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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 March 31, 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 o    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        Smaller reporting company o
(Do not check if a smaller reporting company)  
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 May 9, 2011 45,481,604
 
 
 
 

 
INDEX

   
 
Page
 
 
 
 
 
 
 
 
 
 
                                  3
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


 
 

 
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;
 
·  
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 reports and registration statements filed from time to time with the SEC and (4) 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.

 
 

 
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 natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
·  
BOE/D.  One BOE per day.
·  
Completion.  The installation of permanent equipment for the production of hydrocarbons.
·  
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.
·  
Development Well.  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
·  
Dry Hole. An exploratory, development, or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural 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 producing oil or natural gas in another 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.
·  
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 natural gas.
·  
Mcf/D.  One Mcf per day.
·  
MMcf.  One million cubic feet, used in reference to natural 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 our wells and related equipment and facilities. For a complete definition of production costs, please refer to Regulation S-X, Rule 4-10(a)(20).
·  
Production Margin.  Wellhead revenues less production costs.
·  
Productive Well.  A well capable of producing hydrocarbons in commercial quantities, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
·  
Proved Developed 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, is acreage that is allocated or assignable to producing wells or wells capable of production. For a complete definition of developed oil and gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(6).
·  
Proved 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 the SEC’s Regulation S-X, Rule 4-10(a)(22).
·  
Proved Undeveloped 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 the SEC’s Regulation S-X, Rule 4-10(a)(31).
·  
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 have 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 natural gas and related substances anticipated to the 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 hydrocarbons that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
·  
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 natural 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.
 

 
 
 

 

 
 
(in thousands, except unit amounts)

   
March 31,
   
December 31,
 
   
2011
   
2010
 
   
(unaudited)
       
ASSETS
 
Current assets:
           
   Cash and cash equivalents
  $ 1,488     $ 1,380  
   Accounts receivable - trade
    21,985       22,795  
   Derivatives
    416       2,604  
   Other
    2,462       470  
          Total current assets
    26,351       27,249  
                 
Properties and equipment, at cost - successful efforts method:
               
   Proved properties, including wells and related equipment
    859,230       857,999  
   Unproved properties
    25       17  
   Accumulated depletion, depreciation, and amortization
    (270,868 )     (259,575 )
      588,387       598,441  
   Other property and equipment
    1,531       1,327  
   Accumulated depreciation
    (671 )     (613 )
      860       714  
                 
Goodwill
    9,290       9,290  
Other intangibles, net
    2,936       3,012  
Derivatives
    -       836  
Other
    -       1,778  
          Total assets
  $ 627,824     $ 641,320  
                 
LIABILITIES AND PARTNERS' EQUITY
 
Current liabilities:
               
   Accounts payable:
               
      Trade
  $ 2,796     $ 2,103  
      Affiliate
    1,571       98  
   Accrued liabilities:
               
      Lease operating
    4,298       4,550  
      Development capital
    1,354       890  
      Interest
    221       298  
      Production taxes and marketing
    12,061       10,109  
   Derivatives
    19,715       3,530  
   Oil and natural gas revenues payable
    1,636       1,730  
   Credit agreement
    224,000       -  
   Other
    1,442       1,278  
          Total current liabilities
    269,094       24,586  
                 
Derivatives
    53,155       20,681  
Future abandonment cost, net of current portion
    13,198       13,080  
Deferred taxes
    82       11  
Credit agreement
    -       234,000  
          Total liabilities
    335,529       292,358  
                 
Commitments and contingencies (see Note 11)
               
                 
Partners' equity:
               
Limited partners - public, 24,557,549 and 24,417,542 common units issued
         
      and outstanding, respectively
    309,571       340,126  
   Limited partners - affiliates, 20,924,055 common units issued and outstanding
    (15,909 )     10,125  
   General partner - 504,851 general partner units issued and outstanding
    (722 )     (94 )
   Accumulated other comprehensive loss
    (645 )     (1,195 )
          Total partners' equity
    292,295       348,962  
          Total liabilities and partners' equity
  $ 627,824     $ 641,320  
 
 
 
1

 

(in thousands, except per unit amounts)
(unaudited)
 
   
2011
   
2010
 
Revenues:
           
   Oil
  $ 39,020     $ 36,010  
   Natural gas
    5,793       8,622  
   Natural gas liquids
    2,339       3,943  
   Marketing
    47       70  
   Commodity derivative fair value loss - realized
    (3,345 )     (707 )
   Commodity derivative fair value gain (loss) - unrealized
    (48,125 )     6,179  
Total revenues
    (4,271 )     54,117  
                 
Expenses:
               
   Production:
               
      Lease operating
    8,010       11,619  
      Production taxes and marketing
    4,322       5,066  
   Depletion, depreciation, and amortization
    11,614       12,851  
   Exploration
    -       21  
   General and administrative
    3,330       3,728  
Total expenses
    27,276       33,285  
                 
Operating income (loss)
    (31,547 )     20,832  
                 
Other income (expenses):
               
   Interest
    (2,170 )     (2,377 )
   Interest rate derivative fair value loss - realized
    (972 )     (982 )
   Interest rate derivative fair value gain (loss) - unrealized
    395       (59 )
   Other
    1       25  
Total other expenses
    (2,746 )     (3,393 )
                 
Income (loss) before income taxes
    (34,293 )     17,439  
Income tax provision
    (112 )     (26 )
                 
Net income (loss)
  $ (34,405 )   $ 17,413  
                 
Net income (loss) allocation (see Note 8):
               
      Limited partners' interest in net income (loss)
  $ (34,027 )   $ 17,221  
      General partner's interest in net income (loss)
  $ (378 )   $ 192  
                 
Net income (loss) per common unit:
               
      Basic
  $ (0.75 )   $ 0.38  
      Diluted
  $ (0.75 )   $ 0.38  
                 
Weighted average common units outstanding:
               
      Basic
    45,473       45,299  
      Diluted
    45,473       45,324  
                 
Cash distributions declared per common unit
  $ 0.5000     $ 0.5375  
 
 
 
2

 

ENCORE ENERGY PARTNERS LP
(in thousands, except per unit amounts)
(unaudited)
 
                           
Accumulated
       
                           
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 $7
    -       -       -       -       2,225       2,225  
     Total comprehensive income
                                            34,295  
 Balance at December 31, 2010
    45,342       350,251       505       (94 )     (1,195 )     348,962  
     Non-cash equity-based compensation
    140       178       -       2       -       180  
     Cash distributions to unitholders ($.50 per unit)
    -       (22,740 )     -       (252 )     -       (22,992 )
     Components of comprehensive income:
                                               
          Net loss attributable to unitholders
    -       (34,027 )     -       (378 )     -       (34,405 )
          Settlement of interest rate cash flow hedges in
                                               
          comprehensive loss
    -       -       -       -       550       550  
     Total comprehensive loss
                                            (33,855 )
 Balance at March 31, 2011
    45,482     $ 293,662       505     $ (722 )   $ (645 )   $ 292,295  
 
 
 
3

 

(in thousands)
(unaudited)

   
Three months ended
 
   
March 31,
 
   
2011
   
2010
 
Cash flows from operating activities:
           
   Net income (loss)
  $ (34,405 )   $ 17,413  
   Adjustments to reconcile net income (loss) to net cash provided
               
      by operating activities:
               
         Depletion, depreciation, and amortization
    11,614       12,851  
         Deferred taxes
    107       (11 )
         Non-cash equity-based compensation expense
    180       906  
         Non-cash derivative loss (gain)
    52,237       (3,700 )
         Other
    381       1,366  
         Changes in operating assets and liabilities:
               
            Accounts receivable
    810       6,556  
            Other current assets
    (2,016 )     141  
            Other assets
    1,397       (15 )
            Accounts payable - trade
    693       (1,153 )
            Other current liabilities
    3,545       4,167  
Net cash provided by operating activities
    34,543       38,521  
                 
Cash flows from investing activities:
               
   Purchase of other property and equipment
    (204 )     -  
   Acquisition of oil and natural gas properties
    -       (292 )
   Development of oil and natural gas properties
    (1,239 )     (989 )
Net cash used in investing activities
    (1,443 )     (1,281 )
                 
Cash flows from financing activities:
               
   Proceeds from credit agreement
    10,000       5,000  
   Payments of credit agreement
    (20,000 )     (10,000 )
   Cash distributions to unitholders
    (22,992 )     (24,612 )
Net cash used in financing activities
    (32,992 )     (29,612 )
                 
Increase in cash and cash equivalents
    108       7,628  
Cash and cash equivalents, beginning of period
    1,380       1,754  
Cash and cash equivalents, end of period
  $ 1,488     $ 9,382  
 
 
 
4

 
 

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 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 March 24, 2011, VNR delivered a formal proposal to the chairman of the Conflicts Committee (the “Conflicts Committee”) of ENP GP to acquire all of the outstanding common units of ENP, for consideration of 0.72 common unit of VNR for each outstanding common unit of ENP in a transaction to be structured as a merger of ENP with VNG. The Conflicts Committee of ENP GP has retained Bracewell & Giuliani as legal advisors and Jefferies & Company as financial advisors to assist in the evaluation of the proposal from VNR. The proposal is subject to customary terms and conditions, including applicable board and special committee approvals and the negotiation of definitive agreements.  The Conflicts Committee of ENP GP and its advisors are currently considering the proposal and expect to respond to VNR in due course.

Note 2. 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 March 31, 2011, results of operations for the three months ended March 31, 2011 and 2010, and cash flows for the three months ended March 31, 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.

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 (loss) 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:

 
5

 
 
   
March 31,
   
December 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Proved leasehold costs
  $ 609,938     $ 609,910  
Wells and related equipment - completed
    249,248       248,017  
Wells and related equipment - in process
    44       72  
   Total proved properties
  $ 859,230     $ 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:
 
   
March 31, 2011
   
December 31, 2010
 
   
Book
   
Fair
   
Book
   
Fair
 
   
Value
   
Value
   
Value
   
Value
 
   
(in thousands)
 
Assets:
                       
Cash and cash equivalents
  $ 1,488     $ 1,488     $ 1,380     $ 1,380  
Accounts receivable - trade
    21,985       21,985       22,795       22,795  
Commodity derivative contracts
    416       416       15,682       15,682  
Liabilities:
                               
Accounts payable - trade
    2,796       2,796       2,103       2,103  
Accounts payable - affiliate
    1,571       1,571       98       98  
Credit Agreement
    224,000       224,000       234,000       232,517  
Commodity derivative contracts
    71,823       71,823       35,011       35,011  
Interest rate swaps
    1,047       1,047       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 March 31, 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 lenders underwriting ENP’s Credit Agreement.  ENP also uses derivative instruments in the form of interest rate swaps, which hedge risk 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.

 
6

 
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 Statement of Operations. The net unrealized gain related to the de-designated cash flow hedges is reported in accumulated other comprehensive income 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.

Commodity Derivative Contracts

Historically, ENP has managed commodity price risk with swap contracts, put contracts and collars.  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.

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.

 
7

 

The following tables summarize ENP’s open commodity derivative contracts as of March 31, 2011:

   
April 1, -December 31, 2011
   
Year
2012
   
Year
2013
   
Year
2014
 
Gas Positions:
                       
Fixed Price Swaps:
                       
Notional Volume (MMBtu)
    2,805,550       3,367,932       2,993,000        
Fixed Price ($/MMBtu)
  $ 6.06     $ 5.75     $ 5.10     $  
Puts:
                               
Notional Volume (MMBtu)
    934,450       328,668              
Fixed Price ($/MMBtu)
  $ 6.31     $ 6.76     $     $  
Total Gas Positions:
                               
Notional Volume (MMBtu)
    3,740,000       3,696,600       2,993,000        
Oil Positions:
                               
Fixed Price Swaps:
                               
Notional Volume (Bbls)
    394,625       947,940       1,295,750       1,168,000  
Fixed Price ($/Bbl)
  $ 81.62     $ 83.29     $ 88.95     $ 88.95  
Collars:
                               
Notional Volume (Bbls)
    517,000       475,800              
Floor Price ($/Bbl)
  $ 80.00     $ 74.23     $     $  
Ceiling Price ($/Bbl)
  $ 96.49     $ 90.98     $     $  
Total Oil Positions:
                               
Notional Volume (Bbls)
    911,625       1,423,740       1,295,750       1,168,000  

Interest Rate Swaps

ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under the Credit Agreement to a weighted average fixed rate.  The following table summarizes ENP’s open interest rate swap as of March 31, 2011, which was entered into with Bank of America, N.A.:

   
Notional
   
Fixed
 
Floating
Term
 
Amount
   
Rate
 
Rate
   
(in thousands)
         
April 1, 2011 - March 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) prior to January 1, 2011 ineffectiveness on derivative contracts designated as hedges.  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:

 
8

 
 
 
Location of Gain (Loss)
 
Three months ended March 31,
 
 
Recognized in Income
 
2011
   
2010
 
     
(in thousands)
 
Realized gains (losses):
             
  Premium amortization
Commodity derivative fair value loss - realized
  $ (3,953 )   $ (2,420 )
  Receipts, net of settlements
Commodity derivative fair value gain - realized
    608       1,713  
  Receipts, net of settlements
Interest rate derivative fair value loss - realized
    (972 )     (982 )
      $ (4,317 )   $ (1,689 )
Unrealized gains (losses):
                 
  Mark-to-market gain (loss)
Commodity derivative fair value gain (loss) - unrealized
  $ (48,125 )   $ 6,179  
  Mark-to-market gain (loss)
Interest rate derivative fair value gain - unrealized
    395       -  
  Ineffectiveness on interest rate swaps
Interest rate derivative fair value loss - unrealized
    -       (59 )
      $ (47,730 )   $ 6,120  
Total gains (losses):
                 
  Commodity derivatives
    $ (51,470 )   $ 5,472  
  Interest rate derivatives
      (577 )     (1,041 )
      $ (52,047 )   $ 4,431  
 
Accumulated Other Comprehensive Loss

At March 31, 2011 and December 31, 2010, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $0.6 million and $1.2 million, respectively.  During the twelve months ending March 31, 2012, ENP expects to reclassify $0.6 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 Sheet due to fluctuations in interest rates.
 
 
 
9

 
 
 
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):
 
 
Asset Derivatives
 
Liability Derivatives
 
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
   
March 31, 2011
   
December 31, 2010
   
March 31, 2011
   
December 31, 2010
 
Derivatives not designated as hedges
                       
Commodity derivative contracts
 Derivatives - current
  $ 13,447     $ 10,196  
 Derivatives - current
  $ 31,699     $ 9,906  
Interest rate swaps
 Derivatives - current
    -       -  
 Derivatives - current
    1,047       -  
Commodity derivative contracts
 Derivatives - noncurrent
    6,187       5,486  
 Derivatives - noncurrent
    59,342       25,105  
Total derivatives not designated as hedges
    $ 19,634     $ 15,682       $ 92,088     $ 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
    $ 19,634     $ 15,682       $ 92,088     $ 36,453  

 
The following tables summarize the effect of derivative instruments designated as hedges on the Consolidated Statements of Operations for the periods indicated (in thousands):
 
   
Accumulated OCI (Effective Portion)
 
   
Three Months Ended March 31,
 
Derivatives Designated as Hedges
 
2011
   
2010
 
Interest rate swaps
  $ (550 )   $ 824  

 
   
Amount of Loss Recognized
 
   
in Income as Ineffective
 
   
Three Months Ended March 31,
 
Location of Loss Recognized in Income as Ineffective
 
2011
   
2010
 
Derivative fair value gain (loss)
  $ -     $ (59 )
 
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 March 31, 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
  $ (64,390 )   $ -     $ (64,390 )   $ -  
Oil derivative contracts - floors and caps
    (16,355 )     -       (16,355 )     -  
Natural gas derivative contracts - swaps
    6,888       -       6,888       -  
Natural gas derivative contracts - floors
    2,450       -       2,450       -  
Interest rate swaps
    (1,047 )     -       (1,047 )     -  
   Total
  $ (72,454 )   $ -     $ (72,454 )   $ -  
 
The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for the three months ended March 31, 2011:
 
   
Fair Value Measurements Using Significant
 
   
Unobservable Inputs (Level 3)
 
   
Oil Derivative
   
Natural Gas
       
   
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 March 31, 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 three months ended March 31, 2011 (in thousands):

 
11

 
 
Future abandonment liability at January 1, 2011
  $ 13,838  
   Accretion of discount
    186  
Total future abandonment costs at March 31, 2011
    14,024  
Less: current obligations
    (826 )
Long-term future abandonment liability at March 31, 2011
  $ 13,198  
 
As of March 31, 2011, $13.2 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.8 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheet.  Approximately $5.1 million of the long-term future abandonment liability represents the estimated cost for decommissioning the Elk Basin natural gas processing plant.

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 March 31, 2011.  ENP is currently evaluating its options including extending the term of the 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 million.  Availability under the Credit Agreement is subject to a borrowing base of $375.0 million, which is redetermined semi-annually and upon requested special redeterminations.  As of March 31, 2011, there were $224 million of outstanding borrowings and $151 million of borrowing capacity under the Credit Agreement. In April 2011, the borrowing base was redetermined. See Note 13. Subsequent Events for further discussion.

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.

 
12

 
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:

·  
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 March 31, 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 March 31
4/28/2011
  $ 0.4900  
5/13/2011
(a)
  $ 22,533  
(a)
                         
 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.
 
 
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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 and unvested phantom units 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 (loss) to ENP’s limited partners and earnings per unit computations for the periods indicated:
 
   
March 31,
 
   
2011
   
2010
 
   
(in thousands, except per unit amounts)
 
      Net income (loss) attributable to unitholders
  $ (34,405 )   $ 17,413  
                 
Numerator:
               
   Numerator for basic earnings per unit:
               
      Net income (loss) attributable to unitholders
  $ (34,405 )   $ 17,413  
      Less: distributions earned by participating securities
    (252 )     (252 )
      Plus: cash distributions in excess of
               
         income (loss) allocated to the general partner
    630       60  
      Net income (loss) allocated to limited partners
  $ (34,027 )   $ 17,221  
                 
Denominator:
               
   Denominator for basic earnings per unit:
               
      Weighted average common units outstanding
    45,473       45,299  
      Effect of dilutive phantom units
    -       25  
   Denominator for diluted earnings per unit
    45,473       45,324  
                 
Net income (loss) per common unit:
               
   Basic
  $ (0.75 )   $ 0.38  
   Diluted
  $ (0.75 )   $ 0.38  
 
 
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. As of March 31, 2011, there was approximately $2.9 million of unrecognized compensation cost related to non-vested restricted units, which is expected to be recognized over a period of 3.8 years. The Consolidated Statements of Operations reflects non-cash compensation of $0.2 million in “General and administrative expense” for the three months ended March 31, 2011.  As of March 31, 2011, there were 934,993 common units available for issuance under the LTIP.

 
14

 
Phantom Units.  As a result of the change of control of the General Partner in conjunction with the merger of Encore Acquisition Company 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 three months ended March 31, 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 March 31, 2011, there were no outstanding phantom units.

Note 10. Comprehensive Income (Loss)

The components of comprehensive income (loss) were as follows for the periods indicated:
 
   
Three months ended
 
   
March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Net income (loss)
  $ (34,405 )   $ 17,413  
Settlement of interest rate cash flow hedges
    550       158  
     Comprehensive income (loss)
  $ (33,855 )   $ 17,571  

 
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, ENP has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, 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 as of March 31, 2011.

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 Encore Acquisition Company 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, such as 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 are 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, Encore Operating received an administrative fee of $2.02 per BOE of ENP’s production.  Effective April 1, 2010, the administrative fee increased to $2.06 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 quarter of 2011 as previously received by Encore Operating.
 
15

 
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.

See Note 13. Subsequent Events for further discussion of change in COPAS Wage Index Adjustment.  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 Statement 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:

   
Three Months Ended March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Administrative fees
  $ 1,588     $ 1,642  
COPAS recovery
  $ 805     $ 667  
Third-party expenses
  $ 1,855     $ 2,762  
 
As of March 31, 2011 and December 31, 2010, ENP had a payable to Vanguard of $1.4 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 February 14, 2011, ENP paid cash distributions of approximately $23 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

Effective April 1, 2011, the administrative fee to be paid to VNG pursuant to the administration services agreement decreased from $2.06 per BOE of ENP’s production to $2.05 per BOE as the COPAS Wage Index Adjustment decreased 0.7 percent.

On April 14, 2011, the borrowing base under the Credit Agreement was increased from $375 million to $400 million pursuant to the semi-annual redetermination. All other terms of the Credit Agreement remained the same.

On April 28, 2011, the board of directors of the General Partner declared an ENP cash distribution for the first quarter of 2011 to unitholders of record as of the close of business on May 6, 2011 of $0.49 per unit or approximately $22.5 million of which $10.5 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 May 13, 2011.

 
16

 

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
· First Quarter 2011 Highlights
· Results of Operations – Comparison of Quarter Ended March 31, 2011 to Quarter Ended March 31, 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 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 March 24, 2011, Vanguard Natural Resources, LLC (“Vanguard”) delivered a formal proposal to the chairman of the Conflicts Committee (the “Conflicts Committee”) of the General Partner, to acquire all of the outstanding common units of us, for consideration of 0.72 common unit of Vanguard for each outstanding common unit of us in a  transaction to be structured as a merger of us with Vanguard. The Conflicts Committee of ENP GP has retained Bracewell & Giuliani as legal advisors and Jefferies & Company as financial advisors to assist in the evaluation of the proposal from VNR. The proposal of Vanguard is subject to customary terms and conditions, including applicable board and special committee approvals and the negotiation of definitive agreements.  The Conflicts Committee of the General Partner is currently considering the proposal and expects to respond to Vanguard in due course.

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.

 
17

 
First Quarter 2011 Highlights
 
Our financial and operating results for the first quarter of 2011 included the following:

· 
Our average realized oil price increased eight percent to $79.64 per Bbl as compared to $73.57 per Bbl in the first quarter of 2010.  Our average realized natural gas price decreased 26 percent to $4.19 per Mcf as compared to $5.69 per Mcf in the first quarter of 2010.
· 
Our oil, natural gas and natural gas liquids revenues decreased three percent to $47.2 million as compared to $48.6 million in the first quarter of 2010.  Oil represented approximately 64 percent and 60 percent of our total production in the first quarter of 2011 and 2010, respectively.
· 
Our production margin increased nine percent to $34.8 million as compared to $31.9 million in the first quarter of 2010.  Total oil and natural gas wellhead revenues per BOE increased by four percent while total production expenses per BOE decreased by 21 percent.  On a per BOE basis, our production margin increased 17 percent to $45.71 per BOE as compared to $39.22 per BOE for the first quarter of 2010.
· 
We invested $1.2 million in development and exploitation activities.
· 
Our net loss was $34.4 million ($(0.75) per common unit) as compared to a net income of $17.4 million ($0.38 per common unit) for the first quarter of 2010 primarily due to $54.3 million increase in mark-to-market losses on our commodity derivatives contracts.
· 
Average daily production volumes decreased six percent on a BOE basis from 9,034 BOE/D to 8,463 BOE/D.

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

Comparison of Quarter Ended March 31, 2011 to Quarter Ended March 31, 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 March 31,
   
Increase / (Decrease)
 
   
2011
   
2010
     $          
Revenues (in thousands):
                         
  Oil
  $ 39,020     $ 36,010     $ 3,010       8 %
  Natural gas
    5,793       8,622       (2,829 )     -33 %
  Natural gas liquids
    2,339       3,943       (1,604 )     -41 %
     Total oil, natural gas and natural gas liquids revenues
    47,152       48,575       (1,423 )     -3 %
  Marketing
    47       70       (23 )     -33 %
  Commodity derivatve fair value loss - realized
    (3,345 )     (707 )     (2,638 )     -373 %
  Commodity derivatve fair value gain (loss) - realized
    (48,125 )     6,179       (54,304 )     -879 %
     Total revenues
  $ (4,271 )   $ 54,117     $ (58,388 )     -108 %
                                 
Average realized prices:
                               
  Oil ($/Bbl)
  $ 79.64     $ 73.57     $ 6.07       8 %
  Natural gas ($/Mcf)
  $ 4.19     $ 5.69     $ (1.50 )     -26 %
  Natural gas liquids ($/Bbl)
  $ 56.82     $ 55.49     $ 1.33       2 %
  Combined ($/BOE)
  $ 61.91     $ 59.75     $ 2.16       4 %
                                 
Total production volumes:
                               
  Oil (MBbls)
    490       489       1       0 %
  Natural gas (MMcf)
    1,383       1,515       (132 )     -9 %
  Natural gas liquids (Bbls)
    41       71       (30 )     -42 %
  Combined (MBOE)
    762       813       (51 )     -6 %
                                 
Average daily production volumes:
                               
  Oil (Bbls/D)
    5,444       5,438       6       0 %
  Natural gas (Mcf/D)
    15,368       16,834       (1,466 )     -9 %
  Natural gas liquids (Bbls/D)
    457       790       (333 )     -42 %
  Combined (BOE/D)
    8,463       9,034       (571 )     -6 %
                                 
Average NYMEX prices:
                               
  Oil (per Bbl)
  $ 94.25     $ 78.61     $ 15.64       20 %
  Natural gas (per Mcf)
  $ 4.11     $ 5.36     $ (1.25 )     -23 %
 
The following table shows the relationship between our oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated.  Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.
 
   
Three months ended March 31,
 
   
2011
   
2010
 
Average realized oil price ($/Bbl)
  $ 79.64     $ 73.57  
Average NYMEX ($/Bbl)
  $ 94.25     $ 78.61  
    Differential to NYMEX
  $ (14.61 )   $ (5.04 )
    Average realized oil price to NYMEX percentage
    84 %     94 %
                 
                 
Average realized natural gas price ($/Mcf)
  $ 4.19     $ 5.69  
Average NYMEX ($/Mcf)
  $ 4.11     $ 5.36  
    Differential to NYMEX
  $ 0.08     $ 0.33  
    Average realized natural gas price to NYMEX percentage
    102 %     106 %
 
 
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Our average realized oil price as a percentage of the average NYMEX price was 84 percent in the first quarter of 2011 as compared to 94 percent in the first quarter of 2010.  Our average realized natural gas price as a percentage of the average NYMEX price was 102 percent in the first quarter of 2011 as compared to 106 percent in the first quarter of 2010.  Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted.  Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas as production.

Oil revenues increased eight percent from $36 million in the first quarter of 2010 to $39 million in the first quarter of 2011 as a result of a $6.07 per Bbl increase in our average realized oil price and a 1 MBbls increase in our oil production volumes.  Our higher average realized oil price increased oil revenues by approximately $3 million and was primarily due to a higher average NYMEX price, which increased from $78.61 per Bbl in the first quarter of 2010 to $94.25 per Bbl in the first quarter of 2011. However, we did not reap the entire benefit of the 20 percent increase in the NYMEX oil price due to significant widening of the basis differential received on our oil. Our negative differential to NYMEX oil pricing increased from $5.04 in first quarter 2010 to $14.61 in the first quarter 2011.

Natural gas revenues decreased 33 percent from $8.6 million in the first quarter of 2010 to $5.8 million in the first quarter of 2011 as a result of a $1.50 per Mcf decrease in our average realized natural gas price and a nine percent decrease in our natural gas production volumes.  Our lower average realized natural gas price decreased natural gas revenues by approximately $2.3 million and was primarily due to a lower average NYMEX price, which decreased from $5.36 per Mcf in the first quarter of 2010 to $4.11 per Mcf in the first quarter of 2011.  Our lower natural gas production volumes were primarily due to natural production declines in our Permian Basin area and some weather related production outages.

 
20

 
Expenses.  The following table summarizes our expenses for the periods indicated:
 
   
Three months ended March 31,
   
Increase / (Decrease)
 
   
2011
   
2010
     $       %  
Expenses (in thousands):
                         
  Production:
                         
     Lease operating
  $ 8,010     $ 11,619     $ (3,609 )     -31 %
     Production taxes and marketing
    4,322       5,066       (744 )     -15 %
  Total production expenses
    12,332       16,685       (4,353 )     -26 %
  Other:
                               
     Depletion, depreciation, and amortization
    11,614       12,851       (1,237 )     -10 %
     Exploration
    -       21       (21 )     -100 %
     General and administrative
    3,330       3,728       (398 )     -11 %
  Total operating expenses
    27,276       33,285       (6,009 )     -18 %
  Interest
    2,170       2,377       (207 )     -9 %
  Interest rate derivative fair value loss - realized
    972       982       (10 )     -1 %
  Interest rate derivative fair value gain (loss) - unrealized
    (395 )     59       (454 )     -769 %
 Other
    (1 )     (25 )     24       96 %
  Income tax provision
    112       26       86       331 %
Total expenses
  $ 30,134     $ 36,704     $ (6,570 )     -18 %
                                 
Expenses (per BOE):
                               
  Production:
                               
     Lease operating
  $ 10.52     $ 14.29     $ (3.77 )     -26 %
     Production taxes and marketing
    5.67       6.23       (0.56 )     -9 %
  Total production expenses
    16.19       20.52       (4.33 )     -21 %
  Other:
                               
     Depletion, depreciation, and amortization
    15.25       15.81       (0.56 )     -4 %
     Exploration
    -       0.03       (0.03 )     -100 %
     General and administrative