Encore Energy Partners 8K | SEC 7 May 09

Exhibit 99.2

ENCORE ENERGY PARTNERS LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In January 2009, we acquired certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interests in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”) from Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of Encore Acquisition Company (“EAC”). Because the Arkoma Basin Assets were acquired from an affiliate, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities were recorded at Encore Operating’s historical cost, and our historical financial information was recast to include the results of operations of the Arkoma Basin Assets for all periods presented. Our recast historical financial information presents the Arkoma Basin Assets as if they were owned by us for all periods owned by Encore Operating. Accordingly, the following discussion and analysis has been recast from that presented in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2008 Annual Report on Form 10-K (the “2008 Annual Report”) filed with the United States Securities and Exchange Commission on February 26, 2009.

The following recast discussion and analysis of our consolidated financial position and results of operations should be read in conjunction with our recast consolidated financial statements as of December 31, 2008 and 2007 and for the years ended December 31, 2008, 2007, and 2006 (collectively, the “Recast Financial Statements”) and notes, and supplementary data thereto included as Exhibit 99.3 to our Current Report on Form 8-K that includes this recast discussion and analysis. 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 these 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. You are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the headings: “Cautionary Statement Regarding Forward-Looking Statements” included in our Current Report on Form 8-K that includes this recast discussion and analysis 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 Events

	•		2009 Events and 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

Overview of Business

We are a Delaware limited partnership formed in February 2007 by EAC to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Our primary business objective is to make quarterly cash distributions to our unitholders at our current distribution rate and, over time, increase our quarterly cash distributions.

In September 2007, we completed our initial public offering (the “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 option to purchase an additional 1,148,400 common units. Net proceeds from the issuance of common units, including the underwriters’ over-allotment option, were 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. The net proceeds were used to repay in full $126.4 million of outstanding indebtedness under a subordinated credit agreement with EAP Operating, LLC, a wholly owned subsidiary of EAC, and reduce outstanding indebtedness under our revolving credit facility.

ENCORE ENERGY PARTNERS LP

Upon the closing of our IPO, Encore Operating contributed to us certain oil and natural gas properties and related assets in the Permian Basin located in Crockett County, Texas (the “Permian Basin Assets”). The Permian Basin Assets are considered our predecessor, and therefore, our historical results of operations include the results of operations of the Permian Basin Assets for all periods presented. In March 2007, we acquired certain oil and natural gas properties and related assets in the Elk Basin in Wyoming and Montana (the “Elk Basin Assets”) from a third party. The results of operations of the Elk Basin Assets have been included with ours from the date of acquisition forward.

In February 2008, we acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating. In January 2009, we acquired the Arkoma Basin Assets from Encore Operating. Because these assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities were recorded at Encore Operating’s historical cost and our historical financial information was recast to include the acquired properties for all periods presented. Accordingly, our consolidated financial statements reflect our historical results combined with those of the Permian Basin Assets, the Permian and Williston Basin Assets, and the Arkoma Basin Assets for all periods presented.

At December 31, 2008, our oil and natural gas properties had estimated total proved reserves of 16.9 MMBbls of oil and 64.8 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 27.6 MMBOE at December 31, 2008, of which approximately 61 percent was oil and approximately 89 percent was proved developed. Based on 2008 production, our ratio of reserves to production was approximately 11.1 years for total proved reserves and 9.9 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. Our oil wellhead differentials to NYMEX improved in 2008 as we realized 89 percent of the average NYMEX oil price, as compared to 82 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 94 percent of the average NYMEX natural gas price in 2008, as compared to 98 percent in 2007. Commodity prices are influenced by many factors that are outside 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.

2008 Events

In February 2008, we acquired the Permian and Williston Basin Assets from Encore Operating in exchange for approximately $125.3 million in cash and 6,884,776 common units representing limited partner interests in us. In determining the total purchase price, the common units were valued at $125 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties.

In May 2008, we acquired an existing net profits interest in certain of our properties in the Permian Basin in West Texas in exchange for 283,700 common units representing limited partner interests in us, which were valued at approximately $5.8 million at the time of the acquisition.

2009 Events and Outlook

For 2009, the board of directors of our general partner has approved a $7.4 million capital budget for oil and natural gas related activities, all of which is for development and exploitation. We expect to fund our 2009 capital expenditures with cash flow from operations.

The prices we receive for 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

ENCORE ENERGY PARTNERS LP

inventory of capital projects based on management’s outlook of future commodity prices. If NYMEX prices continue to trend downward, we may further reevaluate our capital projects. 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. Moreover, EAC is not prohibited from competing with us and constantly evaluates acquisitions and dispositions that do not involve us.

ENCORE ENERGY PARTNERS LP

Results of Operations

Comparison of 2008 to 2007

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


	Year Ended December 31,				*Increase / (Decrease)*
	2008		2007		$			%
Revenues (in thousands):
Oil	$	149,184	$	86,319	$	62,865			73	%
Natural gas		41,955		30,086		11,869			39	%

Total oil and natural gas revenues		191,139		116,405		74,734			64	%
Marketing		5,324		8,582		(3,258	)		-38	%

Total revenues	$	196,463	$	124,987	$	71,476			57	%


Averaged realized prices:
Oil ($/Bbl)	$	89.27	$	59.38	$	29.89			50	%
Natural gas ($/Mcf)	$	8.54	$	6.74	$	1.80			27	%
Combined ($/BOE)	$	76.78	$	52.96	$	23.82			45	%

Total production volumes:
Oil (MBbls)		1,671		1,454		217			15	%
Natural gas (MMcf)		4,910		4,466		444			10	%
Combined (MBOE)		2,490		2,198		292			13	%

Average daily production volumes:
Oil (Bbls/D)		4,566		4,629		(63	)		-1	%
Natural gas (Mcf/D)		13,416		12,413		1,003			8	%
Combined (BOE/D)		6,802		6,698		104			2	%

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 73 percent from $86.3 million in 2007 to $149.2 million in 2008 as a result of higher average realized oil prices, which increased oil revenues by approximately $50.0 million, and higher oil production volumes of 217 MBbls, which increased oil revenues by approximately $12.9 million. Our average realized oil price increased $29.89 per Bbl from 2007 to 2008 primarily as a result of the increase in the average NYMEX price from $72.45 per Bbl for 2007 to $99.75 per Bbl for 2008. The increase in oil production volumes was primarily due to a full year of production from our Elk Basin Assets, which were acquired in March 2007. For 2008, approximately 74 percent of our oil production was from our Elk Basin Assets.

Natural gas revenues increased 39 percent from $30.1 million in 2007 to $42.0 million in 2008 as a result of higher average realized natural gas prices, which increased natural gas revenues by approximately $8.9 million, and higher natural gas production volumes of 444 MMcf, which increased natural gas revenues by approximately $3.0 million. Our average realized natural gas price increased $1.80 per Mcf from 2007 to 2008 primarily as a result of the increase in the average NYMEX price from $6.86 per Mcf for 2007 to $9.04 per Mcf for 2008. The increase in natural gas production volumes was primarily due to wells drilled in the Permian Basin during the second half of 2007 and the first half of 2008.

Marketing revenues decreased 38 percent from $8.6 million in 2007 to $5.3 million in 2008 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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

ENCORE ENERGY PARTNERS LP


	Year Ended December 31,
	2008			2007
Average realized oil price ($/Bbl)	$	89.27		$	59.38
Average NYMEX ($/Bbl)	$	99.75		$	72.45
Differential to NYMEX	$	(10.48	)	$	(13.07	)
Average realized oil price to NYMEX percentage		89	%		82	%

Average realized natural gas price ($/Mcf)	$	8.54		$	6.74
Average NYMEX ($/Mcf)	$	9.04		$	6.86
Differential to NYMEX	$	(0.50	)	$	(0.12	)
Average realized natural gas price to NYMEX percentage		94	%		98	%

Our average realized oil price as a percentage of the average NYMEX price improved to 89 percent for 2008 from 82 percent for 2007 as a result of improved pricing in the Rocky Mountain area. Our average realized natural gas price as a percentage of the average NYMEX price deteriorated slightly to 94 percent for 2008 from 98 percent for 2007.

ENCORE ENERGY PARTNERS LP

Expenses.The following table summarizes our expenses for the periods indicated:


	Year Ended December 31,					*Increase / (Decrease)*
	2008			2007		$			%
Expenses (in thousands):
Production:
Lease operating	$	28,863		$	21,684	$	7,179
Production, ad valorem, and severance taxes		19,218			11,972		7,246

Total production expenses		48,081			33,656		14,425			43	%
Other:
Depletion, depreciation, and amortization		39,269			33,900		5,369
Exploration		194			124		70
General and administrative		12,774			12,698		76
Marketing		5,466			6,673		(1,207	)
Derivative fair value loss (gain)		(96,880	)		26,301		(123,181	)
Other operating		1,489			1,249		240

Total operating		10,393			114,601		(104,208	)		-91	%
Interest		6,969			12,702		(5,733	)
Income tax provision		618			78		540

Total expenses	$	17,980		$	127,381	$	(109,401	)		-86	%


Expenses (per BOE):
Production:
Lease operating	$	11.59		$	9.87	$	1.72
Production, ad valorem, and severance taxes		7.72			5.45		2.27

Total production expenses		19.31			15.32		3.99			26	%
Other:
Depletion, depreciation, and amortization		15.77			15.42		0.35
Exploration		0.08			0.06		0.02
General and administrative		5.13			5.78		(0.65	)
Marketing		2.20			3.04		(0.84	)
Derivative fair value loss (gain)		(38.91	)		11.97		(50.88	)
Other operating		0.60			0.57		0.03

Total operating		4.18			52.16		(47.98	)		-92	%
Interest		2.80			5.78		(2.98	)
Income tax provision		0.25			0.04		0.21

Total expenses	$	7.23		$	57.98	$	(50.75	)		-88	%

Production expenses.Total production expenses increased 43 percent from $33.7 million in 2007 to $48.1 million in 2008 as a result of higher production volumes and an increase in the per BOE rate. Our production margin (defined as oil and natural gas wellhead revenues less production expenses) increased by $60.3 million (73 percent) to $143.1 million for 2008 as compared to $82.7 million for 2007. On a per BOE basis, our production margin increased 53 percent to $57.47 per BOE for 2008 as compared to $37.64 per BOE for 2007. Total oil and natural gas revenues per BOE increased by 45 percent while total production expenses per BOE increased by 26 percent.

Production expense attributable to LOE increased $7.2 million from $21.7 million in 2007 to $28.9 million in 2008 as a result of a $1.72 increase in the average per BOE rate, which contributed approximately $4.3 million of additional LOE, and an increase in production volumes, which contributed approximately $2.9 million of additional LOE. The increase in our average LOE per BOE rate was primarily due to the increase in natural gas prices and increases in prices paid to oilfield service companies and suppliers. In West Texas, the higher gas prices increased the electrical rates charged to our producing properties, and at the Elk Basin gas plant, the charges associated with the fuel gas were also higher.

Production expense attributable to production taxes increased $7.2 million from $12.0 million in 2007 to $19.2 million in 2008 primarily due to higher wellhead revenues. As a percentage of oil and natural gas revenues, production taxes remained approximately constant at 10.1 percent for 2008 as compared to 10.3 percent in 2007.

ENCORE ENERGY PARTNERS LP

DD&A expense.DD&A expense increased $5.4 million from $33.9 million in 2007 to $39.3 million in 2008 as a result of higher production volumes, which contributed approximately $4.5 million of additional DD&A expense, and an increase in the per BOE rate of $0.35, which contributed approximately $0.9 million of additional DD&A expense. The increase in our average DD&A per BOE rate was primarily due to higher costs incurred resulting from increases in rig rate, pipe costs, and acquisition costs, and the decrease in our total proved reserves to 27.6 MMBOE as of December 31, 2008 as compared to 33.1 MMBOE as of December 31, 2007.

G&A expense.G&A expense remained approximately constant at $12.8 million in 2008 as compared to $12.7 million in 2007.

Marketing expense.Marketing expense decreased $1.2 million from $6.7 million in 2007 to $5.5 million in 2008 as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

Derivative fair value loss (gain).During 2008, we recorded a $96.9 million derivative fair value gain as compared to a $26.3 million loss in 2007, the components of which were as follows:


	Year Ended December 31,						*Increase /*
	2008			2007			*(Decrease)*
	(in thousands)
Ineffectiveness	$	372		$	—		$	372
Mark-to-market loss (gain)		(101,595	)		23,470			(125,065	)
Premium amortization		8,936			4,073			4,863
Settlements		(4,593	)		(1,242	)		(3,351	)

Total derivative fair value loss (gain)	$	(96,880	)	$	26,301		$	(123,181	)

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.

Interest expense.Interest expense decreased $5.7 million from $12.7 million in 2007 to $7.0 million in 2008, primarily due to (1) the use of net proceeds from our IPO to reduce weighted average outstanding borrowings on our revolving credit facility and subordinated credit agreement, (2) a reduction in LIBOR, and (3) our use of interest rate swaps to fix the rate on a portion of outstanding borrowings on our revolving credit facility. The weighted average interest rate for 2008 was 4.8 percent as compared to 8.9 percent for 2007.

ENCORE ENERGY PARTNERS LP

Comparison of 2007 to 2006

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


	Year Ended December 31,				*Increase / (Decrease)*
	2007		2006		$			%
Revenues (in thousands):
Oil	$	86,319	$	18,952	$	67,367			355	%
Natural gas		30,086		30,374		(288	)		-1	%

Total oil and natural gas revenues		116,405		49,326		67,079			136	%
Marketing		8,582		—		8,582			—

Total revenues	$	124,987	$	49,326	$	75,661			153	%


Averaged realized prices:
Oil ($/Bbl)	$	59.38	$	60.96	$	(1.58	)		-3	%
Natural gas ($/Mcf)	$	6.74	$	6.72	$	0.02			0	%
Combined ($/BOE)	$	52.96	$	46.37	$	6.59			14	%

Total production volumes:
Oil (MBbls)		1,454		311		1,143			368	%
Natural gas (MMcf)		4,466		4,517		(51	)		-1	%
Combined (MBOE)		2,198		1,064		1,134			107	%

Average daily production volumes:
Oil (Bbl/D)		4,629		852		3,777			443	%
Natural gas (Mcf/D)		12,413		12,377		36			0	%
Combined (BOE/D)		6,698		2,915		3,783			130	%

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 355 percent from $19.0 million in 2006 to $86.3 million in 2007 due to an increase in oil production volumes of 1,143 MBbls, which contributed approximately $69.6 million in additional oil revenues, partially offset by lower average realized oil prices, which negatively impacted oil revenues by approximately $2.2 million. The increase in oil production volumes was primarily due to our acquisition of the Elk Basin Assets in March 2007. Despite higher average NYMEX crude oil prices in 2007 compared to 2006, our average realized oil price decreased $1.58 per Bbl in 2007 as compared to 2006. Differentials for oil production from our Elk Basin Assets were wider than oil differentials from our properties located in the Permian Basin in West Texas and the Williston Basin in North Dakota. In 2007, approximately 72 percent of our oil production was from our Elk Basin Assets, which sells at a higher discount to NYMEX due to the quality of the crude oil, which is a heavy, sour crude, as well as its location relative to markets in the Rocky Mountains.

Natural gas revenues decreased one percent from $30.4 million in 2006 to $30.1 million in 2007 primarily due to a decrease in production volumes of 51 MMcf.

In March 2007, we acquired the Clearfork crude oil pipeline and the Wildhorse natural gas pipeline as part of the Elk Basin acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets. In addition, we collect pipeline tariffs for transportation through our Clearfork crude oil pipeline. We had no marketing revenues in 2006.

ENCORE ENERGY PARTNERS LP


	Year Ended December 31,
	2007			2006
Average realized oil price ($/Bbl)	$	59.38		$	60.96
Average NYMEX ($/Bbl)	$	72.45		$	66.26
Differential to NYMEX	$	(13.07	)	$	(5.30	)
Average realized oil price to NYMEX percentage		82	%		92	%

Average realized natural gas price ($/Mcf)	$	6.74		$	6.72
Average NYMEX ($/Mcf)	$	6.86		$	7.17
Differential to NYMEX	$	(0.12	)	$	(0.45	)
Average realized natural gas price to NYMEX percentage		98	%		94	%

In 2007, our average realized oil price as a percentage of the average NYMEX price decreased to 82 percent from 92 percent in 2006. The differential widened due to our Elk Basin acquisition, as approximately 72 percent of our oil production in 2007 was from our Elk Basin Assets. The oil production from our Elk Basin Assets sells at a larger discount to NYMEX as compared to our properties located in the Permian Basin in West Texas and the Williston Basin in North Dakota due to continued production increases from competing Canadian and Rocky Mountain producers, limited refining and pipeline capacity in the Rocky Mountain area, corresponding steep pricing discounts by regional refiners, and the quality of the Elk Basin oil.

Our average realized natural gas price as a percentage of the average NYMEX price improved to 98 percent in 2007 as compared to 94 percent in 2006.

ENCORE ENERGY PARTNERS LP

Expenses.The following table summarizes our expenses for the periods indicated:


	Year Ended December 31,				*Increase / (Decrease)*
	2007		2006		$			%
Expenses (in thousands):
Production:
Lease operating	$	21,684	$	7,058	$	14,626
Production, ad valorem, and severance taxes		11,972		4,068		7,904

Total production expenses		33,656		11,126		22,530			202	%
Other:
Depletion, depreciation, and amortization		33,900		6,819		27,081
Exploration		124		22		102
General and administrative		12,698		2,195		10,503
Marketing		6,673		—		6,673
Derivative fair value loss		26,301		—		26,301
Other operating		1,249		682		567

Total operating		114,601		20,844		93,757			450	%
Interest		12,702		—		12,702
Income tax provision		78		260		(182	)

Total expenses	$	127,381	$	21,104	$	106,277			504	%


Expenses (per BOE):
Production:
Lease operating	$	9.87	$	6.63	$	3.24
Production, ad valorem, and severance taxes		5.45		3.82		1.63

Total production expenses		15.32		10.45		4.87			47	%
Other:
Depletion, depreciation, and amortization		15.42		6.41		9.01
Exploration		0.06		0.02		0.04
General and administrative		5.78		2.06		3.72
Marketing		3.04		—		3.04
Derivative fair value loss		11.97		—		11.97
Other operating		0.57		0.64		(0.07	)

Total operating		52.16		19.58		32.58			166	%
Interest		5.78		—		5.78
Income tax provision		0.04		0.24		(0.20	)

Total expenses	$	57.98	$	19.82	$	38.16			193	%

Production expenses.Total production expenses increased 202 percent from $11.1 million in 2006 to $33.7 million in 2007 due to higher production volumes, primarily associated with our Elk Basin acquisition, and a $4.87 increase in production expenses per BOE. Our production margin in 2007 increased by $44.5 million (117 percent) to $82.7 million as compared to $38.2 million in 2006. On a per BOE basis, our production margin increased 5 percent to $37.64 per BOE as compared to $35.92 per BOE in 2006. Total production expenses per BOE increased by 47 percent while total oil and natural gas revenues per BOE increased by 14 percent.

Production expense attributable to LOE increased $14.6 million from $7.1 million in 2006 to $21.7 million in 2007, primarily due to higher total production volumes, which contributed approximately $7.5 million of additional LOE, and a $3.24 increase in the per BOE rate, which contributed approximately $7.1 million of additional LOE. The increase in our average LOE per BOE rate was attributable to higher operating costs for the Elk Basin Assets as compared to our other properties, as well as a general increase in industry costs.

Production expense attributable to production taxes increased $7.9 million from $4.1 million in 2006 to $12.0 million in 2007 due to higher wellhead revenues. As a percentage of oil and natural gas revenues, production taxes increased to 10.3 percent in 2007 as compared to 8.2 percent in 2006, primarily due to higher tax rates in the Elk Basin region as compared to our Permian and Williston Basin properties.

ENCORE ENERGY PARTNERS LP

DD&A expense.DD&A expense increased $27.1 million from $6.8 million in 2006 to $33.9 million in 2007 due to an increase in the per BOE rate of $9.01 and higher production volumes resulting from our Elk Basin acquisition. The increase in the per BOE rate was due to the higher acquisition price of proved reserves in the Elk Basin as compared to our other properties.

G&A expense.G&A expense increased $10.5 million from $2.2 million in 2006 to $12.7 million in 2007 primarily due to $6.8 million of non-cash compensation expense recognized for management incentive units, $3.3 million of administrative fees incurred pursuant to the administrative services agreement with Encore Operating, and increased expenses associated with being a publicly traded partnership. In 2007, administrative fees were paid to Encore Operating at a rate of $1.75 per BOE of our production. Prior to the purchase of the Elk Basin Assets in March 2007, no administrative services were performed for us by Encore Operating.

Marketing expense.In March 2007, we acquired the Clearfork crude oil pipeline and the Wildhorse natural gas pipeline as part of the Elk Basin acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets. We had no marketing expenses in 2006.

Derivative fair value loss.During 2007, we recorded a $26.3 million derivative fair value loss, of which $23.5 million related to mark-to-market losses and $4.1 million related to premium amortization, offset by $1.2 million of cash receipts related to settlements on our commodity derivative contracts. There were no such derivative instruments in place during 2006.

Other operating expense.Other operating expense increased $0.6 million from $0.7 million in 2006 to $1.2 million in 2007 primarily due to higher transportation expenses for our increased oil production.

Interest expense.Interest expense was $12.7 million in 2007, of which $5.9 million related to our revolving credit facility and $6.8 million related to our subordinated credit agreement. We had no interest expense in 2006. The weighted average interest rate for 2007 was 8.9 percent.

Capital Commitments, Capital Resources, and Liquidity

Capital commitments.Our primary needs for cash are:

	•		Distributions to unitholders;

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

	•		Acquisitions of oil and natural gas properties;

	•		Funding of working capital; and

	•		Contractual obligations.

Distributions to unitholders.Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in the partnership agreement). Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs. During 2008, we distributed $74.4 million to our unitholders.

In May 2008, the board of directors of our general partner approved a new distribution methodology, which returns additional cash flow to our unitholders during high commodity price environments. As a general guideline, we plan to distribute to unitholders 50 percent of the excess distributable cash flow above: (1) maintenance capital requirements; (2) an implied minimum quarterly distribution of $0.4325 per unit, or $1.73 per unit annually; and (3) a minimum coverage ratio of 1.10. We may move excess cash flow to previous quarters or defer excess cash flows to future quarters. There can be no assurance that we will be able to distribute $0.4325 on a quarterly basis or achieve a minimum coverage ratio of 1.10.

On January 26, 2009, we announced a cash distribution with respect to the fourth quarter of 2008 to unitholders of record as of the close of business on February 6, 2009. The $16.8 million total distribution was paid on February 13, 2009 to unitholders at a rate of $0.50 per unit. On April 27, 2009, we announced a cash distribution for the first quarter of 2009 to unitholders of record as of the close of business on May 11, 2009 at a rate of $0.50 per unit. Approximately $16.8 million is expected to be paid to unitholders on or about May 15, 2009.

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:

ENCORE ENERGY PARTNERS LP


	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Development and exploitation	$	15,034	$	18,637	$	5,433
Exploration		2,391		3,500		39

Total	$	17,425	$	22,137	$	5,472

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 44 gross (11.3 net) successful wells and no 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 one 9 gross (0.3 net) successful wells and one dry hole.

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	$	5,827	$	353,987	$	341
Acquisitions of leasehold acreage		—		105		103

Total	$	5,827	$	354,092	$	444

In January 2009, we acquired the Arkoma Basin Assets from Encore Operating for $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). In May 2008, we acquired an existing net profits interest in certain of our proved properties in the Permian Basin in West Texas in exchange for 283,700 common units representing limited partner interests in us, which were valued at approximately $5.8 million at the time of the acquisition. In February 2008, we acquired the Permian and Williston Basin Assets from Encore Operating for total consideration of approximately $125.3 million in cash, including certain post-closing adjustments, and 6,884,776 common units representing limited partner interests in us. In determining the total purchase price, the common units were valued at $125 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties. Because the Permian and Williston Basin Assets and the Arkoma Basin Assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities were recorded at Encore Operating historical cost and our historical financial information was recast to include the acquired properties for all periods presented.

In March 2007, we acquired the Elk Basin Assets for a purchase price of approximately $330.7 million, including transaction costs.

Funding of working capital.As of December 31, 2008 and 2007, our working capital (defined as total current assets less total current liabilities) was $71.7 million and $4.6 million, respectively. The improvement 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 commodity derivative contracts. We anticipate cash reserves to be close to zero because we intend to distribute available cash to unitholders and reduce outstanding borrowings under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting our working capital in future periods. 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 for 2009.

The board of directors of our general partner approved a capital budget of approximately $7.4 million for 2009, excluding proved property acquisitions. 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 availability under our revolving credit facility.

ENCORE ENERGY PARTNERS LP

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.

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


	Payments Due by Period
Contractual Obligations and Commitments	Total		2009		2010 - 2011		2012 - 2013		Thereafter
	(in thousands)
Revolving credit facility (a)	$	162,350	$	3,900	$	7,800	$	150,650	$	—
Commodity derivative contracts (b)		—		—		—		—		—
Interest rate swaps		4,342		1,269		3,071		2		—
Development commitments (c)		1,799		1,799		—		—		—
Operating leases and commitments (d)		2,576		687		1,374		515		—
Asset retirement obligations (e)		32,707		389		778		778		30,762

Total	$	203,774	$	8,044	$	13,023	$	151,945	$	30,762


(a)		Includes principal and projected interest payments. Please read Note 7 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. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” included in our 2008 Annual Report and Notes 11 and 12 of our Recast Financial Statements for additional information regarding our commodity derivative contracts.

(c)		Represents authorized purchases for work in process. Also at December 31, 2008, we had $10.4 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 expected to be made unless circumstances change.

(d)		Represents equipment obligations that have non-cancelable lease terms in excess of one year. Please read Note 4 of our Recast Financial Statements for additional information regarding our operating leases.

(e)		Represents 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. Encore Operating provides administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an 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 us. Encore Operating initially received an administrative fee of $1.75 per BOE of our production for such services. As of December 31, 2008, the administrative fee was $1.88 per BOE of our production. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of our production as a result of the COPAS Wage Index Adjustment. Encore Operating also charges us for reimbursement of actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our 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.

The administrative fee will increase in the following circumstances:

	•		beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

	•		if we or one of our subsidiaries acquires any additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of our general partner upon the recommendation of its conflicts committee; and

	•		otherwise as agreed upon by Encore Operating and our general partner, with the approval of the conflicts committee of our general partner.

Capital resources

Cash flows from operating activities. Cash provided by operating activities increased $84.0 million from $40.0 million in 2007 to $123.9 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 remained constant at $40.0 million in 2007 as compared to $39.9 million in 2006.

ENCORE ENERGY PARTNERS LP

Cash flows from investing activities. Cash used in investing activities decreased $357.2 million from $377.5 million in 2007 to $20.3 million in 2008 as a result of a decrease in amounts paid for the acquisition of oil and natural gas properties. In March 2007, we paid approximately $330.7 million, including transaction costs, in connection with the acquisition of the Elk Basin Assets. In April 2007, we used cash of approximately $27.3 million in connection with the purchase of certain properties in the Williston Basin. The Williston Basin properties were acquired from EAC in February 2008 as part of the Permian and Williston Basin Assets and, as the transaction was accounted for as a transaction between entities under common control, the purchase price of the properties are shown in the period the properties were originally purchased by EAC.

Cash used in investing activities increased $370.7 million from $6.8 million in 2006 to $377.5 million in 2007, primarily due to a $357.2 million increase in amounts paid for the acquisition of oil and natural gas properties, primarily the acquisition of our Elk Basin Assets, and a $13.0 million increase in amounts paid for development of our oil and natural gas properties.

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

During 2008, we used net cash of $103.1 million in financing activities, including $125.0 million in deemed distributions to affiliates in connection with our acquisition of the Permian and Williston Basin Assets and $74.4 million in distributions to unitholders, partially offset by net borrowings of $102.5 million under our revolving credit facility. Net borrowings on our revolving credit facility resulted in an increase in outstanding borrowings under our revolving credit facility from $47.5 million at December 31, 2007 to $150 million at December 31, 2008.

During 2007, we received net cash of $337.5 million from financing activities, including net borrowings on our long-term debt of $47.5 million, net proceeds received from the sale of our common units of $193.5 million, $93.7 million contribution from EAC used to partially finance the acquisition of the Elk Basin Assets, and $6.0 million of net contributions from EAC prior to our IPO.

During 2006, we used net cash of $33.1 million in financing activities for distributions of earnings to EAC.

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 debt or common units, to fund acquisitions and to 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 facility could be adversely affected. In the event of a reduction in the borrowing base under our revolving credit facility, we do not believe it will result in any required prepayments of indebtedness given our relatively low levels of borrowings under that facility in relation to the existing borrowing base.

Our partnership agreement requires that we distribute all of our available cash quarterly. In May 2008, the board of directors of our general partner approved a new distribution methodology, which returns additional cash flow to our unitholders during high commodity price environments. As a general guideline, we plan to distribute to unitholders 50 percent of the excess distributable cash flow above: (1) maintenance capital requirements; (2) an implied minimum quarterly distribution of $0.4325 per unit, or $1.73 per unit annually; and (3) a minimum coverage ratio of 1.10. We may decide to make a fixed quarterly distribution over a specified period pursuant to the preceding formula in order to reduce some of the variability in quarterly distributions over the specified period. Accordingly, we may make a distribution during a quarter even if we have not generated sufficient cash flow to cover such distribution by borrowing under our revolving credit facility, and we may reserve some of our cash during a quarter for distributions in future quarters even if the preceding formula would result in the distribution of a higher amount for such quarter. Our board of directors also may change our distribution philosophy based on prevailing business conditions. There can be no assurance that we will be able to distribute $0.4325 on a quarterly basis or achieve a minimum coverage ratio of 1.10. Our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

We plan to make substantial capital expenditures in the future for the acquisition, exploitation, and development of oil and natural gas properties. We intend to finance these capital expenditures with cash flow from operations. We intend to finance our acquisition

ENCORE ENERGY PARTNERS LP

and future development and exploitation activities with a combination of cash flow from operations and issuances of debt, equity, or a combination thereof.

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 50 percent and 27 percent, respectively, as compared to 2007. Realized oil and natural gas prices fluctuate widely in response to changing market forces. In 2008, approximately 67 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 decline 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 two-thirds of our forecasted production through 2011 against falling commodity prices. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” included in our 2008 Annual Report and Notes 11 and 12 of our Recast Financial Statements for additional information regarding our commodity derivative contracts.

Revolving credit facility.Our principal source of short-term liquidity is a five year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”) between OLLC and 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 the OLLC Credit Agreement to revise certain financial covenants. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. 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 syndicate of lenders underwriting our facility includes 13 banking and other financial institutions, 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 total commitments. We believe the large number of lenders, the relatively small percentage participation of each, and the remaining availability under our 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
	Contracts			Derivative Contracts
Counterparty	Committed			Committed
Bank of America, N.A.		27	%		—
BNP Paribas		28	%		24	%
Fortis		11	%		—
Calyon		—			31	%
Goldman Sachs Group		20	%		—
Wachovia Bank		—			38	%

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. At December 31, 2008, the borrowing base was $240 million. In March 2009, the borrowing base under the OLLC Credit Agreement was redetermined with no change.

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 us and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.

ENCORE ENERGY PARTNERS LP

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


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

The “Eurodollar Rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) during a “LIBOR Unavailability Period,” the “Eurodollar Rate” (for dollar deposits for a one-month term) for such day plus 1.0 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 our assets and the assets of our 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 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. At December 31, 2008, we were in compliance with all debt covenants.

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 commitment fee percentage under the OLLC Credit Agreement:


	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

On December 31, 2008, we had $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement. On April 30, 2009, we had $176 million of outstanding borrowings and $64 million of borrowing capacity under the OLLC Credit Agreement.

ENCORE ENERGY PARTNERS LP

Capitalization.At December 31, 2008, we had total assets of $577.4 million and total capitalization was $542.6 million, of which 72 percent was represented by partners’ equity and 28 percent by long-term debt. At December 31, 2007, we had total assets of $515.6 million and total capitalization was $459.8 million, of which 90 percent was represented by partners’ equity and 10 percent by long-term debt. The percentages of our capitalization represented by partners’ 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 realized oil and natural gas prices for the periods indicated.


	Year Ended December 31,
	2008		2007		2006
Average realized prices:
Oil ($/Bbl)	$	89.27	$	59.38	$	60.96
Natural gas ($/Mcf)		8.54		6.74		6.72
Combined ($/BOE)		76.78		52.96		46.37

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 was 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 we are making sufficient progress 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 in the period in which the determination was 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.

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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 on 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. 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,”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 might be impaired. However, our estimates of undiscounted cash flows based on management’s outlook of future commodity prices at the date of assessment indicated that the remaining carrying amounts of our oil and natural gas properties are expected to be recovered, although in some cases by only a marginal amount. 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 a 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 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:

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	•		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 well 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 current 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 in the fourth quarter or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. We have determined that we have only one reporting unit, which is oil and natural gas production in the United States. We performed our annual impairment test at December 31, 2008, and determined that no indicators of impairment existed. 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.

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.

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.

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. Royalties 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 our 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

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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.

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 derivative contracts with large financial institutions. We also use derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.

We apply the provisions of SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities”and its amendments (“SFAS 133”), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive income until such time as the hedged item is recognized in earnings.

In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Cash flow hedges are marked to market through accumulated other comprehensive 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 not elected to 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 nonfinancial 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. The adoption of SFAS 157 on January 1, 2009, as it relates to all instruments within the scope of FSP FAS 157-2, did not 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

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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”)

In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141,“Business Combinations.”SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies” (“FSP FAS 141R-1”), which amends and clarifies SFAS 141R to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R and FSP FAS 141R-1 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. Subsequent to December 31, 2008, we completed an acquisition for certain oil and natural gas producing properties and related assets from Encore Operating. The accounting for transactions between entities under common control is unchanged under SFAS 141R. However, the application of SFAS 141R and FSP FAS 141R-1 to future acquisitions could have an impact on our results of operations and financial condition.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”)

In March 2008, the FASB issued SFAS 161, which amends SFAS 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 was effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 on January 1, 2009 required additional disclosures regarding our derivative instruments; however, it did not impact our results of operations or financial condition.

Emerging Issues Task Force (“EITF”) Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”)

In March 2008, the EITF ratified its consensus opinion on EITF 07-4, which addresses how master limited partnerships should calculate earnings per unit using the two-class method in SFAS No. 128,“Earnings per Share”(“SFAS 128”) and how current period earnings of a master limited partnership should be allocated to the general partner, limited partners, and other participating securities. EITF 07-4 was retrospectively effective for fiscal years beginning after December 15, 2008, and interim periods within those years. The adoption of EITF 07-4 on January 1, 2009 did not have a material impact on our earnings per unit calculations. All periods presented in our Recast Financial Statements have been restated to reflect the adoption of EITF 07-4.

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

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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 unit-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per unit (“EPU”) under the two-class method prescribed by SFAS 128. FSP EITF 03-6-1 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years, with early application prohibited. The adoption of FSP EITF 03-6-1 on January 1, 2009 did not have a material impact on our earnings per unit calculations. All periods presented in our Recast Financial Statements have been restated to reflect the adoption of FSP EITF 03-6-1.

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