	)		65,444


Increase (decrease) in cash and cash equivalents		606			(887	)		616			—			335
Cash and cash equivalents, beginning of period		1			1,700			3			—			1,704

Cash and cash equivalents, end of period	$	607		$	813		$	619		$	—		$	2,039

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2007
(in thousands)


				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(305,868	)	$	615,484		$	10,091		$	—		$	319,707


Cash flows from investing activities:
Proceeds from disposition of assets		—			287,928			—			—			287,928
Acquisition of oil and natural gas properties		—			(518,251	)		(330,294	)		—			(848,545	)
Development of oil and natural gas properties		—			(329,252	)		(6,645	)		—			(335,897	)
Investments in subsidiaries		(93,658	)		—			—			93,658			—
Other		—			(32,585	)		(457	)		—			(33,042	)

Net cash used in investing activities		(93,658	)		(592,160	)		(337,396	)		93,658			(929,556	)


Cash flows from financing activities:
Proceeds from issuance of ENP common units, net of issuance costs		—			—			193,461			—			193,461
Proceeds from long-term debt, net of issuance costs		1,208,501			—			270,758			—			1,479,259
Payments on long-term debt		(809,428	)		—			(225,000	)		—			(1,034,428	)
Net equity contributions		—			—			93,658			(93,658	)		—
Other		454			(22,387	)		(5,569	)		—			(27,502	)

Net cash provided by (used in) financing activities		399,527			(22,387	)		327,308			(93,658	)		610,790


Increase in cash and cash equivalents		1			937			3			—			941
Cash and cash equivalents, beginning of period		—			763			—			—			763

Cash and cash equivalents, end of period	$	1		$	1,700		$	3		$	—		$	1,704

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 17. ENP

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

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

Contribution, Conveyance and Assumption Agreement

At the closing of ENP’s IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:

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

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

These transfers and distributions were made in a series of steps outlined in the Contribution Agreement. In connection with the issuance of the common units by ENP in exchange for the Permian Basin assets, ENP’s IPO, and the exercise of the underwriters’ over-allotment option to purchase additional common units, GP LLC exchanged such number of common units for general partner units as was necessary to enable it to maintain its two percent general partner interest in ENP. GP LLC received the common units through capital contributions from EAC and its subsidiaries of common units they owned.

Administrative Services Agreement

ENP does not have any employees. The employees supporting ENP’s operations are employees of EAC. Accordingly, EAC recognizes all employee-related expenses and liabilities in its consolidated financial statements. Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to the Administrative Services Agreement. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by ENP. Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. Effective April 1, 2008, the administrative fee increased to $1.88 per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment. Encore Operating also charges ENP for reimbursement of actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the Administrative Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.

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

Purchase and Investment Agreement

In December 2007, OLLC entered into a purchase and investment agreement with Encore Operating pursuant to which OLLC agreed to acquire certain oil and natural gas properties and related assets in the Permian and Williston Basins from Encore Operating. The transaction closed in February 2008, but was effective as of January 1, 2008. The consideration for the acquisition consisted of approximately $125.3 million in cash, including post-closing adjustments, and 6,884,776 common units representing limited partner

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

interests in ENP. ENP funded the cash portion of the purchase price with borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale to reduce outstanding borrowings under the EAC Credit Agreement.

Long-Term Incentive Plan

In September 2007, GP LLC approved the ENP Plan, which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other equity-based awards, and unit awards. All employees, consultants, and directors of EAC, GP LLC, and any of their subsidiaries and affiliates who perform services for ENP and its subsidiaries and affiliates are eligible to be granted awards under the ENP Plan. The total number of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of December 31, 2008, there were 1,100,000 common units available for issuance under the ENP Plan. The ENP Plan is administered by the board of directors of GP LLC or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the ENP Plan, ENP may issue new common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.

Phantom Units. From time to time, ENP issues phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units; therefore, these phantom units are classified as equity instruments. Phantom units vest in four equal annual installments. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding. During 2008 and 2007, ENP recognized non-cash equity-based compensation expense for the phantom units of approximately $0.3 million and $31,000, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

The following table summarizes the changes in the number of ENP’s unvested phantom units and their related weighted average grant date fair value for 2008:


				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value

Outstanding at January 1, 2008		20,000		$	20.21
Granted		30,000			17.91
Vested		(6,250	)		19.93
Forfeited		—			—

Outstanding at December 31, 2008		43,750			18.67

During 2008 and 2007, ENP issued 30,000 and 20,000, respectively, phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan the vesting of which is dependent only on the passage of time and continuation as a board member. The following table illustrates by year of grant the vesting of outstanding phantom units at December 31, 2008:


	Year of Vesting
Year of Grant	2009		2010		2011		2012		Total
2007		5,000		5,000		5,000		—		15,000
2008		7,500		7,500		7,500		6,250		28,750

Total		12,500		12,500		12,500		6,250		43,750

As of December 31, 2008, ENP had $0.6 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 1.5 years. During 2008, there were 6,250 phantom units that vested, the total fair value of which was $0.1 million.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Management Incentive Units

In May 2007, the board of directors of GP LLC issued 550,000 management incentive units to certain executive officers of GP LLC. A management incentive unit is a limited partner interest in ENP that entitles the holder to quarterly distributions to the extent paid to ENP’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in ENP’s distribution rate to common unitholders. On November 14, 2008 the management incentive units became convertible into ENP common, at the option of the holder, units at a ratio of one management incentive unit to approximately 3.1186 ENP common units. During the fourth quarter of 2008, all 550,000 management incentive units were converted into 1,715,205 ENP common units.

The fair value of the management incentive units granted in 2007 was estimated on the date of grant using a discounted dividend model. During 2008 and 2007, ENP recognized total non-cash equity-based compensation expense for the management incentive units of $4.8 million and $6.8 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of December 31, 2008, there have been no additional issuances of management incentive units.

Distributions

During 2008 and 2007, ENP paid cash distributions to unitholders of $74.4 million and $1.3 million, respectively, of which $46.9 million and $0.8 million was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

Note 18. Segment Information

The following tables provides EAC’s operating segment information required by SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information” as well as the results of operations from oil and natural gas producing activities required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” As discussed in Note 2. Summary of Significant Accounting Policies-Recast of Consolidated Financial Statements and Notes to Consolidated Financial Statements, the financial information for all periods presented has been recast to include the financial position and results of operations of assets purchased by ENP from Encore Operating subsequent to December 31, 2008 in ENP’s financial information rather than in EAC Standalone’s financial information. The consolidated totals for all periods did not change from amounts previously presented.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


	For the Year Ended December 31, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	670,830		$	226,613		$	—		$	897,443
Natural gas		173,535			53,944			—			227,479
Marketing		5,172			5,324			—			10,496

Total revenues		849,537			285,881			—			1,135,418


Expenses:
Production:
Lease operating		130,363			44,752			—			175,115
Production, ad valorem, and severance taxes		82,497			28,147			—			110,644
Depletion, depreciation, and amortization		170,715			57,537			—			228,252
Impairment of long-lived assets		59,526			—			—			59,526
Exploration		39,011			196			—			39,207
General and administrative		36,082			16,605			(4,266	)		48,421
Marketing		4,104			5,466			—			9,570
Derivative fair value gain		(249,356	)		(96,880	)		—			(346,236	)
Provision for doubtful accounts		1,984			—			—			1,984
Other operating		11,305			1,670			—			12,975

Total expenses		286,231			57,493			(4,266	)		339,458


Operating income		563,306			228,388			4,266			795,960


Other income (expenses):
Interest		(66,204	)		(6,969	)		—			(73,173	)
Other		8,065			99			(4,266	)		3,898

Total other expenses		(58,139	)		(6,870	)		(4,266	)		(69,275	)


Income before income taxes		505,167			221,518			—			726,685
Income tax provision		(240,859	)		(762	)		—			(241,621	)

Consolidated net income		264,308			220,756			—			485,064
Amortization of deferred loss on commodity derivative contracts, net of tax		1,786			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		941			(4,258	)		—			(3,317	)

Comprehensive income	$	267,035		$	216,498		$	—		$	483,533


Costs incurred related to oil and natural gas properties	$	730,908		$	45,613		$	—		$	776,521


Segment assets (as of December 31, 2008)	$	2,823,778		$	813,313		$	(3,896	)	$	3,633,195


Segment liabilities (as of December 31, 2008)	$	1,961,453		$	193,962		$	(5,468	)	$	2,149,947

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


	For the Year Ended December 31, 2007
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	427,271		$	135,546		$	—		$	562,817
Natural gas		110,988			39,119			—			150,107
Marketing		33,439			8,582			—			42,021

Total revenues		571,698			183,247			—			754,945


Expenses:
Production:
Lease operating		109,446			33,980			—			143,426
Production, ad valorem, and severance taxes		56,873			17,712			—			74,585
Depletion, depreciation, and amortization		136,486			47,494			—			183,980
Exploration		27,600			126			—			27,726
General and administrative		25,923			15,245			(2,044	)		39,124
Marketing		33,876			6,673			—			40,549
Derivative fair value loss		86,182			26,301			—			112,483
Provision for doubtful accounts		5,816			—			—			5,816
Other operating		15,640			1,426			—			17,066

Total expenses		497,842			148,957			(2,044	)		644,755


Operating income		73,856			34,290			2,044			110,190


Other income (expenses):
Interest		(82,417	)		(12,702	)		6,415			(88,704	)
Other		10,930			196			(8,459	)		2,667

Total other expenses		(71,487	)		(12,506	)		(2,044	)		(86,037	)


Income before income taxes		2,369			21,784			—			24,153
Income tax provision		(14,398	)		(78	)		—			(14,476	)

Consolidated net income (loss)		(12,029	)		21,706			—			9,677
Amortization of deferred loss on commodity derivative contracts, net of tax		33,541			—			—			33,541

Comprehensive income	$	21,512		$	21,706		$	—		$	43,218


Costs incurred related to oil and natural gas properties	$	792,157		$	424,002		$	—		$	1,216,159


Segment assets (as of December 31, 2007)	$	2,038,707		$	749,144		$	(3,290	)	$	2,784,561


Segment liabilities (as of December 31, 2007)	$	1,611,503		$	109,078		$	(6,709	)	$	1,713,872

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued


	For the Year Ended December 31, 2006
	EAC								Consolidated
	Standalone			ENP			Eliminations		Total
	(in thousands)
Revenues:
Oil	$	306,074		$	40,900		$	—	$	346,974
Natural gas		105,864			40,461			—		146,325
Marketing		147,563			—			—		147,563

Total revenues		559,501			81,361			—		640,862


Expenses:
Production:
Lease operating		84,100			14,094			—		98,194
Production, ad valorem, and severance taxes		42,754			7,026			—		49,780
Depletion, depreciation, and amortization		98,766			14,697			—		113,463
Exploration		30,497			22			—		30,519
General and administrative		19,723			3,471			—		23,194
Marketing		148,571			—			—		148,571
Derivative fair value gain		(24,388	)		—			—		(24,388	)
Provision for doubtful accounts		1,970			—			—		1,970
Other operating		6,735			1,318			—		8,053

Total expenses		408,728			40,628			—		449,356


Operating income		150,773			40,733			—		191,506


Other income (expenses):
Interest		(45,131	)		—			—		(45,131	)
Other		1,429			—			—		1,429

Total other expenses		(43,702	)		—			—		(43,702	)


Income before income taxes		107,071			40,733			—		147,804
Income tax provision		(55,146	)		(260	)		—		(55,406	)

Consolidated net income		51,925			40,473			—		92,398
Amortization of deferred loss on commodity derivative contracts, net of tax		37,499			—			—		37,499

Comprehensive income	$	89,424		$	40,473		$	—	$	129,897


Costs incurred related to oil and natural gas properties	$	369,223		$	9,346		$	—	$	378,569

Note 19. Impairment of Long-Lived Assets

During 2008, circumstances indicated that the carrying amounts of certain oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, may not be recoverable. EAC compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated the need for an impairment charge. EAC then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a pretax write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices EAC might receive for these volumes, discounted to a present value. EAC’s estimates of undiscounted cash flows indicated that the remaining carrying amounts of its oil and natural gas properties are expected to be recovered. Nonetheless, if oil and natural gas prices decline, it is reasonably possible that EAC’s estimates of undiscounted cash flows may change in the near term resulting in the need to record an additional write down of oil and natural gas properties to fair value.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 20. Subsequent Events

Commodity Derivative Contracts

Subsequent to December 31, 2008, EAC entered into additional commodity derivative contracts. The following tables summarize EAC’s open commodity derivative contracts as of February 18, 2009:

Oil Derivative Contracts


	Average		Weighted		Average			Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily			Average		Daily		Average		Daily		Average
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)
Feb. - Dec. 2009
		11,630	$	110.00		—		$	—		440	$	97.75		2,000	$	90.46
		8,000		80.00		—			—		—		—		500		89.39
		—		—		—			—		—		—		1,000		68.70
		—		—		(5,000	)		50.00		—		—		—		—
2010
		880		80.00		—			—		440		93.80		—		—
		2,000		75.00		—			—		1,500		75.48		—		—
		3,000		60.00		—			—		500		65.60		—		—
		1,000		56.00		—			—		—		—		2,000		60.48
2011
		1,880		80.00		—			—		1,440		95.41		—		—
		1,000		70.00		—			—		—		—		—		—

Natural Gas Derivative Contracts


	Average		Weighted		Average	Weighted	Average		Weighted		Average		Weighted
	Daily		Average		Daily	Average	Daily		Average		Daily		Average
	Floor		Floor		Short Floor	Short Floor	Cap		Cap		Swap		Swap
Period	Volume		Price		Volume	Price	Volume		Price		Volume		Price
	(Mcf)		(per Mcf)		(Mcf)	(per Mcf)	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)
Feb 2009 - Dec 2009
		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
		3,800		8.20	—	—		3,800		9.58		—		—
		4,698		7.26	—	—		—		—		902		6.30
2011
		898		6.76	—	—		—		—		902		6.70
2012
		898		6.76	—	—		—		—		902		6.66

As of February 18, 2009, EAC’s total deferred commodity derivative premiums were $58.4 million, $15.7 million, and $0.9 million for the remainder of 2009, 2010, and, 2011, respectively.

Purchase and Sale Agreement

On December 5, 2008, EAC entered into a purchase and sale agreement, with OLLC, pursuant to which OLLC acquired certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres from EAC. The transaction closed on January 2, 2009, but was effective as of November 1, 2008. The

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

purchase price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million), which OLLC financed through borrowings under the OLLC Credit Agreement.

Other Events

Subsequent to December 31, 2008, EAC granted 269,417 stock options and 378,537 shares of restricted stock to employees as part of its annual incentive program and 144,695 stock options and 376,717 shares of restricted stock vested. Subsequent to December 31, 2008, it was determined that the performance measures related to certain awards granted in 2008 were met and therefore, vesting now depends only on the passage of time and continued employment.

On January 26, 2009, ENP announced a distribution for the fourth quarter of 2008 to unitholders of record as of the close of business on February 6, 2009 at a rate of $0.50 per unit. Approximately $16.8 million was paid on February 13, 2009, $10.7 million of which was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION

Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities

The capitalized cost of oil and natural gas properties was as follows as of the dates indicated:


	December 31,
	2008			2007
	(in thousands)
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment	$	3,538,459		$	2,845,776
Unproved properties		124,339			63,352
Accumulated depletion, depreciation, and amortization		(771,564	)		(489,004	)

	$	2,891,234		$	2,420,124

The following table summarizes costs incurred related to oil and natural gas properties for the periods indicated:


	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Acquisitions:
Proved properties	$	28,729	$	787,988	$	4,486
Unproved properties		128,635		52,306		24,462
Asset retirement obligations		111		8,251		785

Total acquisitions		157,475		848,545		29,733


Development:
Drilling and exploitation		362,111		270,016		253,484
Asset retirement obligations		498		145		147

Total development		362,609		270,161		253,631


Exploration:
Drilling and exploitation		252,104		95,221		92,839
Geological and seismic		2,851		1,456		1,720
Delay rentals		1,482		776		646

Total exploration		256,437		97,453		95,205


Total costs incurred	$	776,521	$	1,216,159	$	378,569

Oil & Natural Gas Producing Activities — Unaudited

The estimates of EAC’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the SEC and the FASB. Proved oil and natural gas reserve quantities are derived from estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with SEC guidelines, estimates of future net cash flows from EAC’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Year-end prices used in estimating net cash flows were as follows as of the dates indicated:


	December 31,
	2008		2007		2006

Oil (per Bbl)	$	44.60	$	96.01	$	61.06
Natural gas (per Mcf)	$	5.62	$	7.47	$	5.48

ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION — (Continued)

EAC’s reserve and production quantities from its CCA properties have been reduced by the amounts attributable to the net profits interest. The net profits interest on EAC’s CCA properties has also been deducted from future cash inflows in the calculation of Standardized Measure. In addition, net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. The future net cash flows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes. Future income taxes are based on statutory income tax rates in effect at year-end, EAC’s tax basis in its proved oil and natural gas properties, and the effect of NOL carryforwards and AMT credits.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and natural gas properties and the calculation of DD&A on these properties.

EAC’s estimated net quantities of proved oil and natural gas reserves were as follows as of the dates indicated:


	December 31,
	2008		2007		2006

Proved reserves:
Oil (MBbl)		134,452		188,587		153,434
Natural gas (MMcf)		307,520		256,447		306,764
Combined (MBOE)		185,705		231,328		204,561
Proved developed reserves:
Oil (MBbl)		110,014		125,213		94,246
Natural gas (MMcf)		232,715		191,072		235,049
Combined (MBOE)		148,800		157,058		133,421

ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION — (Continued)

The changes in EAC’s proved reserves were as follows for the periods indicated:


				Natural			Oil
	Oil			Gas			Equivalent
	(MBbl)			(MMcf)			(MBOE)
Balance, December 31, 2005		148,387			283,865			195,698
Purchases of minerals-in-place		25			235			64
Extensions and discoveries		3,269			78,861			16,412
Improved recovery		10,935			941			11,092
Revisions of previous estimates		(1,847	)		(33,682	)		(7,461	)
Production		(7,335	)		(23,456	)		(11,244	)

Balance, December 31, 2006		153,434			306,764			204,561
Purchases of minerals-in-place		40,534			15,667			43,146
Sales of minerals-in-place		(1,845	)		(107,249	)		(19,719	)
Extensions and discoveries		4,362			65,639			15,302
Improved recovery		666			90			681
Revisions of previous estimates		981			(501	)		896
Production		(9,545	)		(23,963	)		(13,539	)

Balance, December 31, 2007		188,587			256,447			231,328
Purchases of minerals-in-place		266			6,220			1,303
Extensions and discoveries		7,411			73,527			19,665
Improved recovery		287			—			287
Revisions of previous estimates		(52,049	)		(2,300	)		(52,432	)
Production		(10,050	)		(26,374	)		(14,446	)

Balance, December 31, 2008 (a)		134,452			307,520			185,705


(a)		Includes reserves of 27.3 MMBbls of oil and 78.0 Bcf of natural gas (40.3 MMBOE) attributable to ENP in which there was a 36 percent noncontrolling interest as of December 31, 2008.

EAC’s Standardized Measure of discounted estimated future net cash flows was as follows as of the dates indicated:


	December 31,
	2008			2007			2006
	(in thousands)
Future cash inflows	$	6,754,431		$	17,394,468		$	9,291,007
Future production costs		(3,082,814	)		(5,721,804	)		(3,668,897	)
Future development costs		(497,197	)		(469,034	)		(371,396	)
Future abandonment costs, net of salvage		(96,480	)		(75,172	)		(134,103	)
Future income tax expense		(555,370	)		(3,236,356	)		(1,499,290	)

Future net cash flows		2,522,570			7,892,102			3,617,321
10% annual discount		(1,302,616	)		(4,600,393	)		(2,155,514	)

Standardized measure of discounted estimated future net cash flows (a)	$	1,219,954		$	3,291,709		$	1,461,807


(a)		Includes $326.6 million attributable to ENP in which there was a 36 percent noncontrolling interest as of December 31, 2008.

ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION — (Continued)

The changes in EAC’s Standardized Measure of discounted estimated future net cash flows were as follows for the periods indicated:


	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Net change in prices and production costs	$	(2,848,387	)	$	1,718,818		$	(634,033	)
Purchases of minerals-in-place		14,155			1,249,008			539
Sales of minerals-in-place		—			(300,727	)		—
Extensions, discoveries, and improved recovery		171,509			282,163			141,211
Revisions of previous quantity estimates		(474,926	)		21,887			(62,615	)
Production, net of production costs		(321,935	)		(710,134	)		(340,036	)
Development costs incurred during the period		148,569			270,016			253,484
Accretion of discount		329,171			146,181			191,847
Change in estimated future development costs		(176,732	)		(235,005	)		(185,212	)
Net change in income taxes		991,368			(672,807	)		248,491
Change in timing and other		95,453			60,502			(70,340	)

Net change in standardized measure		(2,071,755	)		1,829,902			(456,664	)
Standardized measure, beginning of year		3,291,709			1,461,807			1,918,471

Standardized measure, end of year	$	1,219,954		$	3,291,709		$	1,461,807

Selected Quarterly Financial Data — Unaudited

The following table provides selected quarterly financial data for the periods indicated:


	Quarter
	First			Second			Third		Fourth
	(in thousands, except per share data)
2008
Revenues	$	272,902		$	357,334		$	337,478	$	167,704
Operating income (loss)	$	68,956		$	(55,925	)	$	375,148	$	407,781
Net income (loss) attributable to EAC stockholders	$	31,220		$	(35,720	)	$	206,307	$	229,005
Net income (loss) per common share:
Basic	$	0.58		$	(0.68	)	$	3.88	$	4.35
Diluted	$	0.58		$	(0.68	)	$	3.77	$	4.32

2007
Revenues	$	130,542		$	189,643		$	195,016	$	239,744
Operating income (loss)	$	(29,592	)	$	50,914		$	41,059	$	47,809
Net income (loss) attributable to EAC stockholders	$	(29,429	)	$	15,171		$	11,985	$	19,428
Net income (loss) per common share:
Basic	$	(0.55	)	$	0.28		$	0.22	$	0.36
Diluted	$	(0.55	)	$	0.28		$	0.22	$	0.36

As discussed in “Note 2. Summary of Significant Accounting Policies” and “Note 10. Earnings Per Share,” EAC adopted FSP EITF 03-6-1 on January 1, 2009 and all periods presented have been restated to calculate EPS in accordance therewith.


	ENCORE ACQUISITION COMPANY
Date: January 25, 2010	By:	/s/ Andrea Hunter
		Andrea Hunter
		Vice President, Controller, and Principal Accounting Officer


Exhibit No.		Description

99.1		Selected Financial Data.

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

99.3		Financial Statements and Supplementary Data.


	Page

Report of Independent Registered Public Accounting Firm		1
Consolidated Balance Sheets as of December 31, 2008 and 2007		2
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007, and 2006		3
Consolidated Statements of Equity and Comprehensive Income for the Years Ended December 31, 2008, 2007, and 2006		4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007, and 2006		5
Notes to Consolidated Financial Statements		6
Supplementary Information		48