ENP Encore Energy Partners Lp

Encore Energy Partners LP (NYSE:ENP) (the “Partnership” or “ENP”) today announced its unaudited third quarter 2011 results.

Summary of 2011 and 2010 Third Quarter Results

The following table highlights certain reported amounts for the third quarter of 2011 and 2010 (common units and dollars in millions, except quarterly distribution per unit):

 

Three MonthsEnded

September 30,2011

   

Three MonthsEnded

September 30,2010

Adjusted EBITDAX (a non-GAAP measure) $ 33.6 $ 29.8 Net income $ 96.4 $ 2.4 Adjusted net income (a non-GAAP measure) $ 13.4 $ 11.4 Distributable cash flow (a non-GAAP measure) $ 23.2 $ 24.7 Total distributions to be paid $ 21.6 $ 22.9 Quarterly distribution per unit $ 0.47 $ 0.50 Weighted average common units outstanding 45.5 45.3 Total units to which Q3 distributions will be paid 46.0 45.8 Oil and natural gas revenues $ 51.2 $ 42.8 Average daily production volumes (BOE) 8,991 8,630 Oil volumes as a percentage of total production volumes 62 % 64 % Oil and natural gas development & exploration costs $ 7.1 $ 2.0  

Adjusted EBITDAX totaled $33.6 million for the third quarter of 2011 and distributable cash flow totaled $23.2 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.

We reported net income attributable to Encore unitholders for the quarter of $96.4 million or $2.10 per basic unit compared to a reported net income of $2.4 million or $0.05 per basic unit in the third quarter of 2010; however, both quarters included special items. The recent quarter included $83.4 million of non-cash unrealized net gains on our commodity and interest rate derivatives contracts, $1.2 million in one-time material transaction costs incurred on acquisitions and mergers and $0.8 million in net gains on acquisitions of oil and natural gas properties. The 2010 third quarter results included a $9.0 million unrealized net loss on our commodity and interest rate derivatives contracts.

Excluding the net impact of the specific non-cash and one-time items mentioned above, Adjusted Net Income attributable to Encore unitholders (a non-GAAP financial measure defined below) was $13.4 million in the third quarter of 2011 or $0.29 per basic unit, as compared to $11.4 million or $0.24 per basic unit, in the third quarter of 2010.

Average daily production for the third quarter of 2011 was 5,555 Bbls of oil per day, 16,912 Mcf of natural gas per day, and 617 Bbls of natural gas liquids per day compared to 5,544 Bbls of oil per day, 15,755 Mcf of natural gas per day and 460 Bbls of natural gas liquids per day for the third quarter of 2010, for a combined 8,991 barrels of oil equivalent per day ("BOE/D") in the third quarter of 2011 compared to 8,630 BOE/D in the third quarter of 2010.

For the third quarter of 2011, the Partnership's average realized oil price was $75.95 per Bbl after consideration of a negative fifteen percent ($13.64 per Bbl) oil differential to NYMEX compared to $66.20 per Bbl and a negative thirteen percent ($9.90 per Bbl) oil differential to NYMEX for the third quarter of 2010. The average realized natural gas price was $5.66 per Mcf compared to $4.48 per Mcf in the third quarter of 2010.

Summary of 2011 and 2010 Nine Month Results

The following table highlights certain reported amounts for the periods indicated (dollars in millions):

 

Nine MonthsEnded

September 30,2011

   

Nine MonthsEnded

September 30,2010

Adjusted EBITDAX (a non-GAAP measure) $ 98.2 $ 91.7 Net income $ 103.2 $ 46.3 Adjusted net income (a non-GAAP measure) $ 44.5 $ 33.9 Distributable cash flow (a non-GAAP measure) $ 79.1 $ 77.5 Oil and natural gas revenues $ 152.7 $ 136.1 Average daily production volumes (BOE) 8,665 8,833 Oil volumes as a percentage of total production volumes 63 % 63 % Oil and natural gas development & exploration costs $ 9.9 $ 4.3  

Adjusted EBITDAX totaled $98.2 million for the first nine months of 2011 and distributable cash flow totaled $79.1 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.

We reported net income attributable to Encore unitholders for the first nine months of 2011 of $103.2 million or $2.24 per basic unit compared to a reported net income of $46.3 million or $1.01 per basic unit in the first nine months of 2010; however, both periods included special items. The 2011 results included $59.5 million of non-cash unrealized net gains in our commodity and interest rate derivatives contracts, $1.6 million in one-time material transaction costs incurred on acquisitions and mergers and $0.8 million in net gains on acquisitions of oil and natural gas properties. The 2010 results included a $12.4 million unrealized net gain in our commodity and interest rate derivatives contracts.

Excluding the net impact of the specific non-cash and one-time items mentioned above, Adjusted Net Income attributable to Encore unitholders (a non-GAAP financial measure defined below) was $44.5 million in the first nine months of 2011 or $0.97 per basic unit, as compared to $33.9 million or $0.73 per basic unit, in the first nine months of 2010.

Average daily production for the first nine months of 2011 was 5,481 Bbls of oil per day, 16,094 Mcf of natural gas per day, and 501 Bbls of natural gas liquids per day compared to 5,563 Bbls of oil per day, 16,196 Mcf of natural gas per day and 571 Bbls of natural gas liquids per day for the first nine months of 2010, for a combined 8,665 BOE/D in the first nine months of 2011 compared to 8,833 BOE/D in the first nine months of 2010.

For the first nine months of 2011, the Partnership's average realized oil price was $82.11 per Bbl after consideration of a negative fourteen percent ($13.20 per Bbl) oil differential to NYMEX compared to $69.63 per Bbl and a negative ten percent ($7.97 per Bbl) oil differential to NYMEX for the first nine months of 2010. The average realized natural gas price was $4.75 per Mcf for the first nine months of 2011 compared to $4.84 per Mcf in the first nine months of 2010.

Recent Events

On July 11, 2011, Vanguard and ENP announced the execution of a definitive agreement that would result in a merger whereby ENP would become a wholly-owned subsidiary of Vanguard Natural Gas, LLC (“VNG”) through a unit-for-unit exchange. Under the terms of the definitive agreement, ENP’s public unitholders will receive 0.75 Vanguard common units in exchange for each ENP common unit they own at closing. The transaction will result in approximately 18.4 million additional common units being issued by Vanguard. The terms of the definitive agreement were unanimously approved by the members of the ENP Conflicts Committee, who negotiated the terms on behalf of ENP and is comprised solely of independent directors. Jefferies & Company, Inc., has issued a fairness opinion to the ENP Conflicts Committee stating that they believe the exchange ratio is fair, from a financial point of view, to the unaffiliated unitholders of ENP. In addition, RBC Capital Markets has issued a fairness opinion to the Vanguard Conflicts Committee stating that they believe the exchange ratio is fair, from a financial point of view, to Vanguard.

The completion of the merger is subject to approval by a majority of the outstanding ENP common unitholders and also subject to the approval of the issuance of additional Vanguard common units in connection with the merger by the affirmative vote of a majority of the votes cast by Vanguard unitholders. Completion of the merger, assuming the requisite unitholder votes are obtained and subject to other customary terms and conditions, is expected to occur on November 30, 2011. On August 2, 2011, ENP and Vanguard filed a Registration Statement on Form S-4 (the “Form S-4”) with the Securities and Exchange Commission (the “SEC”), which has been declared effective. The Form S-4 incorporates a joint proxy statement/prospectus which ENP and Vanguard mailed to their respective unitholders in connection with obtaining unitholder approval of the proposed merger. Pending completion of the merger, ENP has agreed to customary restrictions in the way it conducts its business.

On November 1, 2011, Vanguard and ENP announced that both companies have established a record date and a meeting date for the special meetings of unitholders to consider and vote upon the previously-announced merger agreement.

ENP unitholders of record at the close of business on October 14, 2011 are entitled to notice of and to vote at the special meeting. The ENP special meeting will be held on Wednesday, November 30, 2011 at 10:00am Central Time, at the offices of Vinson & Elkins, 1001 Fannin Street, Suite 2500, Houston, TX 77002.

Vanguard and ENP unitholders are encouraged to read the definitive proxy statement relating to the special meetings in its entirety. The definitive proxy statement was filed with the SEC on October 31, 2011 and was first mailed to unitholders on the same date.

Vanguard and ENP unitholders who have questions about the merger or who require assistance in submitting their proxy or voting their units should contact the proxy solicitor, D.F. King & Co., Inc. at 1-800-628-8532.

See below for a description of a recently amended credit facility under Liquidity Update.

Acquisitions

On June 22, 2011, pursuant to two Purchase and Sale Agreements, ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from a private seller. ENP and Vanguard agreed to purchase 50% of the Purchased Assets for an aggregate of $85.0 million and each paid the seller a non-refundable deposit of $4.25 million. The effective date of this acquisition is May 1, 2011. We completed this acquisition on July 29, 2011 for an adjusted purchase price of $40.7 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under our Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 2.64 million barrels of oil equivalent, of which approximately 70% are oil and natural gas liquids reserves and are 100% proved developed.

On August 8, 2011, we entered into assignment agreements and completed the acquisition of certain oil and natural gas properties located in the Permian Basin of West Texas from a private seller. The adjusted purchase price for the assets was $14.8 million with an effective date of May 1, 2011. This acquisition was funded with borrowings under our Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 1.02 million barrels of oil equivalent, of which approximately 87% are oil and are 50% proved developed.

On August 15, 2011, we entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Wyoming. The purchase price for the assets was $28.5 million with an effective date of June 1, 2011. We completed this acquisition on September 1, 2011 for an adjusted purchase price of $27.7 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under our Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 3.91 million barrels of oil equivalent, of which approximately 65% are natural gas reserves and are 100% proved developed producing.

On August 31, 2011, we entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the Texas and Louisiana Gulf Coast area from a private seller. The adjusted purchase price for the assets was $47.6 million with an effective date of August 1, 2011. This acquisition was funded with borrowings under our Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 2.13 million barrels of oil equivalent, of which approximately 83% are oil and natural gas liquids reserves and are 100% proved developed.

Hedging Activities

We enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil and natural gas price volatility on our cash flow from operations. We have mitigated some of the volatility through 2014 for both crude oil and natural gas by implementing a hedging program on a portion of our total anticipated production. At September 30, 2011, the fair value of commodity derivative contracts was a net asset of approximately $30.7 million, of which $14.8 million settles during the next twelve months. Currently, we use fixed-price swaps, basis swaps, puts, swaptions, three-way collars and NYMEX collars to hedge oil and natural gas prices.

The following table summarizes new commodity derivative contracts put in place during the three months ended September 30, 2011:

 

October 1, –December 31,2011

   

Year2012

   

Year 2013

   

Year2014

   

Year2015

Gas Positions: Fixed Price Swaps: Notional Volume (MMBtu) 230,000 915,000 912,500 452,500 — Fixed Price ($/MMBtu) $ 4.80 $ 4.80 $ 4.80 $ 4.80 $ — Basis Swaps: (1) Notional Volume (MMBtu) 230,000 915,000 912,500 452,500 — Fixed Price ($/MMBtu) ($0.32 ) ($0.32 ) ($0.32 ) ($0.32 ) $ —   Oil Positions: Fixed Price Swaps: Notional Volume (Bbls) — 36,600 36,500 36,500 — Price ($/Bbl) $ — $ 95.00 $ 95.00 $ 95.00 $ — Swaptions: Notional Volume (Bbls) — — — — 36,500 Floor Price ($/Bbl) $ — $ — $ — $ — $ 95.00 Three Way Collars: Notional Volume (Bbls) 36,800 192,150 191,625 54,750 — Floor Price ($/Bbl) $ 90.00 $ 90.00 $ 90.00 $ 90.00 $ — Ceiling Price ($/Bbl) $ 102.63 $ 106.76 $ 106.76 $ 105.00 $ — Short Put Price ($/Bbl) $ 70.00 $ 70.00 $ 70.00 $ 70.00 $ — Basis Swaps: (2) Notional Volume (MMBtu) 21,000 84,000 84,000 — — Fixed Price ($/MMBtu) $ 19.10 $ 15.15 $ 9.60 $ — $ —  

(1)

 

Natural gas basis swap contracts represent a weighted average differential between prices against Rocky Mountains (CIGC) and NYMEX Henry Hub prices.

(2)

Oil basis swap contracts represent a weighted average differential between prices against Light Louisiana Sweet Crude (LLS) and NYMEX WTI prices.

 

Interest Rate Swaps

ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby the interest due on certain floating rate debt under the Credit Agreement is converted to a weighted average fixed rate. On September 21, 2011, we increased the existing $50 million swap to $75 million and extended the maturity to March 7, 2016, allowing us to decrease the fixed Libor rate from 2.42% to 1.08%. The following table summarizes ENP’s open interest rate swap as of September 30, 2011, which was entered into with Bank of America, N.A.:

Term:    

NotionalAmount

 

 

FixedLiborRates

   

FixedLiborRates

October 1, 2011 to March 7, 2016 (1)

$ 75,000 1.08 % 1-month LIBOR  

(1)

 

ENP entered into this interest rate swap on September 21, 2011, and the terms became effective on October 7, 2011.

 

For a summary of all commodity and interest rate derivative contracts in place at September 30, 2011, please refer to our third quarter Form 10-Q which is expected to be filed on November 8, 2011.

Cash Distributions

On November 14, 2011, Encore will pay a third quarter cash distribution of $0.47 per unit to its unitholders of record as of November 7, 2011. This quarterly distribution payment is unchanged from the amount distributed for the second quarter of 2011 and a $0.02 decrease from the $0.49 per unit quarterly distributions paid in the first quarter of 2011.

Capital Expenditures

Capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $7.1 million in the third quarter of 2011 compared to $2.0 million for the comparable quarter of 2010. During the three months ended September 30, 2011, a substantial portion of these capital expenditures were spent on drilling three wells in the Big Horn Basin amounting to approximately $3.4 million and on drilling of non-operated properties. An additional $3.3 million was spent on maintenance capital projects and recompletions in the Big Horn Basin, Permian Basin and Williston Basin. Capital spending in the third quarter was below expectations because of the early release of the drilling rig in the Big Horn Basin in September 2011.

Liquidity Update

At September 30, 2011, ENP had $356.0 million outstanding under its credit agreement and $44.0 million of remaining availability. As of November 2, 2011 there were $346.0 million of outstanding borrowings and $54.0 million of borrowing capacity under the credit agreement.

On September 30, 2011, Vanguard entered into a Third Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amends and restates its existing facility. The execution of the Amended Credit Agreement will only be effective upon the satisfaction of certain conditions including, but not limited to, the successful consummation of the previously announced merger between Vanguard and ENP. The Amended Credit Agreement provides for an initial borrowing base of $765 million and a maturity of October 31, 2016. Under the terms of the Amended Credit Agreement, Vanguard has agreed that a portion of the proceeds of the credit facility created by this Amended Credit Agreement will be used to repay amounts outstanding under our credit agreement.

As shown on the September 30, 2011 balance sheet, all borrowings under the credit agreement are reflected as current liabilities. This is due to the credit agreement maturing on March 7, 2012. As discussed above, on September 30, 2011, Vanguard entered into the Amended Credit Agreement and has agreed that a portion of the proceeds of the credit facility created by this Amended Credit Agreement will be used to repay amounts outstanding under our credit agreement.

Conference Call Information

Vanguard and Encore will host a joint conference call today to discuss Vanguard and Encore’s third quarter results at 10:30 a.m. Eastern Time (9:30 a.m. Central). To access the call, please dial (800) 762-8908 or (480) 629-9677, for international callers and ask for the Vanguard Natural Resources call a few minutes prior to the start time. The conference call will also be broadcast live via the Internet and can be accessed through the investor relations section of Vanguard’s website, http://www.vnrllc.com.

A telephonic replay of the conference call will be available through December 3, 2011 and may be accessed by calling (303) 590-3030 and using the pass code 4483164#. A webcast archive will be available on the Investor Relations page at www.vnrllc.com shortly after the call and will be accessible for approximately 30 days. For more information, please contact Lisa Godfrey at (832) 327-2234 or email at investorrelations@vnrllc.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: DNR) 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 ENP's evaluation of strategic alternatives, 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, expected expenses, expected taxes, expected capital expenditures, and expected 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; diversion of management's attention from existing operations while pursuing acquisitions; 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 the effects of the worldwide economic recession); 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.

 

ENCORE ENERGY PARTNERS LP

OPERATING STATISTICS

(unaudited)

             

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2011 2010 2011 2010 Average realized prices: Oil ($/Bbl) $ 75.95 $ 66.20 $ 82.11 $ 69.63 Natural gas ($/Mcf) $ 5.66 $ 4.48 $ 4.75 $ 4.84 Natural gas liquids ($/Bbl) $ 62.59 $ 59.54 $ 65.67 $ 57.68 Combined ($/BOE) $ 61.87 $ 53.89 $ 64.56 $ 56.45   Total production volumes: Oil (MBbls) 511 510 1,496 1,519 Natural gas (MMcf) 1,556 1,449 4,394 4,421 Natural gas liquids (MBbls) 57 42 137 156 Combined (MBOE) 827 794 2,365 2,411   Average daily production volumes: Oil (Bbls/D) 5,555 5,544 5,481 5,563 Natural gas (Mcf/D) 16,912 15,755 16,094 16,196 Natural gas liquids (Bbls/D) 617 460 501 571 Combined (BOE/D) 8,991 8,630 8,665 8,833   Average NYMEX prices: Oil (per Bbl) $ 89.59 $ 76.10 $ 95.31 $ 77.60 Natural gas (per Mcf) $ 4.17 $ 4.24 $ 4.19 $ 4.54      

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)

 

Three months endedSeptember 30,

Nine months endedSeptember 30

2011   2010 2011   2010 Revenues: Oil $ 38,814 $ 33,765 $ 122,869 $ 105,732 Natural gas 8,811 6,497 20,872 21,407 Natural gas liquids 3,554 2,521 8,978 9,001 Marketing 126 60 207 207 Commodity derivative fair value gain (loss) - realized (2,818 ) 1,342 (7,616 ) 1,959 Commodity derivative fair value gain (loss) - unrealized   82,914   (8,922 )   58,318   12,521 Total revenues   131,401   35,263   203,628   150,827   Expenses: Production: Lease operating 10,451 9,268 29,198 30,907 Production and other taxes 5,647 4,752 15,672 14,951 Depletion, depreciation, amortization, and accretion 12,500 12,782 35,568 38,472 Exploration - 53 - 129 General and administrative   4,451   2,817   12,710   10,088 Total expenses   33,049   29,672   93,148   94,547   Operating income   98,352   5,591   110,480   56,280   Other income (expenses): Interest (2,646 ) (2,303 ) (7,030 ) (6,987 ) Interest rate derivative fair value loss - realized (445 ) (974 ) (1,858 ) (2,925 ) Interest rate derivative fair value gain (loss) - unrealized 523 (29 ) 1,146 (133 ) Net gain on acquisitions of oil and natural gas properties 815 - 815 - Other   70   9   79   47 Total other expenses   (1,683 )   (3,297 )   (6,848 )   (9,998 )   Income before income taxes 96,669 2,294 103,632 46,282 Income tax provision   (220 )   147   (415 )   36   Net income $ 96,449 $ 2,441 $ 103,217 $ 46,318   Net income allocation: Limited partners' interest in net income $ 95,391 $ 2,419 $ 102,084 $ 45,813 General partner's interest in net income $ 1,058 $ 22 $ 1,133 $ 505   Net income per common unit: Basic $ 2.10 $ 0.05 $ 2.24 $ 1.01 Diluted $ 2.10 $ 0.05 $ 2.24 $ 1.01   Weighted average common units outstanding: Basic 45,487 45,342 45,481 45,328 Diluted 45,487 45,342 45,481 45,336      

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

  September 30, December 31, 2011 2010 (unaudited) Assets Current assets: Cash and cash equivalents $ 651 $ 1,380 Accounts receivable - trade 34,260 22,795 Derivatives 14,813 2,604 Other   2,172     470   Total current assets   51,896     27,249   Properties and equipment, at cost - successful efforts method: Proved properties, including wells and related equipment 1,002,851 857,999 Unproved properties 41 17 Accumulated depletion, depreciation, and amortization   (294,014 )   (259,575 )   708,878     598,441   Other property and equipment 1,694 1,327 Accumulated depreciation   (669 )   (613 )   1,025     714   Goodwill 9,290 9,290 Other intangibles, net 2,784 3,012 Derivatives 15,884 836 Other   318     1,778   Total assets $ 790,075   $ 641,320   Liabilities and partners’ equity Current liabilities: Accounts payable: Trade $ 2,021 $ 2,103 Affiliate 1,490 98 Accrued liabilities: Lease operating 4,717 4,550 Development capital 1,736 890 Interest 375 298 Production and other taxes 14,235 10,109 Derivatives 66 3,530 Oil and natural gas revenues payable 3,276 1,730 Credit agreement 356,000 - Other   2,497     1,278   Total current liabilities 386,413 24,586 Derivatives 241 20,681 Future abandonment cost, net of current portion 16,785 13,080 Deferred taxes 63 11 Credit agreement   -     234,000   Total liabilities   403,502     292,358   Commitments and contingencies Partners' equity: Limited partners - public, 24,560,808 and 24,417,542 common units issued and outstanding, respectively 349,912 340,126 Limited partners - affiliates, 20,924,055 common units issued and outstanding 36,674 10,125 General partner - 504,851 general partner units issued and outstanding 309 (94 ) Accumulated other comprehensive loss   (322 )   (1,195 ) Total partners' equity   386,573     348,962   Total liabilities and partners' equity $ 790,075   $ 641,320    

Non-GAAP Financial Measure

Adjusted EBITDAX

We define Adjusted EBITDAX as net income plus:

• Net interest expense, including write-off of deferred financing fees and realized gains and losses on interest rate derivative contracts;
• Depletion, depreciation and amortization (including accretion of asset retirement obligations);
• Exploration expense;
• Amortization of premiums paid on derivative contracts;
• Unrealized gains and losses on commodity and interest rate derivative contracts;
• Net gain on acquisitions of oil and natural gas properties;
• Income taxes;
• Unit-based compensation expense;
• Material transaction costs incurred on acquisitions and mergers; and
• Non-cash debt related expense paid by previous owner.

Adjusted EBITDAX is a significant performance metric used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors, debt service and capital expenditures) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDAX is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts, and others to assess the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.

Our Adjusted EBITDAX should not be considered as an alternative to net income, operating income, cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDAX excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDAX may not be comparable to similarly titled measures of other companies.

Distributable Cash Flow

We present Distributable Cash Flow in addition to our reported net income in accordance with GAAP. Distributable Cash Flow is a non-GAAP financial measure that is defined as net income plus:

• Depletion, depreciation and amortization (including accretion of asset retirement obligations);
• Exploration expense;
• Amortization of premiums paid on derivative contracts;
• Unrealized gains and losses on other commodity and interest rate derivative contracts;
• Net gain on acquisitions of oil and natural gas properties;
• Unit-based compensation expense;
• Material transaction costs incurred on acquisitions and mergers; and
• Non-cash debt related expense paid by previous owner

Less:

• Drilling, capital workover and recompletion expenditures.

Distributable Cash Flow is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. While Distributable Cash Flow is measured on a quarterly basis for reporting purposes, management must consider the timing and size of its planned capital expenditures in determining the sustainability of its quarterly distribution. Capital expenditures are typically not spent evenly throughout the year due to a variety of factors including weather, rig availability, and the commodity price environment. As a result, there will be some volatility in Distributable Cash Flow measured on a quarterly basis. Distributable Cash Flow is not intended to be a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

   

ENCORE ENERGY PARTNERS LP

Reconciliation of Net Income to Adjusted EBITDAX and Distributable Cash Flow

(in thousands)

(unaudited)

 

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2011   2010   2011     2010 Net income $ 96,449 $ 2,441 $ 103,217 $ 46,318 Plus: Net interest expense, including realized losses on interest rate derivative contracts 3,092 3,268 8,887 9,865 Depletion, depreciation and amortization 12,500 12,782 35,568 38,472 Exploration expense - 53 - 129 Amortization of premiums paid on derivative contracts 4,210 2,474 8,163 7,342 Unrealized (gains) losses on commodity and interest rate derivative contracts (83,437 ) 8,951 (59,464 ) (12,388 ) Net gain on acquisitions of oil and natural gas properties (815 ) - (815 ) - Income taxes 220 (147 ) 415 (36 ) Unit-based compensation expense 222 2 667 1,043 Material transaction costs incurred on acquisitions and mergers 1,182 - 1,589 - Non-cash debt related expense paid by previous owner   -   -   -   938 Adjusted EBITDAX $ 33,623 $ 29,824 $ 98,227 $ 91,683 Less: Interest expense, net 3,092 3,268 8,887 9,865 Income taxes 220 (147 ) 415 (36 ) Drilling, capital workover and recompletion expenditures   7,139   2,051   9,852   4,314 Distributable Cash Flow $ 23,172 $ 24,652 $ 79,073 $ 77,540  

Adjusted Net Income

We present Adjusted Net Income in addition to our reported net income in accordance with GAAP. Adjusted Net Income is a non-GAAP financial measure that is defined as net income plus:

• Unrealized gains and losses on other commodity derivative contracts;
• Unrealized gains and losses on interest rate derivative contracts;
• Net gain on acquisitions of oil and natural gas properties; and
• Material transaction costs incurred on acquisitions and mergers.

This information is provided because management believes exclusion of the impact of our unrealized derivatives not accounted for as cash flow hedges, net gain on acquisitions of oil and natural gas properties and material transaction costs incurred on acquisitions and mergers will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the impact that commodity price volatility has on our results. Adjusted Net Income is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

     

ENCORE ENERGY PARTNERS LP

Reconciliation of Net Income to Adjusted Net Income

(in thousands, except per unit amounts)

(unaudited)

 

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2011     2010 2011     2010   Net income $ 96,449 $ 2,441 $ 103,217 $ 46,318 Plus: Unrealized (gains) losses on commodity and interest rate derivative contracts (83,437 ) 8,951 (59,464 ) (12,388 ) Net gain on acquisitions of oil and natural gas properties (815 ) - (815 ) - Material transaction costs incurred on acquisitions and mergers   1,182     -   1,589     -   Adjusted Net Income $ 13,379   $ 11,392 $ 44,527   $ 33,930     Basic net income per unit: $ 2.10 $ 0.05 $ 2.24 $ 1.01 Plus: Unrealized (gains) losses on commodity and interest rate derivative contracts (1.81 ) 0.19 (1.29 ) (0.28 ) Gain on acquisitions of oil and natural gas properties (0.02 ) - (0.01 ) - Material transaction costs incurred on acquisitions and mergers   0.02     -   0.03     -   Basic adjusted net income per unit: $ 0.29   $ 0.24 $ 0.97   $ 0.73    

Important Information for Investors

This communication does not constitute an offer to sell any securities. Any such offer will be made only by means of a prospectus, and only if and when a definitive agreement has been entered into by Encore Energy Partners, LP (“ENP”) and Vanguard Natural Resources, LLC (“VNR”), pursuant to a registration statement filed with the Securities and Exchange Commission (“SEC”). If the proposed merger is approved, a registration statement of VNR, which will include a joint proxy statement of ENP and VNR, which will also constitute a prospectus of VNR, and other materials, will be filed with the SEC. IF AND WHEN APPLICABLE, INVESTORS AND SECURITY HOLDERS ARE URGED TO CAREFULLY READ THE DOCUMENTS FILED WITH THE SEC REGARDING THE PROPOSED TRANSACTION WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT ENP, VNR AND THE PROPOSED MERGER. If and when applicable, investors and security holders may obtain a free copy of the joint proxy statement / prospectus and other documents containing information about ENP and VNR, without charge, at the SEC’s website at www.sec.gov