Encore Acquisition 8-K Other Events

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

1

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.

2