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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2011
or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _______ to ________

Commission File Number: 001-33676

ENCORE ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)

Delaware
20-8456807
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)


5847 San Felipe, Suite 3000, Houston, Texas
77057
(Address of principal executive offices)
(Zip Code)

(832) 327-2255
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes þ    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o                                                                                                                     Accelerated filer þ
Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No þ

Number of common units outstanding as of August 4, 2011 45,489,584

 
 

 
ENCORE ENERGY PARTNERS LP

INDEX

   
Page
 
 
 
 
 
 


 
 

 
ENCORE ENERGY PARTNERS LP

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
 
Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
 
·  
our ability to pay distributions at the then-current distribution rate;
·  
our operating results;
·  
volatility in oil and natural gas prices;
·  
our ability to protect ourselves from changes in commodity prices using commodity derivative contract positions;
·  
performance of counterparties to our derivative contracts;
·  
our estimates of proved reserves;
·  
our ability to effectively develop our oil and natural gas reserves;
·  
availability of rigs, equipment and crews to support our operations;
·  
competitive conditions;
·  
our ability to acquire assets on acceptable terms; and
·  
legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal and state environmental laws and regulations.
 
Other factors that could cause our actual results to differ from our projected results are described in (1) Part II, “Item 1A. Risk Factors” and elsewhere in this report, (2) our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, (3) our Quarterly Report on Form 10-Q for the three months ended March 31, 2011, (4) our reports and registration statements filed from time to time with the Securities and Exchange Commission (the “SEC”) and (5) other announcements we make from time to time.
 
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
 
 
 

 
ENCORE ENERGY PARTNERS LP
GLOSSARY

The following are abbreviations and definitions of certain terms used in this Report.

·  
Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
·  
Bbl/D.  One Bbl per day.
·  
BOE.  One barrel of oil equivalent, calculated by converting gas to oil equivalent barrels at a ratio of six Mcf of gas to one Bbl of oil.
·  
BOE/D.  One BOE per day.
·  
Completion.  The installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.
·  
Council of Petroleum Accountants Societies (“COPAS”).  A professional organization of petroleum accountants that maintains consistency in accounting procedures and interpretations, including the procedures that are part of most joint operating agreements.  These procedures establish a drilling rate and an overhead rate to reimburse the operator of a well for overhead costs, such as accounting and engineering.
·  
DD&A.  Depletion, depreciation and amortization.
·  
Developed Oil and Gas Reserves.  Reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
·  
Development Well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
·  
Dry Well. An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
·  
Denbury.  Denbury Resources Inc., a publicly traded Delaware corporation, together with its subsidiaries.
·  
EAC.  Encore Acquisition Company, together with its subsidiaries.  EAC merged with and into Denbury on March 9, 2010.
·  
ENP.  Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.
·  
Exploratory Well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. For a complete definition of exploratory well, refer to Regulation S-X, Rule 4-10(a)(13).
·  
Extension Well.  A well drilled to extend the limits of a known reservoir.
·  
FASB.  Financial Accounting Standards Board.
·  
FASC.  FASB Accounting Standards Codification.
·  
Field.  An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of field, refer to Regulation S-X, Rule 4-10(a)(15).
·  
GAAP.  Accounting principles generally accepted in the United States.
·  
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which an entity owns a working interest.
·  
Lease Operating Expense (“LOE”).  All direct and allocated indirect costs of producing hydrocarbons after the completion of drilling.  Such costs include ad valorem taxes, labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.
·  
LIBOR.  London Interbank Offered Rate.
·  
MBbl.  One thousand Bbls.
·  
MBOE.  One thousand BOE.
·  
Mcf.  One thousand cubic feet, used in reference to gas.
·  
Mcf/D.  One Mcf per day.
·  
MMBOE.  One million BOE.
·  
MMcf.  One million cubic feet, used in reference to gas.
·  
Natural Gas Liquids (“NGLs”).  The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
·  
Net Acres or Net Wells. Gross acres or wells, as the case may be, multiplied by the working interest percentage owned by an entity.
·  
NYMEX. New York Mercantile Exchange.
·  
Oil.  Crude oil and condensate.
·  
Operator.  The entity responsible for the exploration, development, and production of a well or lease.
·  
Production Costs.  Costs incurred to operate and maintain wells and related equipment and facilities. For a complete definition of production costs, refer to Regulation S-X, Rule 4-10(a)(20).
·  
Production Margin.  Wellhead revenues less production costs.
·  
Productive Well.  An exploratory, development, or extension well that is not a dry well.
·  
Proved Oil and Gas Reserves.  Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  For a complete definition of proved oil and gas reserves, refer to Regulation S-X, Rule 4-10(a)(22).
·  
Recompletion.  The completion for production from an existing wellbore in another formation from that in which the well has been previously completed.
·  
Reliable Technology.  A grouping of one or more technologies (including computational methods) that have been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
·  
Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
·  
Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
·  
Undeveloped Oil and Gas Reserves.  Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  For a complete definition of undeveloped oil and gas reserves, refer to Regulation S-X, Rule 4-10(a)(31).
·  
Vanguard.  Vanguard Natural Resources, LLC, a publicly traded Delaware limited liability company, together with its subsidiaries.
·  
VNG.  Vanguard Natural Gas, LLC, a wholly-owned subsidiary of Vanguard.
·  
Working Interest.  An interest in an oil or gas lease that gives the owner the right to drill for and produce hydrocarbons on the leased acreage and requires the owner to pay a share of the production and development costs.
·  
Workover.  Operations on a producing well to restore or increase production.
 
 

 

 
 
Item 1. Unaudited Financial Statements
 
(in thousands, except unit amounts)
 
   
June 30,
   
December 31,
 
   
2011
   
2010
 
   
(unaudited)
       
ASSETS
 
Current assets:
           
   Cash and cash equivalents
  $ 2,695     $ 1,380  
   Accounts receivable - trade
    26,555       22,795  
   Derivatives
    855       2,604  
   Other
    1,602       470  
          Total current assets
    31,707       27,249  
                 
Properties and equipment, at cost - successful efforts method:
               
   Proved properties, including wells and related equipment
    860,724       857,999  
   Unproved properties
    5       17  
   Accumulated depletion, depreciation, and amortization
    (281,990 )     (259,575 )
      578,739       598,441  
   Other property and equipment
    1,735       1,327  
   Accumulated depreciation
    (738 )     (613 )
      997       714  
                 
Goodwill
    9,290       9,290  
Other intangibles, net
    2,860       3,012  
Derivatives
    -       836  
Other
    4,738       1,778  
          Total assets
  $ 628,331     $ 641,320  
                 
LIABILITIES AND PARTNERS' EQUITY
 
Current liabilities:
               
   Accounts payable:
               
      Trade
  $ 2,106     $ 2,103  
      Affiliate
    1,456       98  
   Accrued liabilities:
               
      Lease operating
    4,594       4,550  
      Development capital
    1,280       890  
      Interest
    225       298  
      Production taxes
    12,045       10,109  
   Derivatives
    10,752       3,530  
   Oil and natural gas revenues payable
    339       1,730  
   Credit agreement
    230,000       -  
   Other
    2,184       1,278  
          Total current liabilities
    264,981       24,586  
                 
Derivatives
    38,252       20,681  
Future abandonment cost, net of current portion
    13,305       13,080  
Deferred taxes
    23       11  
Credit agreement
    -       234,000  
Other
    412       -  
          Total liabilities
    316,973       292,358  
                 
Commitments and contingencies (see Note 11)
               
                 
Partners' equity:
               
   Limited partners - public, 24,565,529 and 24,417,542 common units issued
               
      and outstanding, respectively
    319,664       340,126  
   Limited partners - affiliates, 20,924,055 common units issued and outstanding
    (7,308 )     10,125  
   General partner - 504,851 general partner units issued and outstanding
    (515 )     (94 )
   Accumulated other comprehensive loss
    (483 )     (1,195 )
          Total partners' equity
    311,358       348,962  
          Total liabilities and partners' equity
  $ 628,331     $ 641,320  
 
The accompanying notes are an integral part of these consolidated financial statements.

 
 
1

 

(in thousands, except per unit amounts)
(unaudited)
 
   
Three months ended
   
Six months ended
 
   
June 30,
   
June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Revenues:
                       
   Oil
  $ 45,035     $ 35,957     $ 84,055     $ 71,967  
   Natural gas
    6,268       6,288       12,061       14,910  
   Natural gas liquids
    3,085       2,537       5,424       6,480  
   Marketing
    34       77       81       147  
   Commodity derivative fair value gain (loss) - realized
    (1,453 )     1,324       (4,798 )     617  
   Commodity derivative fair value gain (loss) - unrealized
    23,529       15,264       (24,596 )     21,443  
Total revenues
    76,498       61,447       72,227       115,564  
                                 
Expenses:
                               
   Production:
                               
      Lease operating
    10,737       10,262       18,747       21,639  
      Production taxes
    5,703       4,891       10,025       10,199  
   Depletion, depreciation, amortization and accretion
    11,454       12,839       23,068       25,690  
   Exploration
    -       55       -       76  
   General and administrative
    4,929       3,543       8,259       7,271  
Total expenses
    32,823       31,590       60,099       64,875  
                                 
Operating income
    43,675       29,857       12,128       50,689  
                                 
Other income (expenses):
                               
   Interest
    (2,214 )     (2,307 )     (4,384 )     (4,684 )
   Interest rate derivative fair value loss - realized
    (441 )     (969 )     (1,413 )     (1,951 )
   Interest rate derivative fair value gain (loss) - unrealized
    228       (45 )     623       (104 )
   Other
    8       13       9       38  
Total other expenses
    (2,419 )     (3,308 )     (5,165 )     (6,701 )
                                 
Income before income taxes
    41,256       26,549       6,963       43,988  
Income tax provision
    (83 )     (85 )     (195 )     (111 )
                                 
Net income
  $ 41,173     $ 26,464     $ 6,768     $ 43,877  
                                 
Net income allocation (see Note 8):
                               
      Limited partners' interest in net income
  $ 40,721     $ 26,173     $ 6,694     $ 43,394  
      General partner's interest in net income
  $ 452     $ 291     $ 74     $ 483  
                                 
Net income per common unit:
                               
      Basic
  $ 0.90     $ 0.58     $ 0.15     $ 0.96  
      Diluted
  $ 0.90     $ 0.58     $ 0.15     $ 0.96  
                                 
Weighted average common units outstanding:
                               
      Basic
    45,484       45,342       45,478       45,320  
      Diluted
    45,484       45,342       45,478       45,333  

The accompanying notes are an integral part of these consolidated financial statements.

 
 
2

 

(in thousands, except per unit amounts)
(unaudited)
 
                           
Other
   
Total
 
   
Limited Partners
   
General Partner
   
Comprehensive
   
Partners'
 
   
Units
   
Amount
   
Units
   
Amount
   
Loss
   
Equity
 
                                     
 Balance at January 1, 2010
    45,285     $ 409,777       505     $ (353 )   $ (3,420 )   $ 406,004  
     Net contributions from owners
    -       (2 )     -       935       -       933  
     Non-cash equity-based compensation
    -       1,323       -       8       -       1,331  
     Vesting of phantom units
    57       -       -       -       -       -  
     Other
    -       (216 )     -       (3 )     -       (219 )
     Cash distributions to unitholders ($2.0375 per unit)
    -       (92,353 )     -       (1,029 )     -       (93,382 )
     Components of comprehensive income:
                                               
     Net income attributable to unitholders
    -       31,722       -       348       -       32,070  
     Change in deferred hedge loss on interest rate swaps,
                                               
     net of tax of $7
    -       -       -       -       2,225       2,225  
     Total comprehensive income
                                            34,295  
 Balance at December 31, 2010
    45,342       350,251       505       (94 )     (1,195 )     348,962  
     Non-cash equity-based compensation
    148       440       -       5       -       445  
     Cash distributions to unitholders ($0.50 per unit to
     unitholders of record February 7, 2011 and $0.49 per unit
     to unitholders of record May 6, 2011)
    -       (45,029 )     -       (500 )     -       (45,529 )
     Components of comprehensive income:
                                               
     Net income attributable to unitholders
    -       6,694       -       74       -       6,768  
     Settlement of interest rate cash flow hedges in
                                               
     comprehensive loss
    -       -       -       -       712       712  
     Total comprehensive income
                                            7,480  
 Balance at June 30, 2011
    45,490     $ 312,356       505     $ (515 )   $ (483 )   $ 311,358  
 
The accompanying notes are an integral part of these consolidated financial statements.

 
 
3

 

(in thousands)
(unaudited)
   
Six months ended
 
   
June 30,
 
   
2011
   
2010
 
Cash flows from operating activities:
           
   Net income
  $ 6,768     $ 43,877  
   Adjustments to reconcile net income to net cash provided
               
      by operating activities:
               
         Depletion, depreciation, amortization and accretion
    23,068       25,690  
         Deferred taxes
    44       2  
         Non-cash exploration expense
    -       35  
         Non-cash equity-based compensation expense
    445       1,041  
         Non-cash derivative loss (gain)
    28,641       (16,471 )
         Other
    762       1,750  
         Changes in operating assets and liabilities:
               
            Accounts receivable
    (4,910 )     15,046  
            Other current assets
    (139 )     66  
            Other assets
    -       (15 )
            Accounts payable
    1,153       (1,102 )
            Other current liabilities
    2,871       3,695  
Net cash provided by operating activities
    58,703       73,614  
                 
Cash flows from investing activities:
               
   Purchase of other property and equipment
    (408 )     -  
   Acquisition of oil and natural gas properties
    -       (279 )
   Deposits and prepayments of oil and natural gas properties
    (4,738 )     -  
   Development of oil and natural gas properties
    (2,713 )     (2,843 )
Net cash used in investing activities
    (7,859 )     (3,122 )
                 
Cash flows from financing activities:
               
   Proceeds from credit agreement
    38,000       10,000  
   Payments of credit agreement
    (42,000 )     (20,000 )
   Cash distributions to unitholders
    (45,529 )     (47,536 )
   Other
    -       (6 )
Net cash used in financing activities
    (49,529 )     (57,542 )
                 
Increase in cash and cash equivalents
    1,315       12,950  
Cash and cash equivalents, beginning of period
    1,380       1,754  
Cash and cash equivalents, end of period
  $ 2,695     $ 14,704  
 
The accompanying notes are an integral part of these consolidated financial statements.

 
 
4

 
ENCORE ENERGY PARTNERS LP
(unaudited)

Note 1. Description of Business

Encore Energy Partners LP (together with its subsidiaries, “ENP”) is engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States.  Encore Energy Partners GP LLC (the “General Partner” or “ENP GP”), a Delaware limited liability company which is a wholly-owned subsidiary of Vanguard Natural Resources, LLC, (together with its subsidiaries, “Vanguard” or “VNR”), a publicly traded Delaware limited liability company, serves as ENP’s general partner and Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, owns and operates ENP’s properties.  ENP’s properties and oil and natural gas reserves are located in four operating areas:

·  
the Big Horn Basin in Wyoming and Montana;
·  
the Permian Basin in West Texas and New Mexico;
·  
the Williston Basin in North Dakota and Montana; and
·  
the Arkoma Basin in Arkansas and Oklahoma.

On December 31, 2010, Denbury Resources Inc. (together with its subsidiaries, “Denbury”), a publicly traded Delaware corporation, sold its ownership interests in ENP and the General Partner to Vanguard Natural Gas, LLC (“VNG”), a wholly-owned subsidiary of Vanguard, for $300.0 million in cash and approximately 3.14 million Vanguard common units (the “Vanguard Acquisition”).  Denbury sold the entity which owns 100 percent of the General Partner and approximately 20.9 million ENP common units, or approximately 46.1 percent of ENP’s outstanding common units.  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 VNG through a unit for unit exchange.  See Note 13.  Subsequent Events for further discussion.

Note 2.  Summary of Significant Accounting Policies

(a)  
Basis of Presentation

ENP’s consolidated financial statements include the accounts of its wholly-owned subsidiaries.  All material intercompany balances and transactions have been eliminated in consolidation.

In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, ENP’s financial position as of June 30, 2011, results of operations for the three and six months ended June 30, 2011 and 2010, and cash flows for the six months ended June 30, 2011 and 2010.  All adjustments are of a normal recurring nature.  These interim results are not necessarily indicative of results for an entire year.

Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC.  Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in ENP’s 2010 Annual Report on Form 10-K.

(b)  
New Pronouncements Issued But Not Yet Adopted

In May 2011, the FASB issued authoritative guidance to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”).  The guidance changes the wording used to describe the requirements in GAAP for measuring fair value and disclosures about fair value.  The guidance includes clarification of the application of existing fair value measurements and disclosure requirements related to a) the application of highest and best use and valuation premise concepts; b) measuring the fair value of an instrument classified in a reporting entity’s stockholders’ equity, and c) disclosure of quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy.  Additionally, the guidance changes particular principles or requirements for measuring fair value and disclosing information about fair value measurements related to a) measuring the fair value of financial instruments that are managed within a portfolio, b) application of premiums and discounts in a fair value measurement, and c) additional requirements to expand the disclosures about fair value measurements.  The guidance is effective for each reporting entity for interim and annual periods beginning after December 15, 2011.  The adoption of this standard is not expected to have any impact on our results of operations, cash flows or financial position.

 
5

 
In June 2011, the FASB issued authoritative guidance intended to improve the comparability, consistency, and transparency of financial reporting.  The guidance is also intended to increase the prominence of items reported in other comprehensive income and to facilitate convergence of GAAP and IFRS by eliminating the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity.  Under this guidance, entities are given two options for presenting other comprehensive income.  The statement of other comprehensive income can be included with the statement of net income, which together will comprise the statement of total comprehensive income. Alternatively, the statement of other comprehensive income can be presented separate from the statement of net income.  However, the guidance requires that the statement of other comprehensive income should immediately follow the statement of net income.  The guidance also requires entities to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement where the components of net income and the components of other comprehensive income are presented.  The guidance is effective for each reporting entity for interim and annual periods beginning after December 15, 2011.  As this guidance provides only presentation requirements, the adoption of this standard is not expected to have any impact on our results of operations, cash flows or financial position.

(c)  
Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and natural gas liquids reserves and related cash flow estimates used in impairment tests of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and natural gas liquids revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization, and accretion. Actual results could differ from those estimates.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the current period presentation.  These reclassifications did not impact our reported net income or partners’ equity.

Note 3.  Proved Properties

Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:
 
   
June 30,
   
December 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Proved leasehold costs
  $ 609,937     $ 609,910  
Wells and related equipment - completed
    250,743       248,017  
Wells and related equipment - in process
    44       72  
   Total proved properties
  $ 860,724     $ 857,999  

Note 4.  Fair Value Measurements

The following table sets forth ENP’s book value and estimated fair value of financial instruments as of the dates indicated:
 
6

 
 
   
June 30, 2011
   
December 31, 2010
 
   
Book
   
Fair
   
Book
   
Fair
 
   
Value
   
Value
   
Value
   
Value
 
   
(in thousands)
 
Assets:
                       
Cash and cash equivalents
  $ 2,695     $ 2,695     $ 1,380     $ 1,380  
Accounts receivable - trade
    26,555       26,555       22,795       22,795  
Commodity derivative contracts
    855       855       15,682       15,682  
Liabilities:
                               
Accounts payable - trade
    2,106       2,106       2,103       2,103  
Accounts payable - affiliate
    1,456       1,456       98       98  
Credit Agreement
    230,000       230,000       234,000       232,517  
Commodity derivative contracts
    48,185       48,185       35,011       35,011  
Interest rate swaps
    819       819       1,442       1,442  
 
       The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments.  The book value of ENP’s five year credit agreement (as amended, the “Credit Agreement”) approximates fair value as the interest rate is variable; however, ENP adjusted the estimated fair value for estimated nonperformance risk of approximately $1.5 million at December 31, 2010.  The nonperformance risk was determined using industry credit default swaps.  No adjustment for nonperformance risk was made at June 30, 2011 as the Credit Agreement matures within one year and any adjustment would be considered insignificant.  Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets.

Derivative Policy

ENP uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production.  These arrangements are structured to reduce ENP’s exposure to commodity price decreases, but they can also limit the benefit ENP might otherwise receive from commodity price increases.  ENP’s risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions, all of which are currently lenders under ENP’s Credit Agreement.  ENP also uses derivative instruments in the form of interest rate swaps, which hedge risks related to interest rate fluctuation.

ENP applies the provisions of the “Derivatives” topic of the FASC, 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, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss within partners’ equity 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.

Effective January 1, 2011, ENP elected to de-designate its outstanding interest rate swaps as cash flow hedges and from that date began recognizing changes in the fair market value of its interest rate swaps in the Consolidated Statements of Operations. The net unrealized gain related to the de-designated cash flow hedges is reported in accumulated other comprehensive loss and is being reclassified to earnings in the month in which the transactions settle.  Prior to January 1, 2011, ENP elected to designate its outstanding interest rate swaps as cash flow hedges.  The effective portion of the mark-to-market gain or loss on these derivative instruments was recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and was reclassified into earnings in the same period in which the hedged transaction affected earnings.  Any ineffective portion of the mark-to-market gain or loss was recognized in earnings and included in “Interest rate derivative fair value gain (loss) - unrealized” in the accompanying Consolidated Statements of Operations.

ENP has elected not to designate its portfolio of commodity derivative contracts as hedges.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in “Commodity derivative fair value gain (loss) - unrealized” in the accompanying Consolidated Statements of Operations.

 
7

 
Commodity Derivative Contracts

ENP manages commodity price risk with swap contracts, put contracts, collars, three-way collars, put spreads and swaptions.  Swap contracts provide a fixed price for a notional amount of sales volumes.  Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price.  Collars provide a floor price for a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. Three-way collar contracts combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price of NYMEX West Texas Intermediate (“WTI”) crude oil drops below the price of the short put. This allows us to settle for WTI market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. We temporarily enter into put spreads which combine a long put with a short put, with the intention of adding a short call to convert them into three-way collars.  Under swaption agreements, we provide options to counterparties to extend swap contracts into subsequent years.

In January 2011, we elected to monetize all of our $65 and $70 oil puts for 2011 and 2012 and used the proceeds to raise the floor price to $80 on a smaller volume of oil in 2012 and also slightly raise the swap price for oil in 2011 and 2012. During the second quarter of 2011, we entered into a NYMEX WTI crude oil derivative three-way collar contract, which provides that if the market price falls below the short put fixed price, we will receive the market price plus $20 per barrel.

The following tables summarize ENP’s open commodity derivative contracts as of June 30, 2011:

   
July 1, -
December 31, 2011
   
Year
2012
   
Year
2013
   
Year
2014
 
Gas Positions:
                       
Fixed Price Swaps:
                       
Notional Volume (MMBtu)
    1,877,168       3,733,932       3,358,000        
Fixed Price ($/MMBtu)
  $ 6.06     $ 5.70     $ 5.12     $  
Puts:
                               
Notional Volume (MMBtu)
    625,232       328,668              
Fixed Price ($/MMBtu)
  $ 6.31     $ 6.76     $     $  
Total Gas Positions:
                               
Notional Volume (MMBtu)
    2,502,400       4,062,600       3,358,000        
                                 
Oil Positions:
                               
Fixed Price Swaps:
                               
Notional Volume (Bbls)
    279,340       984,540       1,295,750       1,168,000  
Fixed Price ($/Bbl)
  $ 82.90     $ 84.10     $ 88.95     $ 88.95  
Collars:
                               
Notional Volume (Bbls)
    345,920       475,800              
Floor Price ($/Bbl)
  $ 80.00     $ 74.23     $     $  
Ceiling Price ($/Bbl)
  $ 96.49     $ 90.98     $     $  
Three-way Collars:
                               
Notional Volume (Bbls)
    19,125                    
Floor Price ($/Bbl)
  $ 90.00     $     $     $  
Ceiling Price ($/Bbl)
  $ 102.35     $     $     $  
Put Sold ($/Bbl)
  $ 70.00     $     $     $  
Put Spreads to be converted to Three-Way Collars (1):
                               
Notional Volume (Bbls)
          45,750       45,625        
Floor Price ($/Bbl)
  $     $ 90.00     $ 90.00     $  
Put Sold ($/Bbl)
  $     $ 70.00     $ 70.00     $  
Total Oil Positions:
                               
Notional Volume (Bbls)
    644,385       1,506,090       1,341,375       1,168,000  

(1)  
On July 7, 2011, we sold $120 calls on 125 Bbl/day for 2012-2013, establishing a Three-Way Collar.

 
8

 
Swaptions

Options were provided to counterparties under swaption agreements to extend swaps into 2013 on 36,500 Bbls of oil at a fixed price of $105.00 per Bbl and into 2014 on 365,000 MMBtu of gas at a fixed price of $5.40 per MMBtu.
 
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.  The following table summarizes ENP’s open interest rate swap as of June 30, 2011, which was entered into with Bank of America, N.A.:
 
   
Notional
   
Fixed
 
Floating
Term
 
Amount
   
Rate
 
Rate
   
(in thousands)
         
July 1, 2011 - March 7, 2012
  $ 50,000       2.4200 %
 1-month LIBOR
 
Current Period Impact

ENP recognizes realized and unrealized commodity and interest rate derivative fair value gains and losses related to: (1) changes in the fair market value of derivative contracts not designated as hedges; (2) premium amortization; (3) receipts and settlements on derivative contracts not designated as hedges; (4) settlements of de-designated interest rate hedges; and (5) the ineffectiveness of derivative contracts designated as hedges prior to January 1, 2011.  The following table summarizes the components of our realized and unrealized commodity and interest rate derivative fair value gains and losses for the periods indicated:
 
 
Location of Gain (Loss)
 
Three months ended June 30,
   
Six months ended June 30,
 
 
Recognized in Income
 
2011
   
2010
   
2011
   
2010
 
     
(in thousands)
   
(in thousands)
 
Realized gains (losses):
                         
  Premium amortization
Commodity derivative fair value loss - realized
  $ -     $ (2,448 )   $ (3,953 )   $ (4,868 )
  Receipts, net of settlements
Commodity derivative fair value gain (loss) - realized
    (1,453 )     3,772       (845 )     5,485  
  Receipts, net of settlements
Interest rate derivative fair value loss - realized
    (441 )     (969 )     (1,413 )     (1,951 )
      $ (1,894 )   $ 355     $ (6,211 )   $ (1,334 )
Unrealized gains (losses):
                                 
  Mark-to-market gain (loss)
Commodity derivative fair value gain (loss) - unrealized
  $ 23,529     $ 15,264     $ (24,596 )   $ 21,443  
  Mark-to-market gain
Interest rate derivative fair value gain - unrealized
    228       -       623       -  
  Ineffectiveness on interest rate swaps
Interest rate derivative fair value loss - unrealized
    -       (45 )     -       (104 )
      $ 23,757     $ 15,219     $ (23,973 )   $ 21,339  
Total gains (losses):
                                 
  Commodity derivatives
    $ 22,076     $ 16,588     $ (29,394 )   $ 22,060  
  Interest rate derivatives
      (213 )     (1,014 )     (790 )     (2,055 )
      $ 21,863     $ 15,574     $ (30,184 )   $ 20,005  
 
Accumulated Other Comprehensive Loss

At June 30, 2011 and December 31, 2010, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, on ENP’s interest rate swaps of $0.5 million and $1.2 million, respectively.  During the twelve months ending June 30, 2012, ENP expects to reclassify $0.5 million of deferred losses associated with its interest rate swaps from accumulated other comprehensive loss to realized interest rate derivative fair value gain (loss).  The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred losses recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheets due to fluctuations in interest rates.

Tabular Disclosures of Fair Value Measurements

Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following summarizes the fair value of derivatives outstanding on a gross basis as of the dates indicated (in thousands):
 
 
9

 
 
 
Asset Derivatives
 
Liability Derivatives
 
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
     
June 30, 2011
   
December 31, 2010
     
June 30, 2011
   
December 31, 2010
 
Derivatives not designated as hedges
                           
Commodity derivative contracts
 Derivatives - current
  $ 11,216     $ 10,196  
 Derivatives - current
  $ 20,295     $ 9,906  
Interest rate swaps
 Derivatives - current
    -       -  
 Derivatives - current
    819       -  
Commodity derivative contracts
 Derivatives - noncurrent
    4,975       5,486  
 Derivatives - noncurrent
    43,226       25,105  
Total derivatives not designated as hedges
    $ 16,191     $ 15,682       $ 64,340     $ 35,011  
                                     
Derivatives designated as hedges
                                   
Interest rate swaps
 Derivatives - current
  $ -     $ -  
 Derivatives - current
  $ -     $ 1,216  
Interest rate swaps
 Derivatives - noncurrent
    -       -  
 Derivatives - noncurrent
    -       226  
Total derivatives designated as hedges
    $ -     $ -       $ -     $ 1,442  
Total derivatives
    $ 16,191     $ 15,682       $ 64,340     $ 36,453  
 
The following tables summarize the effect of derivative instruments designated as hedges prior to January 1, 2011 on the Consolidated Statements of Operations for the periods indicated (in thousands):
 
   
Amount of Gain (Loss) Recognized in
   
Amount of Gain (Loss) Recognized in
 
   
Accumulated OCI (Effective Portion)
   
Accumulated OCI (Effective Portion)
 
   
Three months ended June 30,
   
Six months ended June 30,
 
Derivatives Designated as Hedges
 
2011
   
2010
   
2011
   
2010
 
Interest rate swaps
  $ (162 )   $ 311     $ (712 )   $ 1,135  

   
Amount of Loss Recognized
   
Amount of Loss Recognized
 
   
in Income as Ineffective
   
in Income as Ineffective
 
   
Three months ended June 30,
   
Six months ended June 30,
 
Location of Loss Recognized in Income as Ineffective
 
2011
   
2010
   
2011
   
2010
 
Derivative fair value loss
  $ -     $ (45 )   $ -     $ (104 )
 
Fair Value Hierarchy
 
The FASC established a fair value hierarchy that prioritizes the inputs used to measure fair value.  The three levels of the fair value hierarchy are as follows:

·  
Level 1 – Unadjusted quoted prices are available in active markets for identical assets or liabilities.
·  
Level 2 – Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.
·  
Level 3 – Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.
 
 
As required by FASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Our commodity derivative instruments consist of oil and natural gas swap contracts, put contracts and collars. We estimate the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest rate swap market data. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows. We have classified the fair values of all of our derivative contracts as Level 2.
 
10

 
The following table sets forth ENP’s assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011:
 
         
Fair Value Measurements at Reporting Date Using
 
              Quoted Prices in          
         
Active Markets for
   
Significant Other
   
Significant
 
         
Identical Assets
   
Observable Inputs
   
Unobservable Inputs
 
Description
 
Asset (Liability)
   
(Level 1)
   
(Level 2)
   
(Level 3)
 
   
(in thousands)
 
Oil derivative contracts - swaps
  $ (47,921 )   $ -     $ (47,921 )   $ -  
Oil derivative contracts - floors and caps
    (8,037 )     -       (8,037 )     -  
Natural gas derivative contracts - swaps
    6,699       -       6,699       -  
Natural gas derivative contracts - floors
    1,929       -       1,929       -  
Interest rate swaps
    (819 )     -       (819 )     -  
   Total
  $ (48,149 )   $ -     $ (48,149 )   $ -  

The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for the six months ended June 30, 2011:
 
   
Fair Value Measurements Using Significant
 
   
Unobservable Inputs (Level 3)
 
   
Oil
   
Natural Gas
       
   
Derivative Contracts -
       Derivative Contracts -
 
 
   
Floors and Caps
   
Floors and Caps
   
Total
 
   
(in thousands)
 
Balance at January 1, 2011
  $ (3,666 )   $ 3,067     $ (599 )
Transfers out of level 3 *
    3,666       (3,067 )     599  
Balance at June 30, 2011
  $ -     $ -     $ -  
                         
*Transferred from Level 3 to Level 2 due to a change in management's assessment of the valuation methodology and its placement within the fair value hierarchy levels. The company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer. Management's change in policy occurred on January 1, 2011.
 

Note 5. Asset Retirement Obligations

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal.  The following table summarizes the changes in ENP’s asset retirement obligations for the six months ended June 30, 2011 (in thousands):
 
Future abandonment liability at January 1, 2011
  $ 13,838  
   Liabilities added during the current period
    1  
   Accretion of discount
    375  
Total future abandonment costs at June 30, 2011
    14,214  
Less: current obligations
    (909 )
Long-term future abandonment liability at June 30, 2011
  $ 13,305  
 
As of June 30, 2011, $13.3 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.9 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheet.  Approximately $5.2 million of the long-term future abandonment liability represents the estimated cost for decommissioning the Elk Basin natural gas processing plant near Powell, Wyoming.

 
11

 
Note 6. Credit Agreement

ENP is a party to a five-year Credit Agreement dated March 7, 2007 (as amended, the “ENP Credit Agreement”).  The Credit Agreement matures on March 7, 2012; therefore, all outstanding borrowings under the Credit Agreement are reflected as a current liability at June 30, 2011.  In July 2011, Vanguard began the syndication of a new credit facility that would retire all of the outstanding debt of ENP upon the consummation of the proposed merger with Vanguard.  In the event that the merger is not consummated, we will continue to evaluate our options which, based on discussions with lenders, include extending the term of the ENP Credit Agreement or refinancing under a new revolving credit facility.

In December 2010, ENP amended the Credit Agreement to, among other things, amend the definition of “Change of Control” to eliminate references to the “Selling Parties” and include change of control covenants that require the acceleration of payments upon (1) the failure of Vanguard to continue to control our general partner, (2) the acquisition by any person or group, directly or indirectly, of equity interests representing more than 35% of the total voting power in Vanguard, or (3) the occupation of a majority of the seats on the board of directors of Vanguard by persons who were neither (x) nominated by the board of directors of Vanguard nor (y) appointed by directors so nominated.  This amendment also modifies the covenant governing transactions with affiliates to eliminate all references to the “Selling Parties” and instead reference transactions with Vanguard, VNG, and their subsidiaries.

The Credit Agreement provides for revolving credit loans to be made to ENP from time to time and letters of credit to be issued from time to time for the account of ENP or any of its restricted subsidiaries.  The aggregate amount of the commitments of the lenders under the Credit Agreement is $475.0 million.  Availability under the Credit Agreement is subject to a borrowing base of $400.0 million, which is redetermined semi-annually and upon requested special redeterminations.  As of June 30, 2011, there were $230.0 million of outstanding borrowings and $170.0 million of borrowing capacity under the Credit Agreement.

ENP incurs a quarterly commitment fee at a rate of 0.5 percent per year on the unused portion of the Credit Agreement.

Obligations under the Credit Agreement are secured by a first-priority security interest in substantially all of ENP’s proved oil and natural gas reserves and in the equity interests of its restricted subsidiaries.  In addition, obligations under the Credit Agreement are guaranteed by ENP’s restricted subsidiaries.  Obligations under the Credit Agreement are non-recourse to Vanguard.

Loans under the Credit Agreement are subject to varying rates of interest based on (1) amount outstanding in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan.  Eurodollar loans under the Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the 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 Outstanding Borrowings to Borrowing Base
Eurodollar Loans
Base Rate Loans
Less than .50 to 1
2.250%
1.250%
Greater than or equal to .50 to 1 but less than .75 to 1
2.500%
1.500%
Greater than or equal to .75 to 1 but less than .90 to 1
2.750%
1.750%
Greater than or equal to .90 to 1
3.000%
2.000%

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 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) except 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 Credit Agreement.  Borrowings under the Credit Agreement may be repaid from time to time without penalty.

The Credit Agreement contains several restrictive covenants including, among others, the following:
 
 
12

 

·  
a prohibition against incurring debt, subject to permitted exceptions;
·  
a prohibition against purchasing or redeeming partnership units, or prepaying indebtedness, subject to permitted exceptions;
·  
a restriction on creating liens on ENP’s assets and its restricted subsidiaries, subject to permitted exceptions;
·  
restrictions on merging and selling assets outside the ordinary course of business;
·  
restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;
·  
a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;
·  
a requirement that ENP maintain a ratio of consolidated current assets to consolidated current liabilities, as defined in the Credit Agreement which excludes the current portion of long term debt, of not less than 1.0 to 1.0;
·  
a requirement that ENP maintain a ratio of consolidated EBITDAX to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and
·  
a requirement that ENP maintain a ratio of consolidated funded debt to consolidated adjusted EBITDAX of not more than 3.5 to 1.0.

As of June 30, 2011, ENP was in compliance with all covenants of the Credit Agreement.

The Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within the applicable grace periods. 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 Credit Agreement to be immediately due and payable.

Note 7. Partners’ Equity and Distributions

Distributions

ENP’s partnership agreement requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in ENP’s partnership agreement) to its unitholders.  ENP’s available cash is its cash on hand at the end of a quarter after the payment of its expenses and the establishment of reserves for future capital expenditures and operational needs.  Distributions are not cumulative.  ENP distributes available cash to its unitholders in accordance with their ownership percentages.

The following table illustrates information regarding ENP’s distributions of available cash for the periods indicated:
 
     
Cash Distribution
         
 
 Date
 
Declared per
       
Total
   
 
Declared
 
Common Unit
 
Date Paid
   
Distribution
   
 2011
             
(in thousands)
 Quarter ended June 30
7/26/2011
  $ 0.4700  
8/12/2011
(a)
  $ 21,617  
(a)
 Quarter ended March 31
4/28/2011
  $ 0.4900  
5/13/2011
    $ 22,533    
                         
 2010
                       
 Quarter ended December 31
1/27/2011
  $ 0.5000  
2/14/2011
    $ 22,992    
 Quarter ended September 30
10/28/2010
  $ 0.5000       11/12/2010
 
  $ 22,923    
 Quarter ended June 30
7/29/2010
  $ 0.5000  
8/13/2010
    $ 22,923    
 Quarter ended March 31
4/30/2010
  $ 0.5000  
5/14/2010
    $ 22,923    
____________
(a)  
Represents the date the distribution is expected to be paid and the total amount of the distribution that is expected to be paid.

Note 8. Earnings Per Unit

ENP applies the provisions of the “Earnings Per Share” Topic 260 of the FASC, which requires earnings per unit to be calculated using the two-class method.  Under the two-class method of calculating earnings per unit, earnings are allocated to participating securities as if all earnings for the period had been distributed.  A participating security is any security that may participate in distributions with common units.  For purposes of calculating earnings per unit, general partner units, unvested restricted units and unvested phantom units in 2010 are considered participating securities.  Earnings per unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average common units outstanding.

The following table reflects the allocation of net income to ENP’s limited partners and earnings per unit computations for the periods indicated:
 
 
13

 
 
   
Three months ended
   
Six months ended
 
   
June 30,
   
June 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(in thousands, except per unit amounts)
 
Net income attributable to unitholders
  $ 41,173     $ 26,464     $ 6,768     $ 43,877  
                                 
Numerator:
                               
   Numerator for basic earnings per unit:
                               
      Net income attributable to unitholders
  $ 41,173     $ 26,464     $ 6,768     $ 43,877  
      Less: distributions earned by participating securities
    (248 )     (252 )     (500 )     (504 )
Plus: cash distributions in excess of (less than)
                         
         income allocated to the general partner
    (204 )     (39 )     426       21  
      Net income allocated to limited partners
  $ 40,721     $ 26,173     $ 6,694     $ 43,394  
                                 
Denominator:
                               
   Denominator for basic earnings per unit:
                               
      Weighted average common units outstanding
    45,484       45,342       45,478       45,320  
      Effect of dilutive phantom units
    -       -       -       13  
   Denominator for diluted earnings per unit
    45,484       45,342       45,478       45,333  
                                 
Net income per common unit:
                               
   Basic
  $ 0.90     $ 0.58     $ 0.15     $ 0.96  
   Diluted
  $ 0.90     $ 0.58     $ 0.15     $ 0.96  
 
Note 9. Unit-Based Compensation Plans

Long-Term Incentive Plan

In September 2007, the board of directors of the General Partner adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards.  All employees, consultants, and directors of the General Partner and its affiliates who perform services for or on behalf of ENP and its subsidiaries are eligible to be granted awards under the LTIP.  The LTIP is administered by the board of directors of the General Partner or a committee thereof, referred to as the plan administrator.  To satisfy common unit awards under the LTIP, ENP may acquire common units in the open market, use common units owned by the General Partner, or use common units acquired by the General Partner from ENP or from any other person.

The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000.  In January and February 2011, ENP issued 140,007 restricted units under the LTIP to Vanguard field employees performing services on ENP’s properties. These awards vest equally over a four year period, but have distribution equivalent rights that provide the employees with a bonus equal to the distribution on unvested units. The fair value of these units was approximately $3.1 million on the date of grant.

In February 2011, ENP issued 7,980 units under the LTIP to three members of the Board of Directors which will vest within one year, but have distribution equivalent rights that provide the Board members with a bonus equal to the distribution on unvested units.  The fair value of these units was approximately $0.2 million on the date of grant.
 
These common units and restricted units were granted as partial consideration for services to be performed under employment contracts and thus will be subject to accounting for these grants under ASC Topic 718. The fair value of restricted units issued is determined based on the fair market value of common units on the date of the grant. This value is amortized over the vesting period as referenced above. A summary of the status of the non-vested units as of June 30, 2011 is presented below:
 
 
  Number of 
Non-vested Units
 
Weighted Average
Grant Date Fair Value
 
Non-vested units at January 1, 2011
 
$
 
Granted
147,987
 
22.25
 
Forfeited
 
$
 
Vested
 
$
 
Non-vested units at June 30, 2011
147,987
 
$
22.25
 
 
14

 
As of June 30, 2011, there was approximately $2.8 million of unrecognized compensation cost related to non-vested restricted units, which is expected to be recognized over a period of 2.6 years. The Consolidated Statements of Operations reflects non-cash compensation of $0.2 million and $0.4 million in “General and administrative expense” for the three and six months ended June 30, 2011, respectively.  As of June 30, 2011, there were 927,013 common units available for issuance under the LTIP.

Phantom Units.  As a result of the change of control of the General Partner in conjunction with the merger of EAC with and into Denbury on March 9, 2010, all 56,250 of ENP’s outstanding phantom units vested and were settled in an equal number of ENP’s common units.  The acceleration of the phantom unit vesting resulted in the recognition of the remaining unrecognized unit-based compensation expense of approximately $0.7 million during the six months ended June 30, 2010, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.  The fair value of these phantom units was approximately $1.2 million on March 9, 2010.  As of June 30, 2011, there were no outstanding phantom units.

Note 10. Comprehensive Income

The components of comprehensive income were as follows for the periods indicated:
 
   
Three months ended
   
Six months ended
 
   
June 30,
   
June 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(in thousands)
 
Net income
  $ 41,173     $ 26,464     $ 6,768     $ 43,877  
Change in deferred hedge loss on interest rate swaps
    162       658       712       816  
     Comprehensive income
  $ 41,335     $ 27,122     $ 7,480     $ 44,693  
 
Note 11. Commitments and Contingencies

ENP is a party to ongoing legal proceedings in the ordinary course of business.  The General Partner’s management does not believe the result of these proceedings will have a material adverse effect on ENP’s business, financial condition, results of operations, liquidity, or ability to pay distributions.

Additionally, the following pending litigation is outstanding related to the proposed merger with Vanguard.  On March 29, 2011, John O’Neal, a purported unitholder of ENP filed a class action complaint in the 125th Judicial District of Harris County, Texas on behalf of unitholders of ENP.  Similar actions were filed on April 4, 2011 by Jerry P. Morgan and on April 5, 2011 by Herbert F. Rower in other Harris County district courts.  The O’Neal, Morgan, and Rower actions were consolidated on June 5, 2011 as John O’Neal v. Encore Energy Partners, L.P., et al., Case Number 2011-19340, which is pending in the 125th Judicial District Court of Harris County.  On July 13, 2011, plaintiffs in the consolidated O’Neal action filed an amended putative class action complaint alleging breaches of fiduciary duty and aiding and abetting breach of fiduciary duty claims against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, VNG, Vanguard Acquisition Company, LLC, and Vanguard.  Plaintiffs seek an injunction prohibiting the merger from going forward and compensatory damages if the merger is consummated.  The defendants named in the Texas lawsuits intend to defend vigorously against them.

On April 5, 2011, Stephen Bushansky, filed a putative class action complaint in the Delaware Court of Chancery on behalf of the unitholders of ENP.  Another purported unitholder of ENP, William Allen, filed a similar action in the same court on April 14, 2011.  The Bushansky and Allen actions have been consolidated under the caption In re: Encore Energy Partners LP Unitholder Litigation, C.A. No. 6347-VCP.  On June 21, 2011, those plaintiffs jointly filed a consolidated class action complaint naming as defendants ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, and Vanguard. That putative class action complaint alleges, among other things, that defendants breached contractual duties owed to ENP’s unitholders under the applicable partnership agreement by proposing and recommending the proposed merger.  Plaintiffs seek an injunction prohibiting the proposed merger from going forward and compensatory damages if the proposed merger is consummated.  In response, Vanguard has filed a motion to dismiss and it intends to defend vigorously against this lawsuit.

Vanguard and ENP cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of this filing, nor can Vanguard and ENP predict the amount of time and expense that will be required to resolve these lawsuits. Vanguard, ENP and the other defendants named in these lawsuits intend to defend vigorously against these and any other actions.

 
15

 
Additionally, ENP has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, the Credit Agreement, derivative contracts, operating leases, and development commitments.  Please read “Capital Commitments, Capital Resources, and Liquidity – Capital commitments – Contractual obligations” included in “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2010 Annual Report on Form 10-K for ENP’s contractual obligations.

Note 12. Related Party Transactions

Administrative Services Agreement

ENP does not have any employees.  The employees supporting the operations of ENP were: the employees of EAC prior to March 2010, the employees of Denbury from March 2010 to December 31, 2010, and the employees of VNG on and after December 31, 2010 in connection with the Vanguard Acquisition.  During 2010, Encore Operating, L. P. (“Encore Operating”), a wholly-owned subsidiary of Denbury, provided administrative services for ENP, including accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement.  In addition, Encore Operating provided all personnel, facilities, goods, and equipment necessary to perform these services which were not otherwise provided for by ENP.  Encore Operating was not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constituted gross negligence or willful misconduct.  On December 31, 2010, Encore Operating’s duties under the administrative services agreement were assigned to VNG pursuant to the Vanguard Acquisition.

From April 1, 2009 to March 31, 2010, the administrative fee was $2.02 per BOE of ENP’s production, and from April 1, 2010 through March 31, 2011, the fee was increased to $2.06 per BOE.  Effective April 1, 2011, the administrative fee decreased to $2.05 per BOE of ENP’s production.  ENP also reimbursed Encore Operating for actual third-party expenses incurred on ENP’s behalf.  In addition, Encore Operating was 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.  Pursuant to the Vanguard Acquisition, VNG received the same fees and reimbursements for services performed during the first half of 2011 as previously received by Encore Operating.

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 ENP acquires additional assets, VNG 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 the General Partner upon the recommendation of its conflicts committee; and
·  
otherwise as agreed upon by VNG and the General Partner, with the approval of the conflicts committee of the board of directors of the General Partner.

ENP reimburses the ultimate parent of the General Partner for any state, income, franchise, or similar tax incurred by it resulting from the inclusion of ENP in consolidated tax returns of the ultimate parent of the General Partner as required by applicable law.  The amount of any such reimbursement is limited to the tax that ENP would have incurred had it not been included in a combined group with the ultimate parent of the General Partner.

Administrative fees (including COPAS recovery) paid pursuant to the administrative services agreement are included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations.  The reimbursements of actual third-party expenses incurred on ENP’s behalf are also included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations.  The following table illustrates amounts paid by ENP pursuant to the administrative service agreement for the periods indicated:
 
 
16

 
   
Three months ended
   
Six months ended
 
   
June 30,
   
June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Administrative fees
  $ 1,560     $ 1,657     $ 3,148     $ 3,299  
COPAS recovery
    1,121       659       1,926       1,326  
Third Party Expenses
    1,442       553       3,297       3,315  
 
As of June 30, 2011 and December 31, 2010, ENP had accounts payable to Vanguard of $1.5 million and $0.1 million, respectively, which is reflected as “Accounts payable – affiliate” in the accompanying Consolidated Balance Sheets.
 
Distributions

Each quarter, ENP pays cash distributions with respect to operations in the previous quarter on all of its outstanding units, including those common units held by the General Partner and its affiliates, and pays cash distributions to the General Partner based upon its general partner interest.  On May 13, 2011, ENP paid cash distributions of approximately $22.5 million, of which $10.5 million was paid to the General Partner and its affiliates.  On February 14, 2011, ENP paid cash distributions of approximately $23.0 million, of which $10.7 million was paid to the General Partner and its affiliates.  On May 14, 2010, ENP paid cash distributions of approximately $22.9 million, of which $10.7 million was paid to the General Partner and its affiliates.  On February 12, 2010, ENP paid cash distributions of approximately $24.6 million, of which $11.5 million was paid to the General Partner and its affiliates.

Note 13. Subsequent Events

On June 22, 2011, pursuant to two Purchase and Sale Agreements (the “Purchase Agreements”), ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from a undisclosed seller.  ENP and Vanguard each agreed to purchase 50% of the Purchased Assets for $42.5 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.

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 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.  In addition, 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.

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 during the fourth quarter of 2011. On August 2, 2011, ENP and Vanguard filed a Registration Statement on Form S-4 with the SEC, which has not been declared effective.  The Registration Statement incorporates a joint proxy statement/prospectus which ENP and Vanguard plan to mail 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 July 26, 2011, the board of directors of the General Partner declared an ENP cash distribution for the second quarter of 2011 to unitholders of record as of the close of business on August 5, 2011 of $0.47 per unit or approximately $21.6 million of which $10.1 million is expected to be paid to the General Partner and its affiliates.  The distribution is expected to be paid to unitholders on or about August 12, 2011.
 
17

 
ENCORE ENERGY PARTNERS LP


The following discussion and analysis contains forward-looking statements, which give our current expectations or forecasts of future events.  Actual results could differ materially from those discussed in these forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” and elsewhere in our 2010 Annual Report on Form 10-K.  The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report.

Introduction

In this management’s discussion and analysis of financial condition and results of operations, the following are discussed and analyzed:

· Recent Developments
· Overview of Business
· Second Quarter 2011 Highlights
· Results of Operations
o  
Comparison of Quarter Ended June 30, 2011 to Quarter Ended June 30, 2010
o  
Comparison of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2010
· Capital Commitments, Capital Resources, and Liquidity
· Non-GAAP Financial Measure
· Critical Accounting Policies and Estimates

Recent Developments

On December 31, 2010, Denbury Resources Inc. (together with its subsidiaries, “Denbury”), a publicly traded Delaware corporation, sold its ownership interests in ENP and the General Partner to Vanguard Natural Gas, LLC (“VNG”), a wholly-owned subsidiary of Vanguard, for $300.0 million in cash and approximately 3.14 million Vanguard common units (the “Vanguard Acquisition”).  Denbury sold the entity which owns 100 percent of the General Partner and approximately 20.9 million ENP common units, or approximately 46.1 percent of ENP’s outstanding common units.

On June 22, 2011, pursuant to two Purchase and Sale Agreements (the “Purchase Agreements”), ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from an undisclosed seller.  ENP and Vanguard each agreed to purchase 50% of the Purchased Assets for $42.5 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.  The interests acquired by ENP have estimated total net proved reserves of 2.74 million barrels of oil equivalent, of which approximately 70% are oil and natural gas liquids reserves and are 100% proved developed.

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 VNG, through a unit-for-unit exchange.  Under the terms of the definitive agreement, ENP’s public unitholders would 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.  In addition, 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.

The completion of the merger is subject to approval by a majority of the outstanding ENP common units 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 during the fourth quarter of 2011. On August 2, 2011, ENP and Vanguard filed a Registration Statement on Form S-4 with the SEC, which has not been declared effective.  The Registration Statement incorporates a joint proxy statement/prospectus which ENP and Vanguard plan to mail 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.

 
18

 
Overview of Business

We are a Delaware limited partnership engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States.  Our primary business objective is to make quarterly cash distributions to our unitholders in accordance with our guideline as discussed in “Capital Commitments, Capital Resources, and Liquidity – Capital commitments – Distributions to unitholders.”  Our properties and oil and natural gas reserves are located in four operating areas:

· the Big Horn Basin in Wyoming and Montana;
· the Permian Basin in West Texas and New Mexico;
· the Williston Basin in North Dakota and Montana; and
· the Arkoma Basin in Arkansas and Oklahoma.

Second Quarter 2011 Highlights
 
Our financial and operating results for the second quarter of 2011 included the following:

·  
Our average realized oil price increased 31 percent to $90.90 per Bbl after consideration of a negative 11.4 percent ($11.66 per Bbl) oil differential to NYMEX as compared to $69.27 per Bbl and a negative 11.3 percent ($8.85 per Bbl) oil differential to NYMEX in the second quarter of 2010.  Our average realized natural gas price was $4.31 per Mcf for the second quarter 2011 as compared to $4.32 per Mcf in the second quarter of 2010.
·  
Our oil, natural gas and NGLs revenues increased 21 percent to $54.4 million as compared to $44.8 million in the second quarter of 2010.  Oil represented approximately 64 percent and 65 percent of our total production in the second quarter of 2011 and 2010, respectively.
·  
Average daily production volumes decreased three percent on a BOE basis from 8,841 BOE/D during the second quarter of 2010 to 8,534 BOE/D during the second quarter of 2011.
·  
Our production margin increased 28 percent to $37.9 million as compared to $29.6 million in the second quarter of 2010.  Total oil and natural gas wellhead revenues per BOE increased by 26 percent while total production expenses per BOE increased by 12 percent.  On a per BOE basis, our production margin increased 33 percent to $48.86 per BOE as compared to $36.82 per BOE for the second quarter of 2010.
·  
We invested $1.5 million in development and exploitation activities during the second quarter of 2011.
·  
Our net income was $41.2 million ($0.90 per common unit) as compared to a net income of $26.5 million ($0.58 per common unit) for the second quarter of 2010 primarily due to a $9.6 million increase in our oil, natural gas and NGLs revenues and a $8.3 million increase in mark-to-market gains on our commodity derivatives contracts.

See “Results of Operations” and “Capital Commitments, Capital Resources, and Liquidity” for additional discussion of these items.


 
19

 
ENCORE ENERGY PARTNERS LP
 
Results of Operations
 
Comparison of Quarter Ended June 30, 2011 to Quarter Ended June 30, 2010

Revenues.  The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:
 
   
Three months ended June 30,
   
Increase / (Decrease)
 
   
2011
   
2010
     $       %  
Revenues (in thousands):
                         
  Oil
  $ 45,035     $ 35,957