Encore Energy Partners 8-K Encore Energy Partners LP Announces Third Quarter 2010 Results

Exhibit 99.1

Encore Energy Partners LP Announces Third Quarter 2010 Results

DALLAS, Texas — (BUSINESS WIRE) — November 4, 2010

Encore Energy Partners LP (NYSE: ENP) (the “Partnership” or “ENP”) today announced its unaudited third quarter 2010 results.

Summary of Third Quarter 2010 Results

The following table highlights certain reported amounts for the third quarter of 2010 (Common units and dollars in millions, except quarterly distribution per unit):

	Three Months Ended
	September 30, 2010
Adjusted EBITDAX	$	29.8
Net income excluding certain non-cash items	$	11.4
Net income	$	2.4
Distributable cash flow	$	24.7
Total distributions to be paid	$	22.9
Quarterly distribution per unit	$	0.50
Coverage ratio (distributable cash to distributions)		1.1
Weighted average diluted common units outstanding		45.3
Total units to which Q3 distributions will be paid		45.8
Oil and natural gas revenues	$	42.8
Average daily production volumes (BOE/D)		8,630
Oil as a percentage of total production volumes		70	%
Oil and natural gas development costs	$	2.0

Adjusted EBITDAX (earnings before depletion, depreciation, and amortization expense; non-cash equity-based compensation expense; exploration expense; interest and other expense; income tax expense; and non-cash derivative fair value loss) totaled $29.8 million for the third quarter of 2010 and distributable cash flow totaled $24.7 million. Adjusted EBITDAX and distributable cash flow are non-GAAP financial measures, which are defined and reconciled to their most directly comparable GAAP measures in the attached financial schedules.

ENP’s net income for the third quarter of 2010 was $2.4 million ($0.05 per common unit). The third quarter 2010 results include a non-cash derivative fair value loss of $9.0 million. Excluding this amount, net income for the quarter was $11.4 million ($0.24 per common unit). Net income excluding certain non-cash items is a non-GAAP financial measure, which is defined and reconciled to its most directly comparable GAAP financial measure in the attached financial schedules.

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Average daily production for the third quarter of 2010 was 6,004 Bbls of oil per day and 15,755 Mcf of natural gas per day, for combined average daily production of 8,630 BOE.

For the third quarter of 2010, the Partnership’s average realized wellhead oil price was $65.69 per Bbl, and the average realized wellhead natural gas price was $4.48 per Mcf. During the quarter, the Partnership’s oil differential to NYMEX averaged a negative 14 percent ($10.41 per Bbl) and its natural gas differential to NYMEX averaged a positive six percent ($0.24 per Mcf). ENP’s oil differentials in the Northern Rockies weakened in the third quarter primarily as a result of the closure of Enbridge Pipeline’s 6A and 6B pipelines due to leaks. The Partnership’s oil differentials began to strengthen in the fourth quarter as these pipelines have since been brought back online. The average NYMEX oil price was $76.10 per Bbl in the third quarter of 2010, and the average NYMEX natural gas price was $4.24 per Mcf.

Lease operating expense for the third quarter of 2010 was $9.6 million ($12.10 per BOE).

General and administrative expense for the third quarter of 2010 was $2.8 million ($3.55 per BOE). Included in this amount is approximately $0.5 million of fees incurred by the Conflicts Committee of the board of directors of the Partnership’s general partner in connection with consideration of a potential asset transaction with Denbury Resources Inc. (“Denbury”) regarding the Elk Basin field.

Depletion, depreciation, and amortization expense for the third quarter of 2010 was $12.8 million ($16.10 per BOE).

Operations Update

The Partnership invested $2.0 million in its capital program during the third quarter of 2010. The money was invested primarily in various well work-over projects and miscellaneous field development.

Liquidity Update

At September 30, 2010, ENP had $240 million outstanding under its revolving credit facility, giving the Partnership $135 million of remaining availability on its $375 million facility at the end of the third quarter.

Strategic Alternatives and Asset Transaction Processes

On September 2, 2010, ENP and Denbury announced (1) that they had terminated the asset process regarding the Elk Basin field, as no agreement could be reached on the value of the potential tertiary reserves; and (2) Denbury’s ongoing focus upon its intent to sell its interest in the Partnership’s general partner and all or part of the ENP common units that Denbury owns. Although Denbury intends to sell its interest in the Partnership’s general partner and all or part of ENP’s common units that Denbury owns, there is no assurance of the completion of any transaction.

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Conference Call Details

Title: Denbury Resources Inc. and Encore Energy Partners LP 3Q10 Conference Call

Date and Time: Thursday, November 4, 2010 at 10:00 a.m. CT

Webcast: Listen to the live broadcast at www.encoreenp.com

If you are unable to participate during the live broadcast, the call will be archived on the Partnership’s website for approximately 30 days. The audio portion of the call will also be available for playback by phone for one month after the call by dialing 800-475-6701 or 320-365-3844 and entering access code 175172.

About the Partnership

ENP’s assets consist primarily of producing and non-producing oil and natural gas properties in the Big Horn Basin in Wyoming and Montana, the Williston Basin in North Dakota and Montana, the Permian Basin in West Texas and New Mexico, and the Arkoma Basin in Arkansas and Oklahoma.

Cautionary Statement

This press release includes forward-looking statements, which give ENP’s current expectations or forecasts of future events based on currently available information. Forward-looking statements are statements that are not historical facts, including possible future transactions (including the timing or effects thereof), potential changes in ENP’s current business plan, increases in unitholder value expected distributions, the benefits, timing, and mix of acquisitions, and expected production volumes, expenses, taxes, capital expenditures, and differentials. The assumptions of management and the future performance of ENP are subject to a wide range of business risks and uncertainties and there is no assurance that these statements and projections will be met. Factors that could affect ENP’s business include, but are not limited to: the risks associated with drilling of oil and natural gas wells; ENP’s ability to find, acquire, market, develop, and produce new reserves; the risk of drilling dry holes; oil and natural gas price volatility; derivative transactions (including the costs associated therewith and the ability of counterparties to perform thereunder); uncertainties in the estimation of proved, probable, and possible reserves and in the projection of future rates of production and reserve growth; inaccuracies in ENP’s assumptions regarding items of income and expense and the level of capital expenditures; uncertainties in the timing of exploitation expenditures; operating hazards attendant to the oil and natural gas business; drilling and completion losses that are generally not recoverable from third parties or insurance; potential mechanical failure or underperformance of significant wells; climatic conditions; availability and cost of material and equipment; the risks associated with operating in a limited number of geographic areas; actions or inactions of third-party operators of ENP’s properties; availability of capital; the ability of lenders to fulfill their commitments; the strength and financial resources of ENP’s competitors; regulatory developments; environmental risks; uncertainties in the capital markets; general economic and business conditions, including on a worldwide basis; industry trends; and other factors detailed in ENP’s most recent Form 10-K and other filings with the Securities and Exchange Commission. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. ENP undertakes no obligation to publicly update or revise any forward-looking statements.

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SOURCE: Encore Energy Partners LP

ENCORE ENERGY PARTNERS LP

Phil Rykhoek, 972-673-2000
Chief Executive Officer
or
Mark Allen, 972-673-2000
Chief Financial Officer
or
Laurie Burkes, 972-673-2166
Investor Relations Manager

www.encoreenp.com

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Encore Energy Partners LP
Condensed Consolidated Statements of Operations
(in thousands, except per unit amounts)
(unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenues:
Oil	$	36,286		$	35,494		$	114,733		$	88,952
Natural gas		6,497			5,436			21,407			14,624
Marketing		60			102			207			381
Total revenues		42,843			41,032			136,347			103,957
Expenses:
Production:
Lease operating		9,607			9,717			31,701			32,614
Production taxes and marketing		4,413			4,523			14,157			11,865
Depletion, depreciation, and amortization		12,782			14,640			38,472			44,226
Exploration		53			3,034			129			3,074
General and administrative		2,817			3,557			10,088			9,800
Derivative fair value loss (gain)		7,609			(4,822	)		(14,347	)		21,711
Total operating expenses		37,281			30,649			80,200			123,290
Operating income (loss)		5,562			10,383			56,147			(19,333	)
Other income (expenses):
Interest		(3,277	)		(2,984	)		(9,912	)		(7,551	)
Other		9			23			47			34
Total other expenses		(3,268	)		(2,961	)		(9,865	)		(7,517	)
Income (loss) before income taxes		2,294			7,422			46,282			(26,850	)
Income tax benefit (provision)		147			38			36			(163	)
Net income (loss)	$	2,441		$	7,460		$	46,318		$	(27,013	)
Net income (loss) allocation:
Limited partners’ interest in net income (loss)	$	2,419		$	5,904		$	45,813		$	(26,745	)
General partner’s interest in net income (loss)	$	22		$	63		$	505		$	(444	)
Net income (loss) per common unit:
Basic	$	0.05		$	0.13		$	1.01		$	(0.72	)
Diluted	$	0.05		$	0.13		$	1.01		$	(0.72	)
Weighted average common units outstanding:
Basic		45,342			44,653			45,328			37,373
Diluted		45,342			44,675			45,336			37,373

Encore Energy Partners LP
Condensed Consolidated Statements of Cash Flows
(in thousands)
(unaudited)

	Nine Months Ended
	September 30,
	2010			2009
Net income (loss)	$	46,318		$	(27,013	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash and other items		36,596			128,514
Changes in operating assets and liabilities		15,516			(8,959	)
Net cash provided by operating activities		98,430			92,542
Net cash used in investing activities		(4,248	)		(39,314	)
Financing activities:
Net proceeds from issuance of common units		—			170,149
Net proceeds from (payments on) long-term debt		(15,000	)		107,061
Deemed distributions to affiliates in connection with the acquisition of assets		—			(258,429	)
Cash distributions to unitholders		(70,459	)		(57,041	)
Other		(194	)		(12,150	)
Net cash used in financing activities		(85,653	)		(50,410	)
Increase in cash and cash equivalents		8,529			2,818
Cash and cash equivalents, beginning of period		1,754			619
Cash and cash equivalents, end of period	$	10,283		$	3,437

Encore Energy Partners LP
Condensed Consolidated Balance Sheets
(in thousands)

	September 30,		December 31,
	2010		2009
	(unaudited)
Total assets	$	678,914	$	719,651
Liabilities (excluding long-term debt)	$	53,876	$	58,647
Long-term debt		240,000		255,000
Partners’ equity		385,038		406,004
Total liabilities and partners’ equity	$	678,914	$	719,651
Working capital (a)	$	14,481	$	15,558

(a) Working capital is defined as current assets minus current liabilities.

Encore Energy Partners LP
Selected Operating Results
(unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010			2009
Total production volumes:
Oil (MBbls)		552		586			1,675			1,775
Natural gas (MMcf)		1,449		1,663			4,421			4,470
Combined (MBOE)		794		863			2,411			2,520
Average daily production volumes:
Oil (Bbls/D)		6,004		6,369			6,134			6,502
Natural gas (Mcf/D)		15,755		18,077			16,196			16,375
Combined (BOE/D)		8,630		9,382			8,833			9,231
Average realized prices:
Oil (per Bbl)	$	65.69	$	60.58		$	68.51		$	50.11
Natural gas (per Mcf)		4.48		3.27			4.84			3.27
Combined (per BOE)		53.89		47.42			56.45			41.10
Average expenses per BOE:
Lease operating	$	12.10	$	11.26		$	13.15		$	12.94
Production taxes and marketing		5.56		5.24			5.87			4.71
Depletion, depreciation, and amortization		16.10		16.96			15.95			17.55
Exploration		0.07		3.52			0.05			1.22
General and administrative		3.55		4.12			4.18			3.89
Derivative fair value loss (gain)		9.58		(5.59	)		(5.95	)		8.62

Encore Energy Partners LP
Derivative Summary as of November 4, 2010
(unaudited)

Oil Derivative Contracts (b)

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average
	Floor		Floor		Cap		Cap		Swap		Swap
Period	Volume		Price		Volume		Price		Volume		Price
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)
Nov. — Dec. 2010
		880	$	80.00		440	$	93.80		760	$	75.43
		2,000		75.00		1,000		77.23		250		65.95
		760		67.00		—		—		—		—
2011
		1,880		80.00		1,440		95.41		760		78.46
		1,000		70.00		—		—		—		—
		760		65.00		—		—		250		69.65
2012
		750		70.00		500		82.05		210		81.62
		1,510		65.00		250		79.25		1,300		76.54

Natural Gas Derivative Contracts (b)

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average
	Floor		Floor		Cap		Cap		Swap		Swap
Period	Volume		Price		Volume		Price		Volume		Price
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)
Nov. — Dec. 2010
		3,800	$	8.20		3,800	$	9.58		5,452	$	6.20
		4,698		7.26		—		—		550		5.86
2011
		3,398		6.31		—		—		7,952		6.36
		—		—		—		—		550		5.86
2012
		898		6.76		—		—		5,452		6.26
		—		—		—		—		550		5.86

Interest Rate Swaps

	Notional		Fixed
Period	Amount		Rate			Floating Rate
	(in thousands)
Nov. 2010 - Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
Nov. 2010 - Jan. 2011		25,000		2.9650	%	1-month LIBOR
Nov. 2010 - Jan. 2011		25,000		2.9613	%	1-month LIBOR
Nov. 2010 - Mar. 2012		50,000		2.4200	%	1-month LIBOR

(b) Oil prices represent NYMEX WTI monthly average prices. Natural gas contracts are written at various market indices which may differ substantially from equivalent NYMEX prices.

Encore Energy Partners LP
Non-GAAP Financial Measures
(in thousands, except ratios and per unit amounts)
(unaudited)

     This press release includes a discussion of “Adjusted EBITDAX,” which is a non-GAAP financial measure. The following table provides reconciliations of “Adjusted EBITDAX” to net income and net cash provided by operating activities, ENP’s most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP, for the three months ended September 30, 2010:

Net income	$	2,441
Depletion, depreciation, and amortization		12,782
Non-cash equity-based compensation expense		2
Exploration expense		53
Interest expense and other		3,268
Income taxes		(147	)
Non-cash derivative fair value loss		11,425
Adjusted EBITDAX		29,824
Changes in operating assets and liabilities		(2,174	)
Other non-cash expenses		16
Cash interest expense		(2,887	)
Cash exploration expense		(53	)
Current income taxes		90
Net cash provided by operating activities	$	24,816

     “Adjusted EBITDAX” is used as a supplemental financial measure by ENP’s management and by external users of ENP’s financial statements, such as investors, commercial banks, research analysts, and others, to assess: (1) the financial performance of ENP’s assets without regard to financing methods, capital structure, or historical cost basis; (2) the ability of ENP’s assets to generate cash sufficient to pay interest costs and support its indebtedness; (3) ENP’s operating performance and return on capital as compared to those of other entities in the oil and natural gas industry, without regard to financing or capital structure; and (4) the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

     “Adjusted EBITDAX” should not be considered an alternative to net income, operating income, net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. ENP’s definition of “Adjusted EBITDAX” may not be comparable to similarly titled measures of another entity because all companies may not calculate “Adjusted EBITDAX” in the same manner.

     This press release also includes a discussion of “Distributable cash flow,” which is a non-GAAP financial measure. The following table provides a reconciliation of “distributable cash flow” to net income and net cash provided by operating activities, ENP’s most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP, for the three months ended September 30, 2010:

Net income	$	2,441
Depletion, depreciation, and amortization		12,782
Non-cash equity-based compensation expense		2
Non-cash derivative fair value loss		11,425
Exploration expense		53
Development capital		(2,051	)
Distributable cash flow		24,652
Changes in operating assets and liabilities		(2,174	)
Other non-cash expenses		16
Non-cash interest		381
Cash exploration expense		(53	)
Deferred income taxes		(57	)
Development capital		2,051
Net cash provided by operating activities	$	24,816

     ENP believes that “distributable cash flow” is a useful measure of ENP’s financial and operating performance and its ability to continue to make quarterly distributions.

     “Distributable cash flow” should not be considered an alternative to net income, operating income, net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. ENP’s definition of “distributable cash flow” may not be comparable to similarly titled measures of another entity because all entities may not calculate “distributable cash flow” in the same manner.

     This press release also includes a discussion of “Coverage ratio,” which is a non-GAAP liquidity measure. The following table provides the calculation of “coverage ratio” for the three months ended September 30, 2010:

Distributable cash flow			$	24,652
Divided by:
Equivalent outstanding units		45,846
Times: cash distribution per unit paid	$	0.50		22,923
Coverage ratio				1.1 x

     “Coverage ratio” is important to investors as an indicator of whether ENP is generating cash flow at a level that can sustain or support the quarterly distribution and support ENP’s goal of enhancing its liquidity. Actual distributions are set by the Board of Directors of ENP’s general partner.

     This press release also includes a discussion of “Net income excluding certain items,” which is a non-GAAP financial measure. The following table provides a reconciliation of “net income excluding certain items” to net income allocated to unitholders, ENP’s most directly comparable financial measure calculated and presented in accordance with GAAP, for the three months ended September 30, 2010:

			Per Diluted
	Total		Common Unit
Net income allocated to unitholders	$	2,441	$	0.05
Non-cash equity-based compensation expense		2		—
Non-cash derivative fair value loss excluding premium amortization		8,950		0.19
Net income excluding certain items	$	11,393	$	0.24

     ENP believes that the exclusion of these items enables it to evaluate operations more effectively period-over-period and to identify operating trends that could otherwise be masked by the excluded items.

     “Net income excluding certain items” should not be considered an alternative to net income allocated to unitholders, operating income, net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. ENP’s definition of “net income excluding certain items” may not be comparable to similarly titled measures of another entity because all entities may not calculate “net income excluding certain items” in the same manner.