Encore Energy Partners LP Announces Year-End Proved Reserves, Fourth Quarter and Year-End 2010 Results, and Provides Outlook for 2011

HOUSTON--(BUSINESS WIRE)--Encore Energy Partners LP (NYSE:ENP) (the “Partnership” or “ENP”) today announced its 2010 year end reserves, unaudited fourth quarter and year end 2010 results, and provided an outlook for 2011.

Proved Reserves

Total proved oil and natural gas reserves at December 31, 2010 were 41.1 million barrels of oil equivalent, consisting of 28.7 million barrels of crude oil, condensate, and natural gas liquids and 74.5 billion cubic feet of natural gas. Proved reserves were calculated utilizing 12-month average prices during 2010, or $79.43 per Bbl of oil and $4.45 per Mcf of natural gas as compared to $61.18 per Bbl of oil and $3.83 per Mcf of natural gas for 2009.

Using 2010 average prices, the estimated discounted net present value of ENP’s proved oil and natural gas reserves, before projected income taxes and net abandonment costs, using a 10 percent per annum discount rate (“PV-10 Value”) was approximately $703.5 million at December 31, 2010, as compared to a PV-10 Value of approximately $499.8 million at December 31, 2009.

At December 31, 2010, oil, condensate, and natural gas liquids reserves accounted for 70 percent of total proved reserves, and 90 percent of total proved reserves are developed. The following table summarizes the changes in proved reserves:

ENP’s proved reserve estimates for all of its properties were prepared by independent petroleum engineers from DeGolyer and McNaughton.

Summary of Fourth Quarter and Year End 2010 Results

The following table highlights certain reported amounts for the fourth quarter and year end of 2010 (common units and $ in millions, except quarterly distribution per unit):

Full Year 2010 Highlights

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 gain or loss) totaled $124.3 million for 2010 and distributable cash flow totaled $105.2 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 2010 was $32.1 million ($0.70 per diluted common unit). ENP’s 2010 results include a non-cash derivative fair value loss related to future periods of $16.3 million, non-cash equity-based compensation of $1.3 million, and a $0.9 million non-cash general and administrative (“G&A”) expense for a bank fee paid by Denbury Resources Inc. (the former parent of the Partnership’s general partner) related to a waiver of the change of control provision of the ENP credit agreement. Excluding these amounts, net income for the year was $50.6 million ($1.10 per diluted common unit). Net income excluding certain non-cash items is defined and reconciled to its most directly comparable GAAP measure in the attached financial schedules.

Average daily production for 2010 was 6,101 Bbls of oil per day and 15,990 Mcf of natural gas per day, for a combined 8,766 BOE per day. For 2010, the Partnership’s average realized wellhead oil price was $69.77 per Bbl, and the average realized wellhead natural gas price was $4.82 per Mcf. In 2010, the Partnership’s oil and natural gas differentials to NYMEX averaged a negative 12 percent ($9.74 per Bbl) and a positive 10 percent ($0.42 per Mcf), respectively. The average NYMEX oil price was $79.51 per Bbl in 2010, and the average NYMEX natural gas price was $4.40 per Mcf.

Lease operating expense for 2010 was $43.0 million ($13.45 per BOE).

G&A expense for 2010 was $12.4 million ($3.87 per BOE).

Depletion, depreciation, and amortization (“DD&A”) expense for 2010 was $50.6 million ($15.81 per BOE).

In 2010, the Partnership invested a total of $6.2 million in its development and exploration program.

Fourth Quarter 2010 Highlights

Adjusted EBITDAX totaled $32.6 million for the fourth quarter of 2010 and distributable cash flow totaled $27.6 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 loss for the fourth quarter of 2010 was $14.2 million ($0.31 per diluted common unit). ENP’s fourth quarter 2010 results include a non-cash derivative fair value loss related to future periods of $28.7 million and non-cash equity-based compensation of $0.3 million. Excluding these amounts, net income for the quarter was $14.7 million ($0.32 per diluted common unit). Net income excluding certain non-cash items is defined and reconciled to its most directly comparable GAAP measure in the attached financial schedules.

Average daily production for the fourth quarter of 2010 was 6,004 Bbls of oil per day and 15,379 Mcf of natural gas per day, for a combined 8,567 BOE per day. For the fourth quarter of 2010, the Partnership’s average realized wellhead oil price was $73.56 per Bbl, and the average realized wellhead natural gas price was $4.74 per Mcf. During the fourth quarter of 2010, the Partnership’s oil and natural gas differentials to NYMEX averaged a negative 14 percent ($11.60 per Bbl) and a positive 19 percent ($0.76 per Mcf), respectively. The average NYMEX oil price was $85.16 per Bbl in the fourth quarter of 2010, and the average NYMEX natural gas price was $3.98 per Mcf.

Lease operating expense for the fourth quarter of 2010 was $11.3 million ($14.36 per BOE).

G&A expense for the fourth quarter of 2010 was $2.3 million ($2.93 per BOE).

DD&A expense for the fourth quarter of 2010 was $12.1 million ($15.36 per BOE).

During the fourth quarter of 2010, the Partnership invested $1.8 million in its development and exploration program.

Liquidity Update

At December 31, 2010, ENP had $234 million outstanding under its revolving credit facility and $141 million of remaining availability on its $375 million revolving credit facility. The amount outstanding on the revolving credit facility decreased $6 million during the quarter as the Partnership continues to apply a portion of distributable cash flow to debt service in order to maintain its strong liquidity position.

2011 Outlook

Based on estimated average 2011 NYMEX pricing of $93.51 and $4.27 for crude oil and natural gas, respectively, the Partnership expects the following for 2011:

ENP is unique among upstream master limited partnerships, as it employs a variable rate distribution policy whereby the Partnership uses a formulaic guideline to calculate the amount of the quarterly distribution. The guideline suggests that the Partnership will pay an implied minimum distribution of $1.73 per unit annually and then include 50% of the excess cash flow above a minimum 1.1x distribution coverage ratio. As there can be significant fluctuations in distributable cash flow from quarter to quarter primarily based on the timing of capital expenditures, the amount of each quarterly distribution considers the expected distributable cash flow for the following twelve months to minimize the volatility in the quarterly distribution rate.

The Partnership’s strategy for 2011 is to significantly increase capital expenditures to approximately $19.5 million to $21.0 million compared to $6.2 million in 2010. The increase in capital expenditures is to provide long-term value to unitholders by maintaining well production and reducing the decline rate. Absent an accretive acquisition and based on the guidance provided above, the anticipated coverage ratio for 2011 is in the range of 1.1x – 1.2x at a distribution range to unitholders between $1.80 - $1.85 per unit on an annualized basis. The partnership agreement provides the general partner wide latitude to establish reserves for future capital expenditures and operational needs prior to determining the amount of cash available for distribution.

Conference Call Details

ENP will host the fourth quarter and full year 2010 earnings conference call to be held on Tuesday, February 22, 2011 at 10:00 a.m. Central Time. The call may be accessed on ENP’s website at www.encoreenp.com.

About Encore Energy Partners LP

Encore Energy Partners LP is a publicly traded master limited partnership focused on the acquisition, production, and development of oil and natural gas properties. 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. By virtue of Vanguard Natural Resources, LLC’s (NYSE: VNR) (“Vanguard”) acquisition of Encore Energy Partners GP LLC and certain limited partner interests in Encore Energy Partners LP from Denbury Resources Inc. (NYSE: DRI) on December 31, 2010, Vanguard now owns approximately 46% of the common units of ENP. More information on Vanguard can be found at www.vnrllc.com. More information on ENP can be found at www.encoreenp.com.

Forward-Looking Statements

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, 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.