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.

     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.

     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

     In the first quarter of 2009, we expect our LOE to average $12.75 to $13.25 per BOE, including approximately $2.5 million ($0.68 per BOE) for retention bonuses related to the strategic alternatives process to be paid in August 2009. We expect our production taxes to average approximately 9.5 percent of wellhead revenues in the first quarter of 2009. In the first quarter of 2009, we expect our depletion, depreciation, and amortization (“DD&A”) expense to average $18.00 to $18.50 per BOE. In the first quarter of 2009, we expect our G&A expense to average $3.50 to $4.00 per BOE, including approximately $1.7 million ($0.46 per BOE) for retention bonuses related to the strategic alternatives process to be paid in August 2009.

     During the first quarter of 2009, we expect our effective tax rate to be approximately 38 percent, 95 percent of which is expected to be deferred.

     We do not expect to reduce our total debt levels during the first quarter of 2009.

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

     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:

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.

     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,
		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

     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	%

     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 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.