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Erickson Air-Crane Inc 10-K 2010
e10vk
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2009
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: 001-16295
ENCORE ACQUISITION COMPANY
 
     
Delaware   75-2759650
(State or other jurisdiction
of incorporation or organization)
  (I.R.S. Employer
Identification No.)
     
777 Main Street, Suite 1400, Fort Worth, Texas   76102
(Address of principal executive offices)   (Zip Code)
 
Registrant’s telephone number, including area code: (817) 877-9955
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of each class
 
Name of each exchange on which registered
 
Common Stock
  New York Stock Exchange
Rights to Purchase Series A Junior Participating Preferred Stock
  New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
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. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   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 Act).  Yes o     No þ
 
         
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity of the registrant was last sold as of June 30, 2009 (the last business day of the registrant’s
most recently completed second fiscal quarter)
  $ 1,522,208,999  
Number of shares of Common Stock, $0.01 par value, outstanding as of February 17, 2010
    55,988,169  
 
DOCUMENTS INCORPORATED BY REFERENCE:
None
 


 

 
ENCORE ACQUISITION COMPANY
 
 
 
 
             
        Page
 
  Business and Properties     1  
  Risk Factors     23  
  Unresolved Staff Comments     34  
  Legal Proceedings     34  
  Submission of Matters to a Vote of Security Holders     34  
 
PART II
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     35  
  Selected Financial Data     37  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     40  
  Quantitative and Qualitative Disclosures About Market Risk     72  
  Financial Statements and Supplementary Data     76  
  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     144  
  Controls and Procedures     144  
  Other Information     146  
 
PART III
  Directors, Executive Officers and Corporate Governance     146  
  Executive Compensation     153  
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     167  
  Certain Relationships and Related Transactions, and Director Independence     169  
  Principal Accountant Fees and Services     170  
 
PART IV
  Exhibits and Financial Statement Schedules     171  
 EX-12.1
 EX-21.1
 EX-23.1
 EX-23.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1


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ENCORE ACQUISITION COMPANY
 
GLOSSARY
 
The following are abbreviations and definitions of certain terms used in this annual report on Form 10-K (the “Report”). The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
 
  •  ASC.  FASB Accounting Standards Codification.
 
  •  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.
 
  •  Bcf.  One billion cubic feet, used in reference to natural gas.
 
  •  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.
 
  •  CO2.  Carbon dioxide.
 
  •  Completion.  The installation of permanent equipment for the production of oil or natural gas.
 
  •  Council of Petroleum Accountants Societies (“COPAS”).  A professional organization of oil and gas 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.
 
  •  Delay Rentals.  Fees paid to the lessor of an oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.
 
  •  Developed Acreage.  The number of acres allocated or assignable to producing wells or wells capable of production.
 
  •  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.
 
  •  EAC.  Encore Acquisition Company, a publicly traded Delaware corporation, together with its subsidiaries.
 
  •  ENP.  Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.
 
  •  EOR.  Enhanced oil recovery.
 
  •  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.
 
  •  Extension Well.  A well drilled to extend the limits of a known reservoir.
 
  •  Farm-out.  Transfer of all or part of the operating rights from the working interest holder to an assignee, who assumes all or some of the burden of development, in return for an interest in the property. The assignor usually retains an overriding royalty, but may retain any type of interest.
 
  •  FASB.  Financial Accounting Standards Board.


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ENCORE ACQUISITION COMPANY
 
 
  •  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.
 
  •  Horizontal Drilling.  A drilling operation in which a portion of a well is drilled horizontally within a productive or potentially productive formation, which usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.
 
  •  Lease Operating Expense (“LOE”).  All direct and allocated indirect costs of producing hydrocarbons after completion of drilling and before commencement of production. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.
 
  •  LIBOR.  London Interbank Offered Rate.
 
  •  MBbl.  One thousand Bbls.
 
  •  MBOE.  One thousand BOE.
 
  •  MBOE/D.  One thousand BOE per day.
 
  •  Mcf.  One thousand cubic feet, used in reference to natural gas.
 
  •  Mcf/D.  One Mcf per day.
 
  •  Mcfe.  One Mcf equivalent, calculated by converting oil to natural gas equivalent at a ratio of one Bbl of oil to six Mcf of natural gas.
 
  •  Mcfe/D.  One Mcfe per day.
 
  •  MMBbl.  One million Bbls.
 
  •  MMBOE.  One million BOE.
 
  •  MMBtu.  One million British thermal units. One British thermal unit is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
 
  •  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.
 
  •  Net Production.  Production owned by an entity less royalties, net profits interests, and production due others.
 
  •  Net Profits Interest.  An interest that entitles the owner to a specified share of net profits from the production of hydrocarbons.
 
  •  NYMEX.  New York Mercantile Exchange.
 
  •  NYSE.  The New York Stock Exchange.
 
  •  Oil.  Crude oil, condensate, and NGLs.
 
  •  Operator.  The entity responsible for the exploration, development, and production of a well or lease.


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ENCORE ACQUISITION COMPANY
 
 
  •  Present Value of Future Net Revenues (“PV-10”).  The present value of estimated future revenues to be generated from the production of proved reserves, net of estimated future production and development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to commodity derivative activities, non-property related expenses such as general and administrative expenses, debt service, depletion, depreciation, and amortization, and income taxes, discounted at an annual rate of 10 percent.
 
  •  Production Margin.  Wellhead revenues less production costs.
 
  •  Production Taxes.  Production expense attributable to production, ad valorem, and severance taxes.
 
  •  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.  Proved reserves that can be expected to be recovered from 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.
 
  •  Proved Reserves.  The estimated quantities of hydrocarbons, 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 under existing conditions and operating methods.
 
  •  Proved Undeveloped Reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion. Includes unrealized production response from enhanced recovery techniques that have been proved effective by projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
 
  •  Recompletion.  The completion for production of an existing well bore 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.
 
  •  Royalty.  An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
 
  •  SEC.  The United States Securities and Exchange Commission.


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ENCORE ACQUISITION COMPANY
 
 
  •  Secondary Recovery.  Enhanced recovery of hydrocarbons from a reservoir beyond the hydrocarbons that can be recovered by normal flowing and pumping operations. Involves maintaining or enhancing reservoir pressure by injecting water, gas, or other substances into the formation in order to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding.
 
  •  SFAS.  Statement of Financial Accounting Standards.
 
  •  Standardized Measure.  Future cash inflows from proved reserves, less future production costs, development costs, net abandonment costs, and income taxes, discounted at 10 percent per annum to reflect the timing of future net cash flows. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of estimated future net abandonment costs and income taxes.
 
  •  Tertiary Recovery.  An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gases are used as the injectant.
 
  •  Undeveloped Acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
 
  •  Unit.  A specifically defined area within which acreage is treated as a single consolidated lease for operations and for allocations of costs and benefits without regard to ownership of the acreage. Units are established for the purpose of recovering hydrocarbons from specified zones or formations.
 
  •  Waterflood.  A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.
 
  •  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.


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ENCORE ACQUISITION COMPANY
 
As used in this Report, references to “EAC,” “we,” “our,” “us,” or similar terms refer to Encore Acquisition Company and its subsidiaries, unless the context indicates otherwise. References to “ENP” refers to Encore Energy Partners LP and its subsidiaries. The financial position, results of operations, and cash flows of ENP are consolidated with those of EAC. This Report contains forward-looking statements, which give our current expectations or forecasts of future events. The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements made by us or on our behalf. Please read “Item 1A. Risk Factors” for a description of various factors that could materially affect our ability to achieve the anticipated results described in the forward-looking statements. Certain terms commonly used in the oil and natural gas industry and in this Report are defined under the caption “Glossary.” In addition, all production and reserve volumes disclosed in this Report represent amounts net to us, unless otherwise noted.
 
PART I
 
ITEMS 1 and 2.   BUSINESS AND PROPERTIES
 
 
Our Business.  We are a Delaware corporation engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, we have acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, reengineering, or expanding existing waterflood projects, and applying tertiary recovery techniques. Our properties and oil and natural gas reserves are located in four core areas:
 
  •  the Cedar Creek Anticline (“CCA”) in the Williston Basin in Montana and North Dakota;
 
  •  the Permian Basin in West Texas and southeastern New Mexico;
 
  •  the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and
 
  •  the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Arkansas and Oklahoma, the North Louisiana Salt Basin, and the East Texas Basin.
 
In August 2009, we acquired certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO Resources, Inc. (together with its affiliates, “EXCO”) for approximately $357.4 million in cash, substantially all of which are proved producing.
 
Merger with Denbury.  On October 31, 2009, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Denbury Resources Inc. (“Denbury”) pursuant to which we have agreed to merge with and into Denbury, with Denbury as the surviving entity (the “Merger”). The Merger Agreement, which was unanimously approved by our Board of Directors (the “Board”) and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of our issued and outstanding shares of common stock, par value $.01 per share, in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of our interest in ENP. We expect to complete the Merger during the first quarter of 2010, although completion by any particular date cannot be assured.
 
Proved Reserves.  Our estimated total proved reserves at December 31, 2009 were 147.1 MMBbls of oil and 439.1 Bcf of natural gas, based on 2009 average market prices of $61.18 per Bbl for oil and $3.83 per Mcf for natural gas. On a BOE basis, our proved reserves were 220.3 MMBOE at December 31, 2009, of which 67 percent was oil, 80 percent was proved developed, and 20 percent was proved undeveloped.
 
Most Valuable Asset.  The CCA represented approximately 32 percent of our total proved reserves as of December 31, 2009 and is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around current and future CCA exploitation and production through primary, secondary, and tertiary recovery techniques.


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ENCORE ACQUISITION COMPANY
 
Drilling.  In 2009, we drilled 34 gross (27.5 net) operated productive wells and participated in drilling 78 gross (14.8 net) non-operated productive wells for a total of 112 gross (42.3 net) productive wells. In 2009, we drilled six gross (5.9 net) operated dry holes and participated in drilling another two gross (0.6 net) dry holes for a total of eight gross (6.6 net) dry holes. This represents a success rate of over 93 percent during 2009. We invested $286.9 million in development, exploitation, and exploration activities in 2009, of which $25.4 million related to dry holes.
 
ENP.  As of February 17, 2010, we owned 20,924,055 of ENP’s outstanding common units, representing an approximate 45.7 percent limited partner interest. Through our indirect ownership of ENP’s general partner, we also hold all 504,851 general partner units, representing a 1.1 percent general partner interest in ENP. As we control ENP’s general partner, ENP’s financial position, results of operations, and cash flows are consolidated with ours.
 
In February 2008, we sold certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota to ENP for approximately $125.0 million in cash and 6,884,776 ENP common units. In determining the total sales price, the common units were valued at $125.0 million. In January 2009, we sold certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash. In June 2009, we sold certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.2 million in cash. In August 2009, we sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) to ENP for approximately $179.6 million in cash.
 
Financial Information About Operating Segments.  We have operations in only one industry segment: the oil and natural gas exploration and production industry in the United States. However, we are organizationally structured along two operating segments: EAC Standalone and ENP. The contribution of each operating segment to revenues and operating income (loss), and the identifiable assets and liabilities attributable to each operating segment, are set forth in Note 16 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”
 
 
 
In general, we seek to be the operator of wells in which we have a working interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oilfield service equipment used for drilling or maintaining wells on properties we operate. Independent contractors engaged by us provide all the equipment and personnel associated with these activities.
 
As of December 31, 2009, we operated properties representing approximately 79 percent of our proved reserves. As the operator, we are able to better control expenses, capital allocation, and the timing of exploitation and development activities on our properties. We also own working interests in properties that are operated by third parties for which we are required to pay our share of production, exploitation, and development costs. Please read “— Properties — Nature of Our Ownership Interests.” During 2009, 2008, and 2007, our development costs on non-operated properties were approximately 39 percent, 22 percent, and 40 percent, respectively, of our total development costs. We also own royalty interests in wells operated by third parties that are not burdened by production or capital costs; however, we have little or no control over the implementation of projects on these properties.


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ENCORE ACQUISITION COMPANY
 
 
We own and operate a network of natural gas gathering systems in our Elk Basin area of operation. These systems gather and transport our natural gas and a small amount of third-party natural gas to larger gathering systems and intrastate, interstate, and local distribution pipelines. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to:
 
  •  realize faster connection of newly drilled wells to the existing system;
 
  •  control pipeline operating pressures and capacity to maximize our production;
 
  •  control compression costs and fuel use;
 
  •  maintain system integrity;
 
  •  control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and
 
  •  track sales volumes and receipts closely to assure all production values are realized.
 
 
Oil and natural gas producing operations are generally not seasonal. However, demand for some of our products can fluctuate season to season, which impacts price. In particular, heavy oil is typically in higher demand in the summer for its use in road construction, and natural gas is generally in higher demand in the winter for heating.


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ENCORE ACQUISITION COMPANY
 
 
The following table sets forth information regarding our production volumes, average realized prices, and average costs per BOE for the periods indicated:
 
                         
    Year Ended December 31,
    2009   2008   2007
 
Total Production Volumes:
                       
Oil (MBbls)
    10,016       10,050       9,545  
Natural gas (MMcf)
    33,919       26,374       23,963  
Combined (MBOE)
    15,669       14,446       13,539  
Average Daily Production Volumes:
                       
Oil (Bbls/D)
    27,441       27,459       26,152  
Natural gas (Mcf/D)
    92,928       72,060       65,651  
Combined (BOE/D)
    42,929       39,470       37,094  
Average Realized Prices:
                       
Oil (per Bbl)
  $ 54.85     $ 89.30     $ 58.96  
Natural gas (per Mcf)
    3.87       8.63       6.26  
Combined (per BOE)
    43.43       77.87       52.66  
Average Costs per BOE:
                       
Lease operating
  $ 10.53     $ 12.12     $ 10.59  
Production, ad valorem, and severance taxes
    4.44       7.66       5.51  
Depletion, depreciation, and amortization
    18.56       15.80       13.59  
Impairment of long-lived assets
    0.64       4.12        
Exploration
    3.35       2.71       2.05  
Derivative fair value loss (gain)
    3.80       (23.97 )     8.31  
General and administrative
    3.45       3.35       2.89  
Provision for doubtful accounts
    0.49       0.14       0.43  
Other operating
    1.64       0.90       1.26  
Marketing, net of revenues
    (0.05 )     (0.06 )     (0.11 )
 
 
The following table sets forth information relating to productive wells in which we owned a working interest at December 31, 2009. Wells are classified as oil or natural gas wells according to their predominant production stream. We also hold royalty interests in units and acreage beyond the wells in which we own a working interest.
 
                                                 
    Oil Wells     Natural Gas Wells  
                Average
                Average
 
    Gross
    Net
    Working
    Gross
    Net
    Working
 
    Wells(a)     Wells     Interest     Wells(a)     Wells     Interest  
 
CCA
    729       645.2       89 %     23       6.3       27 %
Permian Basin
    1,969       772.2       39 %     692       353.5       51 %
Rockies
    1,476       851.7       58 %     42       29.7       71 %
Mid-Continent
    484       282.6       58 %     1,355       569.7       42 %
                                                 
Total
    4,658       2,551.7       55 %     2,112       959.2       45 %
                                                 
 
 
(a) Our total wells include 3,810 operated wells and 2,960 non-operated wells. At December 31, 2009, 62 of our wells had multiple completions.


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ENCORE ACQUISITION COMPANY
 
 
 
The following table sets forth information relating to our leasehold acreage at December 31, 2009. Developed acreage is assigned to productive wells. Undeveloped acreage is acreage held under lease, permit, contract, or option that is not in a spacing unit for a producing well, including leasehold interests identified for exploitation or exploratory drilling. As of December 31, 2009, our undeveloped acreage in the Rockies represented approximately 40 percent of our total net undeveloped acreage. A portion of our oil and natural gas leases are held by production, which means that for as long as our wells continue to produce oil or natural gas, we will continue to own the lease. Leases which are not held by production expire at various dates between 2010 and 2020, with leases representing $28.9 million of cost set to expire in 2010 if not developed.
 
                 
    Gross
    Net
 
    Acreage     Acreage  
 
CCA:
               
Developed
    93,563       94,607  
Undeveloped
    159,264       133,107  
                 
      252,827       227,714  
                 
Permian Basin:
               
Developed
    81,248       53,788  
Undeveloped
    25,242       23,449  
                 
      106,490       77,237  
                 
Rockies:
               
Developed
    235,535       160,024  
Undeveloped
    375,704       245,170  
                 
      611,239       405,194  
                 
Mid-Continent:
               
Developed
    189,778       101,900  
Undeveloped
    292,504       205,703  
                 
      482,282       307,603  
                 
Total:
               
Developed
    600,124       410,319  
Undeveloped
    852,714       607,429  
                 
      1,452,838       1,017,748  
                 


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ENCORE ACQUISITION COMPANY
 
Development Results
 
The following table sets forth information with respect to wells completed during the periods indicated, regardless of when development was initiated. This information should not be considered indicative of future performance, nor should a correlation be assumed between productive wells drilled, quantities of reserves discovered, or economic value.
 
                                                 
    Year Ended December 31,  
    2009     2008     2007  
    Gross     Net     Gross     Net     Gross     Net  
 
Development Wells:
                                               
Productive
    57       25.9       186       73.4       165       61.7  
Dry holes
    1       1.0       5       3.1       5       3.3  
                                                 
      58       26.9       191       76.5       170       65.0  
                                                 
Exploratory Wells:
                                               
Productive
    55       16.4       96       31.4       63       20.9  
Dry holes
    7       5.6       8       3.8       5       2.6  
                                                 
      62       22.0       104       35.2       68       23.5  
                                                 
Total:
                                               
Productive
    112       42.3       282       104.8       228       82.6  
Dry holes
    8       6.6       13       6.9       10       5.9  
                                                 
      120       48.9       295       111.7       238       88.5  
                                                 
 
 
As of December 31, 2009, we had 25 gross (10.3 net) wells that had begun drilling and were in varying stages of drilling operations, of which nine gross (1.9 net) were development wells. As of December 31, 2009, we had 15 gross (6.0 net) wells that had reached total depth and were in the process of being completed pending first production, of which six gross (1.2 net) were development wells.
 
 
Our oil and natural gas production is generally sold to marketers, processors, refiners, and other purchasers that have access to nearby pipeline, processing, and gathering facilities. In areas where there is no practical access to pipelines, oil is trucked to central storage facilities where it is aggregated and sold to various markets and downstream purchasers. Our production sales agreements generally contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices in the area, and generally have terms of one year or less.
 
The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte Pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and subject to apportionment, we currently believe that we have been allocated sufficient pipeline capacity to move our crude oil production. However, there can be no assurance that we will be allocated sufficient pipeline capacity to move our crude oil production in the future. An expansion of the Enbridge Pipeline was completed in early 2008, which moved the total Rockies area pipeline takeaway closer to increasing production volumes and thereby provided greater stability to oil differentials in the area. An additional expansion of Enbridge Pipeline was completed in early


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2010, bringing additional takeaway capacity to the region, but in spite of these increases in capacity, the Enbridge Pipeline continues to run at full capacity. The Enbridge pipeline is currently presenting a new proposal to further expand the line in anticipation of the continuing expected production increases from the Williston / Bakken region. However, any restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.
 
The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot accurately predict future oil and natural gas differentials. Increases in the percentage differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows. The following table shows the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices by quarter for 2009:
 
                                 
    First Quarter
  Second Quarter
  Third Quarter
  Fourth Quarter
    of 2009   of 2009   of 2009   of 2009
 
Average oil wellhead to NYMEX percentage
    82 %     92 %     89 %     89 %
Average natural gas wellhead to NYMEX percentage
    67 %     105 %     109 %     112 %
 
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 liquids 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 in Mcf as production resulting in a price we were paid per Mcf under certain contracts to be higher than the average NYMEX price.
 
 
For 2009, our largest purchaser was Eighty-Eight Oil, which accounted for approximately 18 percent of our total sales of production. Our marketing of oil and natural gas can be affected by factors beyond our control, the potential effects of which cannot be accurately predicted. Management believes that the loss of any one purchaser would not have a material adverse effect on our ability to market our oil and natural gas production.
 
 
The oil and natural gas industry is highly competitive. We encounter strong competition from other oil and natural gas companies in acquiring properties, contracting for development equipment, and securing trained personnel. Many of these competitors have resources substantially greater than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for, and purchase a greater number of properties or prospects than our resources will permit.
 
We are also affected by competition for rigs and the availability of related equipment. The oil and natural gas industry has experienced shortages of rigs, equipment, pipe, and personnel, which has delayed development and exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.
 
Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases, and development rights, and we may not be able to compete satisfactorily when attempting to acquire additional properties.


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ENCORE ACQUISITION COMPANY
 
Properties
 
Nature of Our Ownership Interests
 
The following table sets forth the production, average wellhead prices, and average LOE per BOE of our properties by principal area of operation for the periods indicated:
 
                                                         
    Production     Average  
          Natural
          Percent
    Average Oil
    Natural Gas
    Lease
 
    Oil     Gas     Total     of Total     Wellhead     Wellhead     Operating  
    (MBbls)     (MMcf)     (MBOE)           (per Bbl)     (per Mcf)     (per BOE)  
 
2009
                                                       
                                                         
CCA
    3,786       889       3,934       25 %   $ 55.41     $ 3.87     $ 12.64  
Permian Basin
    1,217       15,182       3,748       24 %     56.73       3.98       8.32  
Rockies
    4,410       2,035       4,749       30 %     53.46       3.96       12.66  
Mid-Continent
    603       15,813       3,238       21 %     57.77       3.74       7.43  
                                                         
Total
    10,016       33,919       15,669       100 %     54.85       3.87       10.53  
                                                         
2008
                                                       
                                                         
CCA
    4,146       978       4,309       30 %     88.66       8.35       12.62  
Permian Basin
    1,246       12,442       3,320       23 %     95.34       8.65       11.96  
Rockies
    4,256       1,870       4,567       32 %     88.15       9.02       13.80  
Mid-Continent
    402       11,084       2,250       15 %     96.28       8.55       8.02  
                                                         
Total
    10,050       26,374       14,446       100 %     89.58       8.63       12.12  
                                                         
2007
                                                       
                                                         
CCA
    4,426       1,122       4,614       34 %     62.72       5.31       10.16  
Permian Basin
    1,214       8,937       2,703       20 %     67.88       7.03       11.97  
Rockies
    3,434       1,368       3,662       27 %     62.61       6.31       12.15  
Mid-Continent
    471       12,536       2,560       19 %     65.98       6.62       7.69  
                                                         
Total
    9,545       23,963       13,539       100 %     63.50       6.69       10.59  
                                                         


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ENCORE ACQUISITION COMPANY
 
The following table sets forth the proved reserves of our properties by principal area of operation as of December 31, 2009:
 
                                 
          Natural
          Percent
 
    Oil     Gas     Total     of Total  
    (MBbls)     (MMcf)     (MBOE)        
 
Proved Developed:
                               
CCA
    60,227       12,708       62,345       36 %
Permian Basin
    14,408       127,620       35,678       20 %
Rockies
    39,274       15,448       41,849       24 %
Mid-Continent
    7,492       166,646       35,266       20 %
                                 
Total Proved Developed
    121,401       322,422       175,138       100 %
                                 
Proved Undeveloped:
                               
CCA
    7,777       675       7,890       17 %
Permian Basin
    5,641       38,886       12,122       27 %
Rockies
    11,469       6,725       12,590       28 %
Mid-Continent
    806       70,364       12,533       28 %
                                 
Total Proved Undeveloped
    25,693       116,650       45,135       100 %
                                 
Total Proved:
                               
CCA
    68,004       13,383       70,235       32 %
Permian Basin
    20,049       166,506       47,800       22 %
Rockies
    50,743       22,173       54,439       24 %
Mid-Continent
    8,298       237,010       47,799       22 %
                                 
Total Proved
    147,094       439,072       220,273       100 %
                                 
 
The following table sets forth the PV-10 of our properties by principal area of operation as of December 31, 2009:
 
                 
    Amount(a)     Percent of Total  
    (In thousands)        
 
CCA
  $ 786,720       37 %
Permian Basin
    419,346       20 %
Rockies
    671,483       31 %
Mid-Continent
    263,488       12 %
                 
Total
  $ 2,141,037       100 %
                 
 
 
(a) Giving effect to commodity derivative contracts, our PV-10 would decrease by $23.4 million at December 31, 2009. Standardized Measure at December 31, 2009 was $1.7 billion. Standardized Measure differs from PV-10 by approximately $414.0 million because Standardized Measure includes the effects of future net abandonment costs and future income taxes. Since we are taxed at the corporate level, future income taxes are determined on a combined property basis and cannot be accurately subdivided among our core areas. Therefore, we believe PV-10 provides the best method for assessing the relative value of each of our areas.
 
Recent SEC Rule-Making Activity.  In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and natural gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 8.5 MBOE while the change in definition of proved


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ENCORE ACQUISITION COMPANY
 
undeveloped reserves increased total proved reserves by 5.7 MMBOE. Therefore, the total impact of the new reserve rules resulted in negative reserves revisions of 2.8 MMBOE. Pursuant to the SEC’s final rule, prior period reserves were not restated.
 
The SEC’s new rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.
 
We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs, and core data to calculate our reserves estimates, including the material additions to the 2009 reserves estimates.
 
Proved Undeveloped Reserves (“PUDs”).  As of December 31, 2009, our PUDs totaled 25.7 MMBbls of crude oil and 116.7 Bcf of natural gas, for a total of 45.1 MMBOE or about 20.5 percent of our total proved reserves.
 
All of our PUDs as of December 31, 2009 are associated with drilling or improved recovery development projects that are scheduled to begin drilling or implementation within the next 5 years. Our major development areas include drilling locations in West Texas, Bakken, and Haynesville and PUDs booked for secondary recovery projects in CCA and West Texas. All of the drilling projects will have PUDs convert from undeveloped to developed as these projects begin production. All of the improved recovery projects will convert to proved developed reserves as, and to the extent, these projects achieve production response.
 
Changes in PUDs that occurred during 2009 were due to:
 
  •  reclassifications of PUDs into proved developed reserves for implementation of drilling projects and response to secondary/tertiary recovery projects;
 
  •  additions of PUDs due to proving up additional drilling locations and changes in PUDs definition under the new SEC rules; and
 
  •  negative revisions in PUDs due to changes in commodity prices.
 
Drilling Plans.  All PUD drilling locations are scheduled to be drilled prior to the end of 2014. Initial production from these PUDs is expected to begin between 2010 to 2014.
 
Internal Controls Over Reserves Estimates.  Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. We engage a third-party petroleum consulting firm, Miller and Lents, to prepare our reserves. Responsibility for compliance in reserves bookings is delegated to the Reserves and Planning Engineering Manager and requires that reserves estimates be made by the regional reservoir engineering staff for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Reserves and Planning Engineering Manager and the Senior Vice President and Chief Operating Officer and certain members of senior management.
 
Our Reserves and Planning Engineering Manager is the technical person primarily responsible for overseeing the preparation of our reserves estimates. She has a Bachelor of Science degree in Petroleum Engineering, 15 years of industry experience, and 9 years experience managing our reserves with positions of increasing responsibility in engineering and evaluations. The Reserves and Planning Engineering Manager reports directly to our Senior Vice President and Chief Operating Officer.
 
The engineers and geologists of Miller and Lents have an average of 30 years of relevant industry experience in the estimation, assessment, and evaluation of oil and natural gas reserves. They have significant industry experience in virtually all petroleum-producing basins in the world and meet the requirements


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ENCORE ACQUISITION COMPANY
 
regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; it does not own an interest in our properties and is not employed on a contingent fee basis. Miller and Lents’ report on our reserves and future net revenues as of December 31, 2009, which details specific information regarding the scope of work undertaken and the results thereof, is filed as Exhibit 99.1 to this Report and incorporated herein by reference.
 
Guidelines established by the SEC were used to prepare these reserve estimates. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates and their PV-10 are inherently imprecise, subject to change, and should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.
 
Other Reserve Information.  During 2009, we filed the estimates of our oil and natural gas reserves as of December 31, 2008 with the U.S. Department of Energy on Form EIA-23. As required by Form EIA-23, the filing reflected only gross production that comes from our operated wells at year-end. Those estimates came directly from our reserve report prepared by Miller and Lents.
 
(MAP)


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ENCORE ACQUISITION COMPANY
 
 
Our initial purchase of interests in the CCA was in 1999, and we continue to acquire additional working interests. As of December 31, 2009, we operated virtually all of our CCA properties with an average working interest of approximately 89 percent in the oil wells and 27 percent in the natural gas wells.
 
The CCA is a major structural feature of the Williston Basin in southeastern Montana and northwestern North Dakota. Our acreage is concentrated on the two-to-six-mile-wide “crest” of the CCA, giving us access to the greatest accumulation of oil in the structure. Our holdings extend for approximately 120 continuous miles along the crest of the CCA across five counties in two states. Primary producing reservoirs are the Red River, Stony Mountain, Interlake, and Lodgepole formations at depths of between 7,000 and 9,000 feet. Our fields in the CCA include the North Pine, South Pine, Cabin Creek, Coral Creek, Little Beaver, Monarch, Glendive North, Glendive, Gas City, and Pennel fields.
 
Our CCA reserves are primarily produced through waterfloods. Our average daily net production from the CCA decreased 15 percent to 10,360 BOE/D in the fourth quarter of 2009 as compared to 12,153 BOE/D in the fourth quarter of 2008. We invested $18.1 million, $37.3 million, and $41.6 million in capital projects in the CCA during 2009, 2008, and 2007, respectively.
 
The CCA represents approximately 32 percent of our total proved reserves as of December 31, 2009 and is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around current and future exploitation of and production from this area.
 
We pursued HPAI in the CCA beginning in 2002 because CO2 was not readily available and HPAI was an attractive alternative. The initial project was successful and continues to be successful; however, the political environment is changing in favor of CO2 sequestration. Therefore, we have made a strategic decision to move away from HPAI and focus on CO2.
 
Existing HPAI project areas in the CCA are in Pennel and Cedar Creek fields. In both fields, HPAI wells will be converted to water injection in three to four phases over a period of approximately 18 months. Priority will be largely based on economics of incremental production uplift and air injection utilization. We anticipate that we will continue injecting air in a small number of HPAI patterns beyond the planned 18-month conversion period. We expect to realize significant LOE savings while achieving current production estimates.
 
Net Profits Interest.  A major portion of our acreage position in the CCA is subject to net profits interests ranging from one percent to 50 percent. The holders of these net profits interests are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been subtracted from net revenue. The net profits calculations are contractually defined. In general, net profits are determined after considering operating expense, overhead expense, interest expense, and development costs. The amounts of reserves and production attributable to net profits interests are deducted from our reserves and production data, and our revenues are reported net of net profits interests. The reserves and production attributed to net profits interests are calculated by dividing estimated future net profits interests (in the case of reserves) or prior period actual net profits interests (in the case of production) by commodity prices at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributable to the net profits interests and will have an inverse effect on our reported reserves and production. For 2009, 2008, and 2007, we reduced oil and natural gas revenues for net profits interests by $31.8 million, $56.5 million, and $32.5 million, respectively.
 
 
West Texas.  Our West Texas properties include 17 operated fields, including the East Cowden Grayburg Unit, Fuhrman-Mascho, Crockett County, Sand Hills, Howard Glasscock, Nolley, Deep Rock, and others; and seven non-operated fields. Production from the central portion of the Permian Basin comes from multiple reservoirs, including the Grayburg, San Andres, Glorieta, Clearfork, Wolfcamp, and Pennsylvanian zones.


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ENCORE ACQUISITION COMPANY
 
Production from the southern portion of the Permian Basin comes mainly from the Canyon, Devonian, Ellenberger, Mississippian, Montoya, Strawn, and Wolfcamp formations with multiple pay intervals.
 
In March 2006, we entered into a joint development agreement with ExxonMobil Corporation (“ExxonMobil”) to develop legacy natural gas fields in West Texas. The agreement covers certain formations in the Parks, Pegasus, and Wilshire Fields in Midland and Upton Counties, the Brown Bassett Field in Terrell County, and Block 16, Coyanosa, and Waha Fields in Ward, Pecos, and Reeves Counties. Targeted formations include the Barnett, Devonian, Ellenberger, Mississippian, Montoya, Silurian, Strawn, and Wolfcamp horizons.
 
Under the terms of the agreement, we have the opportunity to develop approximately 100,000 gross acres. We earn 30 percent of ExxonMobil’s working interest and 22.5 percent of ExxonMobil’s net revenue interest in each well drilled. We operate each well during the drilling and completion phase, after which ExxonMobil assumes operational control of the well. We also have the right to propose and drill wells for as long as we are engaged in continuous drilling operations.
 
We entered into a side letter agreement with ExxonMobil to: (1) combine a group of specified fields into one development area, and extend the period within which we must drill a well in this development area and one additional development area in order to be considered as conducting continuous drilling operations; (2) transfer ExxonMobil’s full working interest in a specified well along with a majority of its net royalty interest to us, while reserving its portion of an overriding royalty interest; (3) allow ExxonMobil to participate in any re-entry of the specified well under the original terms of a “subsequent well” (as defined in the joint development agreement), in which they will pay their proportional share of agreed costs incurred; and (4) reduce the non-consent penalty for 10 specified wells from 200 percent to 150 percent in exchange for ExxonMobil agreeing not to elect the carry for reduced working interest option for these wells.
 
Average daily production for our West Texas properties increased three percent from 8,497 BOE/D in the fourth quarter of 2008 to 8,777 BOE/D in the fourth quarter of 2009. We believe these properties will be an area of growth over the next several years. During 2009, we drilled 21 gross wells and invested approximately $64.3 million of capital to develop these properties.
 
New Mexico.  We began investing in New Mexico in May 2006 with the strategy of deploying capital to develop low- to medium-risk development projects in southeastern New Mexico where multiple reservoir targets are available. Average daily production for these properties decreased 30 percent from 6,732 Mcfe/D in the fourth quarter of 2008 to 4,742 Mcfe/D in the fourth quarter of 2009. During 2009, we drilled two gross wells and invested approximately $3.3 million of capital to develop these properties.
 
 
Oklahoma, Arkansas, and Kansas.  We own various interests, including operated, non-operated, royalty, and mineral interests, on properties located in the Anadarko Basin of western Oklahoma and the Arkoma Basin of eastern Oklahoma and western Arkansas. Our average daily production for these properties nearly tripled from 8,159 Mcfe/D in the fourth quarter of 2008 to 24,420 Mcfe/D for the fourth quarter of 2009. The increase in production was primarily due to our acquisition of the Nogre Marchand Unit and other properties in the Anadarko basin from EXCO in 2009. During 2009, we invested $6.7 million of development and exploration capital in these properties.
 
North Louisiana Salt Basin and East Texas Basin.  Our North Louisiana Salt Basin and East Texas Basin properties consist of operated working interests, non-operated working interests, and undeveloped leases and development in the Stockman, Danville, Gladewater, and Overton fields in east Texas. We purchased interests in the Gladewater and Overton fields from EXCO in 2009. Our interests in the Elm Grove Field in Bossier Parish, Louisiana include non-operated working interests ranging from one percent to 47 percent across 1,800 net acres in 15 sections.


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ENCORE ACQUISITION COMPANY
 
Our East Texas and North Louisiana properties are in the same core area and have similar geology. The properties are producing primarily from multiple tight sandstone reservoirs in the Travis Peak and Lower Cotton Valley formations at depths ranging from 8,000 to 11,500 feet.
 
In the fourth quarter of 2008, we began our Haynesville shale drilling program with the spudding of the first Haynesville shale well at the Greenwood Waskom field in Caddo Parish, Louisiana. This well reached total depth in January 2009 ahead of schedule and was completed with an 11-stage fracture stimulation. Since entering the Haynesville play, we have accumulated over 18,000 gross acres.
 
During 2009, we drilled four gross wells and invested approximately $93.7 million of capital to develop these properties. Average daily production for these properties increased 30 percent from 36,239 Mcfe/D in the fourth quarter of 2008 to 47,104 Mcfe/D for the fourth quarter of 2009.
 
 
Big Horn Basin.  In March 2007, ENP acquired the Big Horn Basin properties, which are located in the Big Horn Basin in northwestern Wyoming and south central Montana. The Big Horn Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. The Big Horn Basin is a prolific basin and has produced over 1.8 billion Bbls of oil since its discovery in 1906.
 
ENP also owns and operates (1) the Elk Basin natural gas processing plant near Powell, Wyoming, (2) the Clearfork crude oil pipeline extending from the South Elk Basin Field to the Elk Basin Field in Wyoming, (3) the Wildhorse natural gas gathering system that transports low sulfur natural gas from the Elk Basin and South Elk Basin fields to our Elk Basin natural gas processing plant, and (4) a natural gas gathering system that transports higher sulfur natural gas from the Elk Basin Field to our Elk Basin natural gas processing facility.
 
Average daily production for these properties decreased seven percent from 4,212 BOE/D in the fourth quarter of 2008 to 3,934 BOE/D in the fourth quarter of 2009. During 2009, we invested approximately $1.0 million of capital to develop these properties.
 
Williston Basin.  Our Williston Basin properties have historically consisted of working and overriding royalty interests in several geographically concentrated fields. The properties are located in western North Dakota and eastern Montana, near our CCA properties. In April 2007, we acquired additional properties in the Williston Basin including 50 different fields across Montana and North Dakota. As part of this acquisition, we also acquired approximately 70,000 net unproved acres in the Bakken play of Montana and North Dakota. Since the acquisition, we have increased our acreage position in the Bakken play to approximately 300,000 acres. During 2009, we drilled and completed six wells in the Bakken and Sanish. The Almond prospect contains 70,000 net acres and is located near the northeast border of Mountrail County, North Dakota.
 
Average daily production for these properties increased 11 percent from 6,919 BOE/D in the fourth quarter of 2008 to 7,708 BOE/D in the fourth quarter of 2009. During 2009, we drilled seven gross wells and invested approximately $81.2 million of capital to develop our Rockies properties.
 
Bell Creek.  Our Bell Creek properties are located in the Powder River Basin of southeastern Montana. We operate seven production units in Bell Creek, each with a 100 percent working interest. The shallow (less than 5,000 feet) Cretaceous-aged Muddy Sandstone reservoir produces oil. We have successfully implemented a polymer injection program on both injection and producing wells on our Bell Creek properties whereby a polymer is injected into a well to reduce the amount of water cycling in the higher permeability interval of the reservoir, reducing operating costs and increasing reservoir recovery. This process is generally more efficient than standard waterflooding.


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We invested $12.3 million of capital to develop these properties in 2009. Average daily production from these properties increased nine percent from 890 BOE/D in the fourth quarter of 2008 to 969 BOE/D in the fourth quarter of 2009.
 
In July 2009, we acquired a private company for $24 million, which procured a CO2 supply intended to be used for a tertiary oil recovery project in the Bell Creek Field. The initial term of the CO2 supply contract is 15 years. The CO2 purchasable is not transportable as capture and compression facilities and a related pipeline need to be built. Until the CO2 can be transported to the field and the capture, compression, and injection of the CO2 proves economic, the contract has an unknown useful life. During 2009, we invested approximately $5.0 million of capital related to a pipeline which is intended to be used to transport this CO2 supply to our Bell Creek field.
 
Paradox Basin.  The Paradox Basin properties, located in southeast Utah’s Paradox Basin, are divided between two prolific oil producing units: the Ratherford Unit and the Aneth Unit. We believe these properties have additional potential in horizontal redevelopment, secondary development, and tertiary recovery potential.
 
Average daily production for these properties increased approximately four percent from 631 BOE/D in the fourth quarter of 2008 to 658 BOE/D in the fourth quarter of 2009. During 2009, we invested approximately $3.1 million of capital to develop these properties.
 
 
We believe that we have satisfactory title to our oil and natural gas properties in accordance with standards generally accepted in the oil and natural gas industry.
 
Our properties are subject, in one degree or another, to one or more of the following:
 
  •  royalties, overriding royalties, net profits interests, and other burdens under oil and natural gas leases;
 
  •  contractual obligations, including, in some cases, development obligations arising under joint operating agreements, farm-out agreements, production sales contracts, and other agreements that may affect the properties or their titles;
 
  •  liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors, and contractual liens under joint operating agreements;
 
  •  pooling, unitization, and communitization agreements, declarations, and orders; and
 
  •  easements, restrictions, rights-of-way, and other matters that commonly affect property.
 
We believe that the burdens and obligations affecting our properties do not in the aggregate materially interfere with the use of the properties. As previously discussed, a major portion of our acreage position in the CCA, our primary asset, is subject to net profits interests.
 
We have granted mortgage liens on substantially all of our oil and natural gas properties in favor of Bank of America, N.A., as agent, to secure borrowings under our revolving credit facility. These mortgages and the revolving credit facility contain substantial restrictions and operating covenants that are customarily found in loan agreements of this type.
 
Environmental Matters and Regulation
 
General.  Our operations are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. These laws and regulations may, among other things:
 
  •  require the acquisition of various permits before development commences;
 
  •  require the installation of pollution control equipment;


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  •  enjoin some or all of the operations of facilities deemed in non-compliance with permits;
 
  •  restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with oil and natural gas development, production, and transportation activities;
 
  •  restrict the way in which wastes are handled and disposed;
 
  •  limit or prohibit development activities on certain lands lying within wilderness, wetlands, areas inhabited by threatened or endangered species, and other protected areas;
 
  •  require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells;
 
  •  impose substantial liabilities for pollution resulting from operations; and
 
  •  require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement for operations affecting federal lands or leases.
 
These laws, rules, and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in indirect compliance costs or additional operating restrictions, including costly waste handling, disposal, and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
 
The following is a discussion of relevant environmental and safety laws and regulations that relate to our operations.
 
Waste Handling.  The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils that may be regulated as hazardous wastes.
 
Site Remediation.  The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed of or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.


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We own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although petroleum, including crude oil, and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations, we generate wastes that may fall within the definition of a “hazardous substance.” We believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, yet hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
 
ENP’s Elk Basin assets have been used for oil and natural gas exploration and production for many years. There have been known releases of hazardous substances, wastes, or hydrocarbons at the properties, and some of these sites are undergoing active remediation. The risks associated with these environmental conditions, and the cost of remediation, were assumed by ENP, subject only to limited indemnity from the seller of the Elk Basin assets. Releases may also have occurred in the past that have not yet been discovered, which could require costly future remediation. In addition, ENP assumed the risk of various other unknown or unasserted liabilities associated with the Elk Basin assets that relate to events that occurred prior to ENP’s acquisition. If a significant release or event occurred in the past, the liability for which was not retained by the seller or for which indemnification from the seller is not available, it could adversely affect our results of operations, financial position, and cash flows.
 
ENP’s Elk Basin assets include a natural gas processing plant. Previous environmental investigations of the Elk Basin natural gas processing plant indicate historical soil and groundwater contamination by hydrocarbons and the presence of asbestos-containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected historical contamination, the extent of the contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event ENP ceased operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. ENP does not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future nor a need to commence remedial activities at this time. However, a regulatory agency could require ENP to investigate and remediate any contamination even while the gas plant remains in operation. As of December 31, 2009, ENP has recorded $4.7 million as future abandonment liability for decommissioning the Elk Basin natural gas processing plant. Due to the significant uncertainty associated with the known and unknown environmental liabilities at the gas plant, ENP’s estimate of the future abandonment liability includes a large contingency. ENP’s estimates of the future abandonment liability and compliance costs are subject to change and the actual cost of these items could vary significantly from those estimates.
 
Water Discharges.  The Clean Water Act (“CWA”), and analogous state laws, impose strict controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control, and countermeasure requirements of CWA require appropriate containment berms and similar structures to help


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prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of CWA and analogous state laws and regulations.
 
The primary federal law for oil spill liability is the Oil Pollution Act (“OPA”), which addresses three principal areas of oil pollution — prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.
 
Air Emissions.  Oil and natural gas exploration and production operations are subject to the federal Clean Air Act (“CAA”), and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including oil and natural gas exploration and production facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.
 
Permits and related compliance obligations under CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and natural gas exploration and production operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.
 
Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the atmosphere. In response to such studies, Congress is considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Supreme Court’s holding in Massachusetts that greenhouse gases fall under CAA’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under various CAA programs, including those used in oil and natural gas exploration and production operations. It is not possible to predict how legislation that may be enacted to address greenhouse gas emissions would impact the oil and natural gas exploration and production business. However, future laws and regulations could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial position, demand for our operations, results of operations, and cash flows.
 
Activities on Federal Lands.  Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and


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comment. Our current exploration and production activities and planned exploration and development activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of our oil and natural gas projects.
 
Occupational Safety and Health Act (“OSH Act”) and Other Laws and Regulation.  We are subject to the requirements of OSH Act and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The Occupational Safety and Health Administration’s hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSH Act and comparable requirements.
 
We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities during 2009, and, as of the date of this Report, we are not aware of any environmental issues or claims that will require material capital expenditures in the future. However, accidental spills or releases may occur in the course of our operations, and we may incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, the passage of more stringent laws or regulations in the future may have a negative impact on our business, financial condition, or results of operations.
 
 
The oil and natural gas industry is extensively regulated by numerous federal, state, and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities, and locations of production.
 
Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
 
Development and Production.  Our operations are subject to various types of regulation at the federal, state, and local levels. These types of regulation include requiring permits for the development of wells, development bonds, and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
 
  •  location of wells;
 
  •  methods of developing and casing wells;
 
  •  surface use and restoration of properties upon which wells are drilled;
 
  •  plugging and abandoning of wells; and
 
  •  notification of surface owners and other third parties.
 
State laws regulate the size and shape of development and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts in order to


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facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdiction.
 
Natural Gas Gathering.  Section 1(b) of the Natural Gas Act (“NGA”), exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (the “FERC”). ENP owns a number of facilities that it believes would meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC’s jurisdiction. In the states in which ENP operates, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirement and complaint-based rate regulation.
 
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since the FERC has taken a less stringent approach to regulation of the offshore gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations could be adversely affected should they become subject to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
 
Sales of Natural Gas.  The price at which we buy and sell natural gas is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms, and cost of pipeline transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with which we compete.
 
The Energy Policy Act of 2005 (“EP Act 2005”) gave the FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended NGA to prohibit market manipulation and also amended NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to increase civil and criminal penalties for any violations of NGA, NGPA, and any rules, regulations, or orders of the FERC to up to $1,000,000 per day, per violation. In 2006, the FERC issued a rule regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement, or omit a material fact, or engage in any practice, act, or course of business that operates or would operate as a fraud. This rule works together with the FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.


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State Regulation.  The various states regulate the development, production, gathering, and sale of oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Reduced rates or credits may apply to certain types of wells and production methods.
 
In addition to production taxes, Texas and Montana each impose ad valorem taxes on oil and natural gas properties and production equipment. Wyoming and New Mexico impose an ad valorem tax on the gross value of oil and natural gas production in lieu of an ad valorem tax on the underlying oil and natural gas properties. Wyoming also imposes an ad valorem tax on production equipment. North Dakota imposes an ad valorem tax on gross oil and natural gas production in lieu of an ad valorem tax on the underlying oil and gas leases or on production equipment used on oil and gas leases.
 
States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of oil and natural gas resources. States may regulate rates of production and establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but they may do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.
 
Federal, State, or Native American Leases.  Our operations on federal, state, or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Federal Bureau of Land Management, Minerals Management Service, and other agencies.
 
 
The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards, and other potential events that can adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation, or leasehold acquisitions or result in loss of properties.
 
In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost. If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.
 
 
As of December 31, 2009, we had a staff of 421 persons, including 35 engineers, 18 geologists, and 13 landmen, none of which are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory.
 
 
Our principal executive office is located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102. Our main telephone number is (817) 877-9955.
 
 
We make available electronically, free of charge through our website (www.encoreacq.com), our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and other filings with the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish such material, to the SEC. In addition, you may read and copy any materials that we file with the SEC at its public reference room at


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100 F Street, N.E., Room 1580, Washington, D.C. 20549. Information concerning the operation of the public reference room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy statements, and other information regarding issuers, like us, that file electronically with the SEC.
 
We have adopted a code of business conduct and ethics that applies to all directors, officers, and employees, including our principal executive officer and principal financial officer. The code of business conduct and ethics is available on our website. In the event that we make changes in, or provide waivers from, the provisions of this code of business conduct and ethics that the SEC or the NYSE require us to disclose, we intend to disclose these events on our website.
 
Our Board has four standing committees: (1) audit; (2) compensation; (3) nominating and corporate governance; and (4) special stock award. Our Board committee charters, code of business conduct and ethics, and corporate governance guidelines are available on our website.
 
The information on our website or any other website is not incorporated by reference into this Report.


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ITEM 1A.   RISK FACTORS
 
You should carefully consider each of the following risks and all of the information provided elsewhere in this Report. If any of the risks described below or elsewhere in this Report were actually to occur, our business, financial condition, results of operations, or cash flows could be materially and adversely affected. In that case, we may be unable to pay interest on, or the principal of, our debt securities, the trading price of our common stock could decline, and you could lose all or part of your investment.
 
Failure to complete the Merger or delays in completing the Merger could negatively affect our stock price and future business and operations.
 
There is no assurance that we will be able to consummate the Merger. If the Merger is not completed for any reason, we may be subject to a number of risks, including the following:
 
  •  we will not realize the benefits expected from the Merger, including a potentially enhanced financial and competitive position;
 
  •  the current market price of our common stock may reflect a market assumption that the Merger will occur and a failure to complete the Merger could result in a negative perception by the stock market of us generally and a resulting decline in the market price of our common stock; and
 
  •  certain costs relating to the Merger, including certain investment banking, financing, legal, and accounting fees and expenses, must be paid even if the Merger is not completed, and we may be required to pay substantial fees to Denbury if the Merger Agreement is terminated under specified circumstances.
 
Delays in completing the Merger could exacerbate uncertainties concerning the effect of the Merger, which may have an adverse effect on the business following the Merger and could defer or detract from the realization of the benefits expected to result from the Merger.
 
There may be substantial disruption to our business and distraction of our management and employees as a result of the Merger.
 
There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the Merger may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to us.
 
Business uncertainties and contractual restrictions while the Merger is pending may have an adverse effect on us.
 
Uncertainty about the effect of the Merger on employees, suppliers, partners, regulators, and customers may have an adverse effect on us. These uncertainties may impair our ability to attract, retain, and motivate key personnel until the Merger is consummated and could cause suppliers, customers, and others that deal with us to defer purchases or other decisions concerning us or seek to change existing business relationships with us. In addition, the Merger Agreement restricts us from making certain acquisitions and taking other specified actions without Denbury’s approval. These restrictions could prevent us from pursuing attractive business opportunities that may arise prior to the completion of the Merger.
 
 
Because our oil and natural gas properties are a depleting asset, our future oil and natural gas reserves, production volumes, and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to


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develop, find, or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition, and results of operations.
 
We need to make substantial capital expenditures to maintain and grow our asset base. If lower oil and natural gas prices or operating difficulties result in our cash flows from operations being less than expected or limit our ability to borrow under our revolving credit facility, we may be unable to expend the capital necessary to find, develop, or acquire additional reserves.
 
 
The oil and natural gas markets are very volatile, and we cannot accurately predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of additional factors that are beyond our control, such as:
 
  •  overall domestic and global economic conditions;
 
  •  weather conditions;
 
  •  political and economic conditions in oil and natural gas producing countries, including those in the Middle East, Africa, and South America;
 
  •  actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;
 
  •  the impact of U.S. dollar exchange rates on oil and natural gas prices;
 
  •  technological advances affecting energy consumption and energy supply;
 
  •  domestic and foreign governmental regulations and taxation;
 
  •  the impact of energy conservation efforts;
 
  •  the proximity, capacity, cost, and availability of oil and natural gas pipelines and other transportation facilities;
 
  •  the availability of refining capacity; and
 
  •  the price and availability of alternative fuels.
 
The worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with substantial losses in worldwide equity markets led to an extended worldwide economic slowdown in 2008 and 2009, which is expected to continue into 2010. The slowdown in economic activity has reduced worldwide demand for energy and resulted in lower oil and natural gas prices.
 
Our revenue, profitability, and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:
 
  •  negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;
 
  •  reduce the amount of cash flow available for capital expenditures, repayment of indebtedness, and other corporate purposes; and
 
  •  result in a decrease in the borrowing base under our revolving credit facility or otherwise limit our ability to borrow money or raise additional capital.


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The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. For example, the oil production from our Elk Basin assets has historically sold at a higher discount to NYMEX as compared to our Permian Basin assets due to competition from Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, and corresponding deep pricing discounts by regional refiners. Increases in differentials could significantly reduce our cash available for development of our properties and adversely affect our financial condition, results of operations, and cash flows.
 
 
Declines in oil and natural gas prices may result in our having to make substantial downward revisions to our estimated reserves. If this occurs, or if our estimates of development costs increase, production data factors change, or development results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties and goodwill. If we incur such impairment charges, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility. In addition, any write-downs that result in a reduction in our borrowing base could require prepayments of indebtedness under our revolving credit facility.
 
 
To reduce our exposure to fluctuations in the price of oil and natural gas, we enter into derivative arrangements for a significant portion of our forecasted oil and natural gas production. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities, as well as to the ability of counterparties under our commodity derivative contracts to satisfy their obligations to us. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual prices we realize on our production. Changes in oil and natural gas prices could result in losses under our commodity derivative contracts.
 
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from the sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our derivative activities are subject to the following risks:
 
  •  a counterparty may not perform its obligation under the applicable derivative instrument, which risk may have been exacerbated by the worldwide financial and credit crisis; and
 
  •  there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, which may result in payments to our derivative counterparty that are not accompanied by our receipt of higher prices from our production in the field.


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In addition, certain commodity derivative contracts that we may enter into may limit our ability to realize additional revenues from increases in the prices for oil and natural gas.
 
We have oil and natural gas commodity derivative contracts covering a significant portion of our forecasted production for 2010. These contracts are intended to reduce our exposure to fluctuations in the price of oil and natural gas. We have a much smaller commodity derivative contract portfolio covering our forecasted production in 2011 and 2012. After 2010, and unless we enter into new commodity derivative contracts, our exposure to oil and natural gas price volatility will increase significantly each year as our commodity derivative contracts expire. We may not be able to obtain additional commodity derivative contracts on acceptable terms, if at all. Our failure to mitigate our exposure to commodity price volatility through commodity derivative contracts could have a negative effect on our financial condition and results of operation and significantly reduce our cash flows.
 
 
As of December 31, 2009, we were entitled to future payments of approximately $61.0 million from counterparties under our commodity derivative contracts. The worldwide financial and credit crisis may have adversely affected the ability of these counterparties to fulfill their obligations to us. If one or more of our counterparties is unable or unwilling to make required payments to us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and results of operations.
 
 
It is not possible to measure underground accumulations of oil or natural gas in an exact way. In estimating our oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to oil and natural gas prices, production levels, capital expenditures, operating and development costs, the effects of regulation, and availability of funds. If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and our estimates of the future net cash flows from our reserves could change significantly.
 
Our Standardized Measure is calculated using prices and costs in effect as of the date of estimation, less future development, production, net abandonment, and income tax expenses, and discounted at 10 percent per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. The Standardized Measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.
 
The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures.
 
The timing of both our production and our incurrence of expenses in connection with the development, production, and abandonment of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based


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on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
 
 
The cost of developing, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. If commodity prices decline, the cost of developing, completing and operating a well may not decline in proportion to the prices that we receive for our production, resulting in higher operating and capital costs as a percentage of oil and natural gas revenues. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and production operations may be curtailed, delayed, or canceled as a result of other factors, including:
 
  •  higher costs, shortages, or delivery delays of rigs, equipment, labor, or other services;
 
  •  unexpected operational events and/or conditions;
 
  •  reductions in oil and natural gas prices;
 
  •  increases in severance taxes;
 
  •  limitations in the market for oil and natural gas;
 
  •  adverse weather conditions and natural disasters;
 
  •  facility or equipment malfunctions, and equipment failures or accidents;
 
  •  title problems;
 
  •  pipe or cement failures and casing collapses;
 
  •  compliance with environmental and other governmental requirements;
 
  •  environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases;
 
  •  lost or damaged oilfield development and service tools;
 
  •  unusual or unexpected geological formations, and pressure or irregularities in formations;
 
  •  loss of drilling fluid circulation;
 
  •  fires, blowouts, surface craterings, and explosions;
 
  •  uncontrollable flows of oil, natural gas, or well fluids; and
 
  •  loss of leases due to incorrect payment of royalties.
 
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
 
 
A significant portion of our production and reserves rely on secondary and tertiary recovery techniques. If production response is less than forecasted for a particular project, then the project may be uneconomic or


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generate less cash flow and reserves than we had estimated prior to investing capital. Risks associated with secondary and tertiary recovery techniques include, but are not limited to, the following:
 
  •  lower than expected production;
 
  •  longer response times;
 
  •  higher operating and capital costs;
 
  •  shortages of equipment; and
 
  •  lack of technical expertise.
 
If any of these risks occur, it could adversely affect our financial condition or results of operations.
 
 
Higher oil and natural gas prices generally increase the demand for rigs, equipment, and crews and can lead to shortages of, and increasing costs for, development equipment, services, and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues.
 
 
Acquisitions are an essential part of our growth strategy, and our ability to acquire additional properties on favorable terms is important to our long-term growth. We may be unable to make acquisitions because we are:
 
  •  unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
 
  •  unable to obtain financing for these acquisitions on economically acceptable terms; or
 
  •  outbid by competitors.
 
Competition for acquisitions is intense and may increase the cost of, or cause us to refrain from, completing acquisitions. If we are unable to acquire properties with proved reserves, our total proved reserves could decline as a result of our production. Future acquisitions could result in our incurring additional debt, contingent liabilities, and expenses, all of which could have a material adverse effect on our financial condition and results of operations. Furthermore, our financial position and results of operations may fluctuate significantly from period to period based on whether significant acquisitions are completed in particular periods.
 
 
Any acquisition involves potential risks, including, among other things:
 
  •  the validity of our assumptions about reserves, future production, revenues, capital expenditures, and operating costs, including synergies;
 
  •  an inability to integrate the businesses we acquire successfully;
 
  •  a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity under our revolving credit facility to finance acquisitions;
 
  •  a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;


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  •  the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which our indemnity is inadequate;
 
  •  the diversion of management’s attention from other business concerns;
 
  •  an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets;
 
  •  natural disasters;
 
  •  the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill, or other intangible assets, asset devaluation, or restructuring charges;
 
  •  unforeseen difficulties encountered in operating in new geographic areas; and
 
  •  customer or key employee losses at the acquired businesses.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
 
Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
 
 
We have extensive operations in the CCA. Our CCA properties represented approximately 32 percent of our proved reserves as of December 31, 2009 and accounted for 25 percent of our 2009 production. Any circumstance or event that negatively impacts production or marketing of oil and natural gas in the CCA would materially affect our results of operations and cash flows.
 
We depend on certain customers for a substantial portion of our sales. If these customers reduce the volumes of oil and natural gas they purchase from us, our revenues and cash available for distribution will decline to the extent we are not able to find new customers for our production.
 
For 2009, our largest purchaser was Eighty-Eight Oil, which accounted for 18 percent of our total sales of production. If customer, or any other significant customer, were to reduce the production purchased from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.
 
 
The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and natural gas companies, and possess financial, technical, and personnel resources substantially greater than us. Those companies may be able to develop and acquire more prospects and productive properties than our resources permit. Our ability to acquire additional properties and to discover reserves in


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the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Some of our competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for, and purchase a greater number of properties than our resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local, and other laws and regulations. Our inability to compete effectively could have a material adverse impact on our business activities, financial condition, and results of operations.
 
 
As of December 31, 2009, we had total consolidated debt of $1.2 billion and $889.7 million of consolidated available borrowing capacity under our revolving credit facilities. We have the ability to incur additional debt under our revolving credit facilities, subject to borrowing base limitations. Our future indebtedness could have important consequences to us, including:
 
  •  our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may not be available on favorable terms, if at all;
 
  •  covenants contained in future debt arrangements may require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
 
  •  we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and
 
  •  our debt level will make us more vulnerable to competitive pressures, or a downturn in our business or the economy in general, than our competitors with less debt.
 
Our ability to service our indebtedness depends upon, among other things, our future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.
 
In addition, we are not currently permitted to offset the value of our commodity derivative contracts with a counterparty against amounts that may be owing to such counterparty under our revolving credit facilities.
 
We are unable to predict the impact of the recent downturn in the credit markets and the resulting costs or constraints in obtaining financing on our business and financial results.
 
U.S. and global credit and equity markets have recently undergone significant disruption, making it difficult for many businesses to obtain financing on acceptable terms. In addition, equity markets are continuing to experience wide fluctuations in value. If these conditions continue or worsen, our cost of borrowing may increase, and it may be more difficult to obtain financing in the future. In addition, an increasing number of financial institutions have reported significant deterioration in their financial condition. If any of the financial institutions are unable to perform their obligations under our revolving credit agreements and other contracts, and we are unable to find suitable replacements on acceptable terms, our results of operations, liquidity, and cash flows could be adversely affected. We also face challenges relating to the


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impact of the disruption in the global financial markets on other parties with which we do business, such as customers and suppliers. The inability of these parties to obtain financing on acceptable terms could impair their ability to perform under their agreements with us and lead to various negative effects on us, including business disruption, decreased revenues, and increases in bad debt write-offs. A sustained decline in the financial stability of these parties could have an adverse impact on our business, results of operations, and liquidity.
 
Our revolving credit facilities have substantial restrictions and financial covenants that may restrict our business and financing activities.
 
The operating and financial restrictions and covenants in our revolving credit facilities and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand, or pursue our business activities.
 
Our ability to comply with the restrictions and covenants in our revolving credit facilities in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, or financial ratios in our revolving credit facilities, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, obligations under our revolving credit facilities are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facilities, the lenders could seek to foreclose on our assets.
 
Our revolving credit facilities limit the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid immediately, or we will be required to pledge other oil and natural gas properties as additional collateral.
 
 
There are a variety of operating risks inherent in our wells, gathering systems, pipelines, and other facilities, such as leaks, explosions, mechanical problems, and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations, and substantial revenue losses. The location of our wells, gathering systems, pipelines, and other facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could significantly increase the level of damages resulting from these risks.
 
We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and our insurance may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, and results of operations.


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The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipelines, oil and natural gas gathering systems, and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.
 
 
Other companies operated approximately 21 percent of our properties (measured by total reserves) and approximately 44 percent of our wells as of December 31, 2009. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in development or acquisition activities and lead to unexpected future costs.
 
 
Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate, and abandon oil and natural gas wells and related pipeline and processing facilities. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, state, and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
 
Our business is subject to federal, state, and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, and results of operations. Please read “Items 1 and 2. Business and Properties — Environmental Matters and Regulation” and “Items 1 and 2. Business and Properties — Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.
 
Possible regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to the warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases. The U.S. Congress is considering climate-related legislation to reduce emissions of greenhouse gases. In addition, at least 20 states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. The EPA has adopted regulations requiring reporting of greenhouse gas emissions from certain facilities and is considering additional regulation of greenhouse gases as “air pollutants” under the CAA. Passage of climate change legislation or other regulatory initiatives by


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Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect our operations and the demand for oil and natural gas.
 
 
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas production activities. In addition, we often indemnify sellers of oil and natural gas properties for environmental liabilities they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state, and local environmental and safety laws and regulations, which have become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, imposition of cleanup and site restoration costs, liens and, to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.
 
Strict, joint, and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations, or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our profitability could be adversely affected.
 
 
Development and exploratory drilling and production activities are subject to many risks, including the risk that we will not discover commercially productive oil or natural gas reserves. In order to further our development efforts, we acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not be required to impair our initial investments.
 
In addition, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us will be productive, or that we will recover all or any portion of our investment in such unproved property or wells. The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions, and shortages or delays in the delivery of equipment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry holes, but also from wells that are productive but do not produce sufficient commercial quantities to cover the development, operating, and other costs. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas, and our ability to add reserves at an acceptable cost.
 
Seismic technology does not allow us to obtain conclusive evidence that oil or natural gas reserves are present or economically producible prior to spudding a well. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The use of seismic data and other technologies also requires greater up-front costs than development on proved properties.
 
 
We make and will continue to make substantial capital expenditures in development, exploitation, and exploration projects. We intend to finance these capital expenditures through operating cash flows. However,


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additional financing sources may be required in the future to fund our capital expenditures. Financing may not continue to be available under existing or new financing arrangements, or on acceptable terms, if at all. If additional capital resources are not available, we may be forced to curtail our development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.
 
 
Our development success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for experienced geologists, engineers, and other professionals is extremely intense and the cost of attracting and retaining technical personnel has increased significantly in recent years. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed. Furthermore, escalating personnel costs could adversely affect our results of operations and financial condition.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS
 
There were no unresolved SEC staff comments as of December 31, 2009.
 
ITEM 3.   LEGAL PROCEEDINGS
 
We are a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these legal proceedings will have a material adverse effect on our business, financial condition, results of operations, or liquidity.
 
Litigation Related to the Merger
 
Three shareholder lawsuits styled as class actions have been filed against us and our Board related to the Merger. The lawsuits are entitled:
 
(1) Sanjay Israni, Individually and On Behalf of All Others Similarly Situated vs. Encore Acquisition Company et al. (filed November 4, 2009 in the District Court of Tarrant County, Texas);
 
(2) Teamsters Allied Benefit Funds, Individually and On Behalf of All Others Similarly Situated vs. Encore Acquisition Company et al. (filed November 5, 2009 in the Court of Chancery in the State of Delaware); and
 
(3) Thomas W. Scott, Jr., individually and on behalf of all others similarly situated v. Encore Acquisition Company et al. (filed November 6, 2009 in the District Court of Tarrant County, Texas).
 
The Teamsters and Scott lawsuits also name Denbury as a defendant. The complaints generally allege that (1) our directors breached their fiduciary duties in negotiating and approving the Merger and by administering a sale process that failed to maximize shareholder value and (2) we, and, in the case of the Teamsters and Scott complaints, Denbury aided and abetted our directors in breaching their fiduciary duties. The Teamsters complaint also alleges that our directors and executives stand to receive substantial financial benefits if the Merger is consummated on its current terms. The plaintiffs in these lawsuits seek, among other things, to enjoin the Merger and to rescind the Merger Agreement. We and Denbury have entered into a Memorandum of Understanding with the plaintiffs in these lawsuits agreeing in principle to the settlement of the lawsuits based upon inclusion in the joint proxy statement/prospectus of additional disclosures requested by the plaintiffs, and agreeing that the parties to the lawsuits will use best efforts to enter into a definitive settlement agreement and seek court approval for the settlement which would be binding on all of our shareholders who do not opt-out of the settlement.
 
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
There were no matters submitted to a vote of stockholders during the fourth quarter of 2009.


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ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
Our common stock, par value $0.01 per share, is listed on the NYSE under the symbol “EAC.” The following table sets forth high and low sales prices of our common stock for the periods indicated:
 
                 
    High     Low  
 
2009
               
Quarter ended December 31
  $ 49.00     $ 35.64  
Quarter ended September 30
  $ 39.93     $ 25.53  
Quarter ended June 30
  $ 39.01     $ 22.30  
Quarter ended March 31
  $ 32.11     $ 17.04  
2008
               
Quarter ended December 31
  $ 41.05     $ 17.89  
Quarter ended September 30
  $ 79.62     $ 36.84  
Quarter ended June 30
  $ 77.35     $ 38.45  
Quarter ended March 31
  $ 40.74     $ 26.10  
 
On February 17, 2010, the closing sales price of our common stock as reported by the NYSE was $50.03 per share and we had approximately 418 shareholders of record. This number does not include owners for whom common stock may be held in “street” name.
 
 
In October 2008, we announced that the Board authorized a share repurchase program of up to $40 million of our common stock. As of December 31, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the fourth quarter of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of December 31, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.
 
 
No dividends have been declared or paid on our common stock. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of the Board after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, and plans for expansion. The declaration and payment of dividends is restricted by our existing revolving credit facility and the indentures governing our senior subordinated notes. Future debt agreements may also restrict our ability to pay dividends.


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The following graph compares our cumulative total stockholder return during the period from January 1, 2005 to December 31, 2009 with total stockholder return during the same period for the Independent Oil and Gas Index and the Standard & Poor’s 500 Index. The graph assumes that $100 was invested in our common stock and each index on January 1, 2005 and that all dividends, if any, were reinvested. The following graph is being furnished pursuant to SEC rules and will not be incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent we specifically incorporate it by reference.
 
Comparison of Total Return Since January 1, 2005 Among Encore
Acquisition Company, the Standard & Poor’s 500 Index, and the
Independent Oil and Gas Index
 
(PERFORMANCE GRAPH)


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ITEM 6.   SELECTED FINANCIAL DATA
 
The following table shows selected historical financial data for the periods and as of the periods indicated. The following selected consolidated financial and operating data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data”:
 
                                         
    Year Ended December 31,(a)  
    2009     2008     2007     2006     2005  
    (In thousands, except per share amounts)  
 
Consolidated Statements of Operations Data:
                                       
Revenues(b):
                                       
Oil
  $ 549,391     $ 897,443     $ 562,817     $ 346,974     $ 307,959  
Natural gas
    131,185       227,479       150,107       146,325       149,365  
Marketing(c)
    4,840       10,496       42,021       147,563        
                                         
Total revenues
    685,416       1,135,418       754,945       640,862       457,324  
                                         
Expenses:
                                       
Production:
                                       
Lease operating(d)
    165,062       175,115       143,426       98,194       69,744  
Production, ad valorem, and severance taxes
    69,539       110,644       74,585       49,780       45,601  
Depletion, depreciation, and amortization
    290,776       228,252       183,980       113,463       85,627  
Impairment of long-lived assets(e)
    9,979       59,526                    
Exploration
    52,488       39,207       27,726       30,519       14,443  
General and administrative(d)
    54,024       48,421       39,124       23,194       17,268  
Marketing(c)
    3,994       9,570       40,549       148,571        
Derivative fair value loss (gain)(f)
    59,597       (346,236 )     112,483       (24,388 )     5,290  
Loss on early redemption of debt(g)
                            19,477  
Provision for doubtful accounts
    7,686       1,984       5,816       1,970       231  
Other operating
    25,761       12,975       17,066       8,053       9,254  
                                         
Total expenses
    738,906       339,458       644,755       449,356       266,935  
                                         
Operating income (loss)
    (53,490 )     795,960       110,190       191,506       190,389  
                                         
Other income (expenses):
                                       
Interest
    (79,017 )     (73,173 )     (88,704 )     (45,131 )     (34,055 )
Other
    2,447       3,898       2,667       1,429       1,039  
                                         
Total other expenses
    (76,570 )     (69,275 )     (86,037 )     (43,702 )     (33,016 )
                                         
Income (loss) before income taxes
    (130,060 )     726,685       24,153       147,804       157,373  
Income tax benefit (provision)
    32,173       (241,621 )     (14,476 )     (55,406 )     (53,948 )
                                         
Consolidated net income (loss)
    (97,887 )     485,064       9,677       92,398       103,425  
Less: net loss (income) attributable to noncontrolling interest
    16,752       (54,252 )     7,478              
                                         
Net income (loss) attributable to EAC stockholders
  $ (81,135 )   $ 430,812     $ 17,155     $ 92,398     $ 103,425  
                                         
Net income (loss) per common share:
                                       
Basic
  $ (1.54 )   $ 8.10     $ 0.32     $ 1.75     $ 2.10  
Diluted
  $ (1.54 )   $ 8.01     $ 0.31     $ 1.74     $ 2.07  
Weighted average common shares outstanding:
                                       
Basic
    52,634       52,270       53,170       51,865       48,682  
Diluted
    52,634       52,866       53,629       52,356       49,303  


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    Year Ended December 31,(a)  
    2009     2008     2007     2006     2005  
    (In thousands, except per unit amounts)  
 
Total Production Volumes:
                                       
Oil (Bbls)
    10,016       10,050       9,545       7,335       6,871  
Natural gas (Mcf)
    33,919       26,374       23,963       23,456       21,059  
Combined (BOE)
    15,669       14,446       13,539       11,244       10,381  
Average Realized Prices:
                                       
Oil ($/Bbl)
  $ 54.85     $ 89.30     $ 58.96     $ 47.30     $ 44.82  
Natural gas ($/Mcf)
    3.87       8.63       6.26       6.24       7.09  
Combined ($/BOE)
    43.43       77.87       52.66       43.87       44.05  
Average Costs per BOE:
                                       
Lease operating(d)
  $ 10.53     $ 12.12     $ 10.59     $ 8.73     $ 6.72  
Production, ad valorem, and severance taxes
    4.44       7.66       5.51       4.43       4.39  
Depletion, depreciation, and amortization
    18.56       15.80       13.59       10.09       8.25  
Impairment of long-lived assets(e)
    0.64       4.12                    
Exploration
    3.35       2.71       2.05       2.71       1.39  
General and administrative(d)
    3.45       3.35       2.89       2.06       1.67  
Derivative fair value loss (gain)(f)
    3.80       (23.97 )     8.31       (2.17 )     0.51  
Provision for doubtful accounts
    0.49       0.14       0.43       0.18       0.02  
Other operating
    1.64       0.90       1.26       0.71       0.89  
Marketing, net of revenues(c)
    (0.05 )     (0.06 )     (0.11 )     0.09        
Consolidated Statements of Cash Flows Data:
                                       
Cash provided by (used in):
                                       
Operating activities
  $ 745,677     $ 663,237     $ 319,707     $ 297,333     $ 292,269  
Investing activities
    (769,430 )     (728,346 )     (929,556 )     (397,430 )     (573,560 )
Financing activities
    35,672       65,444       610,790       99,206       281,842  
 
                                         
    As of December 31,(a)  
    2009     2008     2007     2006     2005  
    (In thousands)  
 
Proved Reserves:
                                       
Oil (Bbls)
    147,094       134,452       188,587       153,434       148,387  
Natural gas (Mcf)
    439,072       307,520       256,447       306,764       283,865  
Combined (BOE)
    220,273       185,705       231,328       204,561       195,698  
Consolidated Balance Sheets Data:
                                       
Working capital
  $ (62,854 )   $ 188,678     $ (16,220 )   $ (40,745 )   $ (56,838 )
Total assets
    3,663,961       3,633,195       2,784,561       2,006,900       1,705,705  
Long-term debt
    1,214,097       1,319,811       1,120,236       661,696       673,189  
Equity
    1,630,833       1,483,248       1,070,689       816,865       546,781  
 
 
(a) We acquired certain oil and natural gas properties and related assets in the Mid-Continent and east Texas regions in August 2009. We acquired certain oil and natural gas properties and related assets in the Big Horn and Williston Basins in March 2007 and April 2007, respectively. We also acquired Crusader Energy Corporation in October 2005. The operating results of these acquisitions are included in our Consolidated Statements of Operations from the date of acquisition forward. We disposed of certain oil and natural gas properties and related assets in the Mid-Continent in June 2007. The operating results of this disposition are included in our Consolidated Statements of Operations through the date of disposition.
 
(b) For 2009, 2008, 2007, 2006, and 2005, we reduced oil and natural gas revenues for net profits interests owned by others by $31.8 million, $56.5 million, $32.5 million, $23.4 million, and $21.2 million, respectively.

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(c) In 2006, we began purchasing third-party oil Bbls from a counterparty other than to whom the Bbls were sold for aggregation and sale with our own equity production in various markets. These purchases assisted us in marketing our production by decreasing our dependence on individual markets. These activities allowed us to aggregate larger volumes, facilitated our efforts to maximize the prices we received for production, provided for a greater allocation of future pipeline capacity in the event of curtailments, and enabled us to reach other markets. In 2007, we discontinued the purchase of oil from third party companies as market conditions changed and pipeline space was gained. Implementing this change allowed us to focus on the marketing of our own oil production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.
 
(d) On January 1, 2006, we adopted the provisions of ASC 718, 505-50, and 260-10-60-1A (formerly SFAS No. 123R, “Share-Based Payment”). Due to the adoption of ASC 718, 505-50, and 260-10-60-1A, non-cash equity-based compensation expense for 2005 has been reclassified to allocate the amount to the same respective income statement lines as the respective employees’ cash compensation. In 2005, this resulted in increases in LOE of $1.3 million ($0.13 per BOE) and in general and administrative (“G&A”) expense of $2.6 million ($0.25 per BOE).
 
(e) During 2009 and 2008, circumstances indicated that the carrying value of certain of our oil and natural gas properties in the Tuscaloosa Marine Shale may not be recoverable. For the proved oil and natural gas property costs, we compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a pretax write-down of the value of oil and natural gas properties. For the unproved acreage costs, we recorded a valuation allowance to reflect the portion of the property costs that we believe will not be transferred to proved properties over the remaining life of the lease. The impairment of proved oil and natural gas properties and unproved acreage in the Tuscaloosa Marine Shale totaled $10.0 million and $59.5 million during 2009 and 2008, respectively. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.
 
(f) During July 2006, we elected to discontinue hedge accounting prospectively for all of our remaining commodity derivative contracts which were previously accounted for as hedges. From that point forward, all mark-to-market gains or losses on all commodity derivative contracts are recorded in “Derivative fair value loss (gain)” while in periods prior to that point, only the ineffective portions of commodity derivative contracts which were designated as hedges were recorded in “Derivative fair value loss (gain).”
 
(g) In 2005, we recorded a $19.5 million loss on early redemption of debt related to the redemption premium and the expensing of unamortized debt issuance costs of our 83/8% Senior Subordinated Notes due 2012. We redeemed all $150 million of such notes with proceeds received from the issuance of $300 million of our 6.0% Senior Subordinated Notes due 2015.


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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis of our consolidated financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes and supplementary data thereto included in “Item 8. Financial Statements and Supplementary Data.” The following discussion and analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Actual results could differ materially from those discussed in the forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the headings: “Information Concerning Forward-Looking Statements” and “Item 1A. Risk Factors.”
 
Introduction
 
In this management’s discussion and analysis of financial condition and results of operations, the following are discussed and analyzed:
 
  •  Overview of Business
 
  •  2009 Highlights
 
  •  Results of Operations
 
— Comparison of 2009 to 2008
 
— Comparison of 2008 to 2007
 
  •  Capital Commitments, Capital Resources, and Liquidity
 
  •  Changes in Prices
 
  •  Critical Accounting Policies and Estimates
 
  •  New Accounting Pronouncements
 
  •  Information Concerning Forward-Looking Statements
 
Overview of Business
 
We are a Delaware corporation engaged in the acquisition, development, exploitation, exploration, and production of oil and natural gas reserves from onshore fields in the United States. Our business strategies include:
 
  •  Maintaining an active development program to maximize existing reserves and production;
 
  •  Utilizing EOR techniques to maximize existing reserves and production;
 
  •  Expanding our reserves, production, and development inventory through a disciplined acquisition program;
 
  •  Exploring for reserves; and
 
  •  Operating in a cost effective, efficient, and safe manner.
 
As previously discussed, on October 31, 2009, we entered into the Merger Agreement with Denbury pursuant to which we have agreed to merge with and into Denbury, with Denbury as the surviving entity. The Merger Agreement, which was unanimously approved by our Board and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of our issued and outstanding shares of common stock in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of our interest


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in ENP. We expect to complete the Merger during the first quarter of 2010, although completion by any particular date cannot be assured.
 
At December 31, 2009, our oil and natural gas properties had estimated total proved reserves of 147.1 MMBbls of oil and 439.1 Bcf of natural gas, based on 2009 12-month average market prices of $61.18 per Bbl of oil and $3.83 per Mcf of natural gas. On a BOE basis, our proved reserves were 220.3 MMBOE at December 31, 2009, of which approximately 67 percent was oil, approximately 80 percent was proved developed, and approximately 20 proved undeveloped.
 
Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Average NYMEX prices deteriorated significantly in 2009. Our oil wellhead differentials to NYMEX deteriorated slightly in 2009 as we realized 89 percent of the average NYMEX oil price, as compared to 90 percent in 2008. Our natural gas wellhead differentials to NYMEX improved in 2009 as we realized 97 percent of the average NYMEX natural gas price, as compared to 95 percent in 2008. Commodity prices are influenced by many factors that are outside of our control. We cannot accurately predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by entering into commodity derivative contracts for a portion of our forecasted production. For a discussion of factors that influence commodity prices and risks associated with our commodity derivative contracts, please read “Item 1A. Risk Factors.”
 
2009 Highlights
 
Our financial and operating results for 2009 included the following:
 
  •  Our average daily production volumes increased nine percent to 42,929 BOE/D as compared to 39,470 BOE/D in 2008. Oil represented 64 percent and 70 percent of our total production volumes in 2009 and 2008, respectively.
 
  •  We invested $706.5 million in oil and natural gas activities, of which $286.9 million was invested in development, exploitation, and exploration activities, yielding 112 gross (42.3 net) productive wells, and $419.5 million was invested in acquisitions, primarily related to our EXCO asset acquisition.
 
  •  In September, we issued 2,750,000 shares of our common stock at a price to the public of $37.40 per common share. The net proceeds of approximately $100.6 million were used to reduce outstanding borrowings under our revolving credit facility.
 
  •  In August, we acquired certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO for approximately $357.4 million in cash (including a deposit of $37.5 million made in June 2009).
 
  •  In August, we sold the Rockies and Permian Basin Assets to ENP for approximately $179.6 million in cash.
 
  •  In June, we sold the Williston Basin Assets to ENP for approximately $25.2 million in cash.
 
  •  In April, we issued $225 million of our 9.5% Senior Subordinated Notes due 2016. We used the net proceeds of approximately $202.4 million to reduce outstanding borrowings under our revolving credit facility.
 
  •  In March, we elected to monetize certain of our 2009 oil derivative contracts and received net proceeds of approximately $190.4 million, which were used to reduce outstanding borrowings under our revolving credit facility.
 
  •  In January, we sold the Arkoma Basin Assets to ENP for approximately $46.4 million in cash.


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Results of Operations
 
Comparison of 2009 to 2008
 
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:
 
                                 
    Year Ended December 31,     Increase/(Decrease)  
    2009     2008     $     %  
 
Revenues (in thousands):
                               
Oil wellhead
  $ 549,391     $ 900,300     $ (350,909 )        
Oil commodity derivative contracts
          (2,857 )     2,857          
                                 
Total oil revenues
  $ 549,391     $ 897,443     $ (348,052 )     (39 )%
                                 
Natural gas wellhead
  $ 131,185     $ 227,479     $ (96,294 )     (42 )%
                                 
Combined wellhead
  $ 680,576     $ 1,127,779     $ (447,203 )     (40 )%
Combined commodity derivative contracts
          (2,857 )     2,857          
                                 
Total combined oil and natural gas revenues
  $ 680,576     $ 1,124,922     $ (444,346 )     (40 )%
Marketing
    4,840       10,496       (5,656 )     (54 )%
                                 
Total revenues
  $ 685,416     $ 1,135,418     $ (450,002 )     (40 )%
                                 
Average realized prices:
                               
Oil wellhead ($/Bbl)
  $ 54.85     $ 89.58     $ (34.73 )        
Oil commodity derivative contracts ($/Bbl)
          (0.28 )     0.28          
                                 
Total oil revenues ($/Bbl)
  $ 54.85     $ 89.30     $ (34.45 )     (39 )%
                                 
Natural gas wellhead ($/Mcf)
  $ 3.87     $ 8.63     $ (4.76 )     (55 )%
                                 
Combined wellhead ($/BOE)
  $ 43.43     $ 78.07     $ (34.64 )        
Combined commodity derivative contracts ($/BOE)
          (0.20 )     0.20          
                                 
Total combined oil and natural gas revenues ($/BOE)
  $ 43.43     $ 77.87     $ (34.44 )     (44 )%
                                 
Total production volumes:
                               
Oil (MBbls)
    10,016       10,050       (34 )     0 %
Natural gas (MMcf)
    33,919       26,374       7,545       29 %
Combined (MBOE)
    15,669       14,446       1,223       8 %
Average daily production volumes:
                               
Oil (Bbl/D)
    27,441       27,459       (18 )     0 %
Natural gas (Mcf/D)
    92,928       72,060       20,868       29 %
Combined (BOE/D)
    42,929       39,470       3,459       9 %
Average NYMEX prices:
                               
Oil (per Bbl)
  $ 61.95     $ 99.75     $ (37.80 )     (38 )%
Natural gas (per Mcf)
  $ 3.99     $ 9.04     $ (5.05 )     (56 )%
 
Oil revenues decreased 39 percent from $897.4 million in 2008 to $549.4 million in 2009 as a result of a $34.73 per Bbl decrease in our average realized oil price and a 34 MBbl decrease in our oil production volumes. Our lower average realized oil price decreased oil revenues by approximately $347.8 million and was primarily due to a lower average NYMEX price, which decreased from $99.75 per Bbl in 2008 to $61.95


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per Bbl in 2009. Our lower oil production volumes decreased oil revenues by approximately $3.1 million. Oil revenues in 2008 were also reduced by approximately $2.9 million, or $0.28 per Bbl, for oil derivative contracts previously designated as hedges. In 2009 and 2008, our average daily production volumes were decreased by 1,721 BOE/D and 1,530 BOE/D, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by $31.3 million and $55.3 million, respectively.
 
Natural gas revenues decreased 42 percent from $227.5 million in 2008 to $131.2 million in 2009 as a result of a $4.76 per Mcf decrease in our average realized natural gas price, partially offset by a 7,545 MMcf increase in natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $161.4 million and was primarily due to a lower average NYMEX price, which decreased from $9.04 per Mcf in 2008 to $3.99 per Mcf in 2009. Our higher natural gas production volumes increased natural gas revenues by approximately $65.1 million was primarily the result of successful development programs in our Permian Basin and Mid-Continent regions and our acquisitions of properties from EXCO in August 2009.
 
The following table shows the relationship between our average oil and natural gas wellhead prices as a percentage of average NYMEX prices for the periods indicated. Management uses the wellhead to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.
 
                 
    Year Ended December 31,  
    2009     2008  
 
Average oil wellhead ($/Bbl)
  $ 54.85     $ 89.58  
Average NYMEX ($/Bbl)
  $ 61.95     $ 99.75  
Differential to NYMEX
  $ (7.10 )   $ (10.17 )
Average oil wellhead to NYMEX percentage
    89 %     90 %
Average natural gas wellhead ($/Mcf)
  $ 3.87     $ 8.63  
Average NYMEX ($/Mcf)
  $ 3.99     $ 9.04  
Differential to NYMEX
  $ (0.12 )   $ (0.41 )
Average natural gas wellhead to NYMEX percentage
    97 %     95 %
 
Our average oil wellhead price as a percentage of the average NYMEX price was 89 percent in 2009 as compared to 90 percent in 2008.
 
Our average natural gas wellhead price as a percentage of the average NYMEX price was 97 percent in 2009 as compared to 95 percent in 2008.
 
Marketing revenues decreased 54 percent from $10.5 million in 2008 to $4.8 million in 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.


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Expenses.  The following table provides the components of our expenses for the periods indicated:
 
                                 
    Year Ended December 31,     Increase/(Decrease)  
    2009     2008     $     %  
 
Expenses (in thousands):
                               
Production:
                               
Lease operating
  $ 165,062     $ 175,115     $ (10,053 )        
Production, ad valorem, and severance taxes
    69,539       110,644       (41,105 )        
                                 
Total production expenses
    234,601       285,759       (51,158 )     (18 )%
Other:
                               
Depletion, depreciation, and amortization
    290,776       228,252       62,524          
Impairment of long-lived assets
    9,979       59,526       (49,547 )        
Exploration
    52,488       39,207       13,281          
General and administrative
    54,024       48,421       5,603          
Marketing
    3,994       9,570       (5,576 )        
Derivative fair value loss (gain)
    59,597       (346,236 )     405,833          
Provision for doubtful accounts
    7,686       1,984       5,702          
Other operating
    25,761       12,975       12,786          
                                 
Total operating
    738,906       339,458       399,448       118 %
Interest
    79,017       73,173       5,844          
Income tax provision (benefit)
    (32,173 )     241,621       (273,794 )        
                                 
Total expenses
  $ 785,750     $ 654,252     $ 131,498       20 %
                                 
Expenses (per BOE):
                               
Production:
                               
Lease operating
  $ 10.53     $ 12.12     $ (1.59 )        
Production, ad valorem, and severance taxes
    4.44       7.66       (3.22 )        
                                 
Total production expenses
    14.97       19.78       (4.81 )     (24 )%
Other:
                               
Depletion, depreciation, and amortization
    18.56       15.80       2.76          
Impairment of long-lived assets
    0.64       4.12       (3.48 )        
Exploration
    3.35       2.71       0.64          
General and administrative
    3.45       3.35       0.10          
Marketing
    0.25       0.66       (0.41 )        
Derivative fair value loss (gain)
    3.80       (23.97 )     27.77          
Provision for doubtful accounts
    0.49       0.14       0.35          
Other operating
    1.64       0.90       0.74          
                                 
Total operating
    47.15       23.49       23.66       101 %
Interest
    5.04       5.07       (0.03 )        
Income tax provision (benefit)
    (2.05 )     16.73       (18.78 )        
                                 
Total expenses
  $ 50.14     $ 45.29     $ 4.85       11 %
                                 
 
Production expenses.  Total production expenses decreased 18 percent from $285.8 million in 2008 to $234.6 million in 2009. Our production margin decreased 47 percent from $842.0 million in 2008 to $446.0 million in 2009. Total oil and natural gas wellhead revenues per BOE decreased by 44 percent and


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ENCORE ACQUISITION COMPANY
 
total production expenses per BOE decreased by 24 percent. On a per BOE basis, our production margin decreased 51 percent to $28.46 per BOE in 2009 as compared to $58.29 per BOE in 2008.
 
Production expense attributable to LOE decreased $10.1 million from $175.1 million in 2008 to $165.1 million in 2009 as a result of a $1.59 decrease in the average per BOE rate, partially offset by higher production volumes. Our lower average LOE per BOE rate decreased LOE by approximately $24.9 million and was primarily due to decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs and lower prices paid to oilfield service companies and suppliers. Our higher production volumes increased LOE by approximately $14.8 million.
 
Production expense attributable to production taxes decreased $41.1 million from $110.6 million in 2008 to $69.5 million in 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes increased to 10.2 percent in 2009 as compared to 9.8 percent in 2008 primarily due to higher ad valorem taxes, which are based on production volumes as opposed to a percentage of wellhead revenues.
 
Depletion, depreciation, and amortization (“DD&A”) expense.  DD&A expense increased $62.5 million from $228.3 million in 2008 to $290.8 million in 2009 as a result of a $2.76 increase in the per BOE rate and higher production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $43.2 million and was primarily due to the decrease in our proved reserves at the beginning of 2009 as a result of lower average commodity prices, partially offset by reserves added during 2009 through our EXCO asset acquisition. Our higher production volumes increased DD&A expense by approximately $19.3 million.
 
Impairment of long-lived assets.  During 2009 and 2008, circumstances indicated that the carrying value of certain of our oil and natural gas properties in the Tuscaloosa Marine Shale may not be recoverable. For the proved oil and natural gas property costs, we compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a pretax write-down of the value of oil and natural gas properties. For the unproved acreage costs, we recorded a valuation allowance to reflect the portion of the property costs that we believe will not be transferred to proved properties over the remaining life of the lease. The impairment of proved oil and natural gas properties and unproved acreage in the Tuscaloosa Marine Shale totaled of $10.0 million and $59.5 million during 2009 and 2008, respectively. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.
 
As of December 31, 2009, we do not have any unproved oil and natural gas properties in the Tuscaloosa Marine Shale whose carrying value has not been written down to zero.


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Exploration expense.  Exploration expense increased $13.3 million from $39.2 million in 2008 to $52.5 million in 2009. During 2009, we expensed 5.6 net exploratory dry holes totaling $25.4 million. During 2008, we expensed 3.8 net exploratory dry holes totaling $14.7 million. Impairment of unproved acreage increased $5.1 million from $20.2 million in 2008 to $25.3 million in 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table provides the components of exploration expenses for the periods indicated:
 
                         
    Year Ended December 31,     Increase
 
    2009     2008     (Decrease)  
    (In thousands)  
 
Dry holes
  $ 25,407     $ 14,683     $ 10,724  
Geological and seismic
    1,022       2,851       (1,829 )
Delay rentals
    773       1,482       (709 )
Impairment of unproved acreage
    25,286       20,191       5,095  
                         
Total
  $ 52,488     $ 39,207     $ 13,281  
                         
 
G&A expense.  G&A expense increased $5.6 million from $48.4 million in 2008 to $54.0 million in 2009 primarily due to retention bonuses paid in August 2009 related to our 2008 strategic alternatives process and the expensing of transaction costs related to our EXCO asset acquisition.
 
Marketing expense.  Marketing expense decreased $5.6 million from $9.6 million in 2008 to $4.0 million in 2009 as a result of a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.
 
Derivative fair value loss (gain).  During 2009, we recorded a $59.6 million derivative fair value loss as compared to a $346.2 million derivative fair value gain in 2008, the components of which were as follows:
 
                         
    Year Ended December 31,     Increase/
 
    2009     2008     (Decrease)  
    (In thousands)  
 
Ineffectiveness
  $ 2     $ 372     $ (370 )
Mark-to-market loss (gain)
    350,365       (365,495 )     715,860  
Premium amortization
    98,395       62,352       36,043  
Settlements
    (389,165 )     (43,465 )     (345,700 )
                         
Total derivative fair value loss (gain)
  $ 59,597     $ (346,236 )   $ 405,833  
                         
 
Provision for doubtful accounts.  In 2009 and 2008, we recorded a provision for doubtful accounts of $7.7 million and $2.0 million, respectively, primarily for the payout allowance related to the ExxonMobil joint development agreement.
 
Other operating expense.  Other operating expense increased $12.8 million from $13.0 million in 2008 to $25.8 million in 2009, primarily due to a $6.5 million adjustment to the carrying value of pipe and other tubular inventory whose market value had declined below cost and higher gathering and transportation fees.
 
Interest expense.  Interest expense increased $5.8 million from $73.2 million in 2008 to $79.0 million in 2009 primarily due to the issuance of our 9.5% Notes in April 2009. The weighted average interest rate for all long-term debt for 2009 was 5.8 percent as compared to 5.6 percent for 2008.


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ENCORE ACQUISITION COMPANY
 
The following table provides the components of interest expense for the periods indicated:
 
                         
    Year Ended December 31,     Increase/
 
    2009     2008     (Decrease)  
    (In thousands)  
 
6.25% Senior Subordinated Notes
  $ 9,751     $ 9,727     $ 24  
6.0% Senior Subordinated Notes
    18,585       18,550       35  
9.5% Senior Subordinated Notes
    15,999             15,999  
7.25% Senior Subordinated Notes
    11,005       10,996       9  
Revolving credit facilities
    18,253       31,038       (12,785 )
Other
    5,424       2,862       2,562  
                         
Total
  $ 79,017     $ 73,173     $ 5,844  
                         
 
Income taxes.  In 2009, we recorded an income tax benefit of $32.2 million as compared to an income tax provision of $241.6 million in 2008. In 2009, we had a loss before income taxes of $130.1 million as compared to income before income taxes of $726.7 million in 2008. Our effective tax rate decreased to 24.7 percent in 2009 as compared to 33.2 percent in 2008 primarily due to the 2008 provision to return difference for the production activities deduction estimated at the end of 2008 due to a change in tax planning as a result of the monetization of hedges in the first quarter of 2009 and an increase in the effective state income tax rate due to changes in apportionment associated with our 2009 acquisitions.


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ENCORE ACQUISITION COMPANY
 
Comparison of 2008 to 2007
 
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:
 
                                 
          Increase/
 
    Year Ended December 31,     (Decrease)  
    2008     2007     $     %  
 
Revenues (in thousands):
                               
Oil wellhead
  $ 900,300     $ 606,112     $ 294,188          
Oil commodity derivative contracts
    (2,857 )     (43,295 )     40,438          
                                 
Total oil revenues
  $ 897,443     $ 562,817     $ 334,626       59 %
                                 
Natural gas wellhead
  $ 227,479     $ 160,399     $ 67,080          
Natural gas commodity derivative contracts
          (10,292 )     10,292          
                                 
Total natural gas revenues
  $ 227,479     $ 150,107     $ 77,372       52 %
                                 
Combined wellhead
  $ 1,127,779     $ 766,511     $ 361,268          
Combined commodity derivative contracts
    (2,857 )     (53,587 )     50,730          
                                 
Total combined oil and natural gas revenues
    1,124,922       712,924       411,998       58 %
Marketing
    10,496       42,021       (31,525 )     (75 )%
                                 
Total revenues
  $ 1,135,418     $ 754,945     $ 380,473       50 %
                                 
Average realized prices:
                               
Oil wellhead ($/Bbl)
  $ 89.58     $ 63.50     $ 26.08          
Oil commodity derivative contracts ($/Bbl)
    (0.28 )     (4.54 )     4.26          
                                 
Total oil revenues ($/Bbl)
  $ 89.30     $ 58.96     $ 30.34       51 %
                                 
Natural gas wellhead ($/Mcf)
  $ 8.63     $ 6.69     $ 1.94          
Natural gas commodity derivative contracts ($/Mcf)
          (0.43 )     0.43          
                                 
Total natural gas revenues ($/Mcf)
  $ 8.63     $ 6.26     $ 2.37       38 %
                                 
Combined wellhead ($/BOE)
  $ 78.07     $ 56.62     $ 21.45          
Combined commodity derivative contracts ($/BOE)
    (0.20 )     (3.96 )     3.76          
                                 
Total combined oil and natural gas revenues ($/BOE)
  $ 77.87     $ 52.66     $ 25.21       48 %
                                 
Total production volumes:
                               
Oil (MBbls)
    10,050       9,545       505       5 %
Natural gas (MMcf)
    26,374       23,963       2,411       10 %
Combined (MBOE)
    14,446       13,539       907       7 %
Average daily production volumes:
                               
Oil (Bbl/D)
    27,459       26,152       1,307       5 %
Natural gas (Mcf/D)
    72,060       65,651       6,409       10 %
Combined (BOE/D)
    39,470       37,094       2,376       6 %
Average NYMEX prices:
                               
Oil (per Bbl)
  $ 99.75     $ 72.45     $ 27.30       38 %
Natural gas (per Mcf)
  $ 9.04     $ 6.86     $ 2.18       32 %


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ENCORE ACQUISITION COMPANY
 
Oil revenues increased 59 percent from $562.8 million in 2007 to $897.4 million in 2008 as a result of an increase in our average realized oil price and an increase in oil production volumes of 505 MBbls. The increase in oil production volumes contributed approximately $32.1 million in additional oil revenues and was primarily the result of a full year of production from our Big Horn Basin acquisition in March 2007 and our Williston Basin acquisition in April 2007, as well as our development program in the Bakken.
 
Our average realized oil price increased $30.34 per Bbl from 2007 to 2008 primarily as a result of an increase in our average realized oil wellhead price, which increased oil revenues by approximately $262.1 million, or $26.08 per Bbl. Our average realized oil wellhead price increased primarily as a result of the increase in the average NYMEX price from $72.45 per Bbl in 2007 to $99.75 per Bbl in 2008.
 
During July 2006, we elected to discontinue hedge accounting prospectively for all remaining commodity derivative contracts which were previously accounted for as hedges. While this change had no effect on our cash flows, results of operations are affected by mark-to-market gains and losses, which fluctuate with the changes in oil and natural gas prices. As a result, oil revenues for 2008 included amortization of net losses on certain commodity derivative contracts that were previously designated as hedges of approximately $2.9 million, or $0.28 per Bbl, while 2007 included approximately $43.3 million, or $4.54 per Bbl, of net losses.
 
Our average daily production volumes were decreased by 1,530 BOE/D and 1,466 BOE/D in 2008 and 2007, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by $55.3 million and $31.9 million in 2008 and 2007, respectively.
 
Natural gas revenues increased 52 percent from $150.1 million in 2007 to $227.5 million in 2008 as a result of an increase in our average realized natural gas price and an increase in natural gas production volumes of 2,411 MMcf. The increase in natural gas production volumes contributed approximately $16.1 million in additional natural gas revenues and was primarily the result of our development program in our Permian Basin and Mid-Continent regions.
 
Our average realized natural gas price increased $2.37 per Mcf from 2007 to 2008 primarily as a result of an increase in our average realized natural gas wellhead price, which increased natural gas revenues by approximately $50.9 million, or $1.94 per Mcf. Our average realized natural gas wellhead price increased primarily as a result of the increase in the average NYMEX price from $6.86 per Mcf in 2007 to $9.04 per Mcf in 2008. In addition, as a result of our discontinuance of hedge accounting in July 2006, natural gas revenues for 2007 included amortization of net losses on certain commodity derivative contracts that were previously designated as hedges of approximately $10.3 million, or $0.43 per Mcf.
 
The table below shows the relationship between our oil and natural gas wellhead prices as a percentage of average NYMEX prices for the periods indicated:
 
                 
    Year Ended December 31,  
    2008     2007  
 
Average oil wellhead ($/Bbl)
  $ 89.58     $ 63.50  
Average NYMEX ($/Bbl)
  $ 99.75     $ 72.45  
Differential to NYMEX
  $ (10.17 )   $ (8.95 )
Average oil wellhead to NYMEX percentage
    90 %     88 %
Average natural gas wellhead ($/Mcf)
  $ 8.63     $ 6.69  
Average NYMEX ($/Mcf)
  $ 9.04     $ 6.86  
Differential to NYMEX
  $ (0.41 )   $ (0.17 )
Average natural gas wellhead to NYMEX percentage
    95 %     98 %
 
Our average oil wellhead price as a percentage of the average NYMEX price was 90 percent in 2008 as compared to 88 percent in 2007. Our average natural gas wellhead price as a percentage of the average NYMEX price was 95 percent in 2008 as compared to 98 percent in 2007.


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Marketing revenues decreased 75 percent from $42.0 million in 2007 to $10.5 million in 2008 primarily as a result of discontinuing the purchase of oil from third party companies as market conditions changed and historical pipeline space was realized. Implementing this change allowed us to focus on the marketing of our own production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.
 
Expenses.  The following table provides the components of our expenses for the periods indicated:
 
                                 
          Increase/
 
    Year Ended December 31,     (Decrease)  
    2008     2007     $     %  
 
Expenses (in thousands):
                               
Production:
                               
Lease operating
  $ 175,115     $ 143,426     $ 31,689          
Production, ad valorem, and severance taxes
    110,644       74,585       36,059          
                                 
Total production expenses
    285,759       218,011       67,748       31 %
Other:
                               
Depletion, depreciation, and amortization
    228,252       183,980       44,272          
Impairment of long-lived assets
    59,526             59,526          
Exploration
    39,207       27,726       11,481          
General and administrative
    48,421       39,124       9,297          
Marketing
    9,570       40,549       (30,979 )        
Derivative fair value loss (gain)
    (346,236 )     112,483       (458,719 )        
Provision for doubtful accounts
    1,984       5,816       (3,832 )        
Other operating
    12,975       17,066       (4,091 )        
                                 
Total operating
    339,458       644,755       (305,297 )     (47 )%
Interest
    73,173       88,704       (15,531 )        
Income tax provision
    241,621       14,476       227,145          
                                 
Total expenses
  $ 654,252     $ 747,935     $ (93,683 )     (13 )%
                                 
Expenses (per BOE):
                               
Production:
                               
Lease operating
  $ 12.12     $ 10.59     $ 1.53          
Production, ad valorem, and severance taxes
    7.66       5.51       2.15          
                                 
Total production expenses
    19.78       16.10       3.68       23 %
Other:
                               
Depletion, depreciation, and amortization
    15.80       13.59       2.21          
Impairment of long-lived assets
    4.12             4.12          
Exploration
    2.71       2.05       0.66          
General and administrative
    3.35       2.89       0.46          
Marketing
    0.66       2.99       (2.33 )        
Derivative fair value loss (gain)
    (23.97 )     8.31       (32.28 )        
Provision for doubtful accounts
    0.14       0.43       (0.29 )        
Other operating
    0.90       1.26       (0.36 )        
                                 
Total operating
    23.49       47.62       (24.13 )     (51 )%
Interest
    5.07       6.55       (1.48 )        
Income tax provision
    16.73       1.07       15.66          
                                 
Total expenses
  $ 45.29     $ 55.24     $ (9.95 )     (18 )%
                                 


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Production expenses.  Total production expenses increased 31 percent from $218.0 million in 2007 to $285.8 million in 2008. Our production margin increased 54 percent to $842.0 million as compared to $548.5 million in 2007. Total oil and natural gas wellhead revenues per BOE increased by 38 percent while total production expenses per BOE increased by 23 percent. On a per BOE basis, our production margin increased 44 percent to $58.29 per BOE as compared to $40.52 per BOE for 2007.
 
Production expense attributable to LOE increased $31.7 million from $143.4 million in 2007 to $175.1 million in 2008 as a result of a $1.53 increase in the average per BOE rate, which contributed approximately $22.1 million of additional LOE, and an increase in production volumes, which contributed approximately $9.6 million of additional LOE. The increase in our average LOE per BOE rate was attributable to:
 
  •  increases in prices paid to oilfield service companies and suppliers;
 
  •  increases in natural gas prices resulting in higher electricity costs and gas plant fuel costs;
 
  •  higher compensation levels for engineers and other technical professionals; and
 
  •  an increase of approximately $4.7 million ($0.32 per BOE) for retention bonuses paid in August 2008 and approximately $4.1 million ($0.28 per BOE) for retention bonuses paid in August 2009, related to our strategic alternatives process.
 
Production expense attributable to production taxes increased $36.1 million from $74.6 million in 2007 to $110.6 million in 2008 primarily due to higher wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes remained approximately constant at 9.8 percent in 2008 as compared to 9.7 percent in 2007.
 
DD&A expense.  DD&A expense increased $44.3 million from $184.0 million in 2007 to $228.3 million in 2008 as a result of a $2.21 increase in the per BOE rate, which contributed approximately $32.0 million of additional DD&A expense, and an increase in production volumes, which contributed approximately $12.3 million of additional DD&A expense. The increase in our average DD&A per BOE rate was attributable to higher costs incurred resulting from increases in rig rates, pipe costs, and acquisition costs and the decrease in our total proved reserves to 185.7 MMBOE as of December 31, 2008 as compared to 231.3 MMBOE as of December 31, 2007.
 
Impairment of long-lived assets.  During 2008, circumstances indicated that the carrying value of certain wells we drilled in the Tuscaloosa Marine Shale may not be recoverable. We compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a pretax write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.
 
Exploration expense.  Exploration expense increased $11.5 million from $27.7 million in 2007 to $39.2 million in 2008. During 2008, we expensed 3.8 net exploratory dry holes totaling $14.7 million. During 2007, we expensed 2.6 net exploratory dry holes totaling $14.7 million. Impairment of unproved acreage increased $9.4 million from $10.8 million in 2007 to $20.2 million in 2008, primarily due to our larger


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unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table provides the components of exploration expenses for the periods indicated:
 
                         
    Year Ended December 31,        
    2008     2007     Increase  
    (In thousands)  
 
Dry holes
  $ 14,683     $ 14,673     $ 10  
Geological and seismic
    2,851       1,455       1,396  
Delay rentals
    1,482       784       698  
Impairment of unproved acreage
    20,191       10,814       9,377  
                         
Total
  $ 39,207     $ 27,726     $ 11,481  
                         
 
G&A expense.  G&A expense increased $9.3 million from $39.1 million in 2007 to $48.4 million in 2008, primarily due to:
 
  •  a full year of ENP public entity expenses;
 
  •  higher activity levels;
 
  •  increased personnel costs due to intense competition for human resources within the industry; and
 
  •  an increase of approximately $2.9 million for retention bonuses paid in August 2008 and approximately $2.8 million for retention bonuses paid in August 2009, related to our strategic alternatives process;
 
  •  partially offset by a $3.1 million decrease in non-cash equity-based compensation.
 
Marketing expense.  Marketing expense decreased $31.0 million from $40.5 million in 2007 to $9.6 million in 2008 primarily as a result of discontinuing purchasing oil from third party companies as market conditions changed and historical pipeline space was realized. Implementing this change allowed us to focus on the marketing of our own production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.
 
Derivative fair value loss (gain).  During 2008, we recorded a $346.2 million derivative fair value gain as compared to a $112.5 million derivative fair value loss in 2007, the components of which were as follows:
 
                         
    Year Ended
       
    December 31,     Increase/
 
    2008     2007     (Decrease)  
    (In thousands)  
 
Ineffectiveness
  $ 372     $     $ 372  
Mark-to-market loss (gain)
    (365,495 )     36,272       (401,767 )
Premium amortization
    62,352       41,051       21,301  
Settlements
    (43,465 )     35,160       (78,625 )
                         
Total derivative fair value loss (gain)
  $ (346,236 )   $ 112,483     $ (458,719 )
                         
 
The change in our derivative fair value loss (gain) was a result of the addition of commodity derivative contracts in the first part of 2008 when prices were high and the significant decrease in prices during the end of 2008, which favorably impacted the fair values of those contracts.
 
Provision for doubtful accounts.  In 2008 and 2007, we recorded a provision for doubtful accounts of $2.0 million and $5.8 million, respectively, primarily for the payout allowance related to the ExxonMobil joint development agreement.


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Other operating expense.  Other operating expense decreased $4.1 million from $17.1 million in 2007 to $13.0 million in 2008, primarily due to a $7.4 million loss on the sale of certain Mid-Continent properties in 2007, partially offset by a $3.4 million increase during 2008 in third-party transportation costs to move our production to markets outside the immediate area of production.
 
Interest expense.  Interest expense decreased $15.5 million from $88.7 million in 2007 to $73.2 million in 2008, primarily due to (1) the use of net proceeds from our Mid-Continent asset disposition and ENP’s IPO to reduce weighted average outstanding borrowings on our revolving credit facilities, (2) a reduction in LIBOR, and (3) our use of interest rate swaps to fix the rate on a portion of outstanding borrowings on ENP’s revolving credit facility. The weighted average interest rate for all long-term debt for 2008 was 5.6 percent as compared to 6.9 percent for 2007.
 
The following table provides the components of interest expense for the periods indicated:
 
                         
    Year Ended December 31,     Increase/
 
    2008     2007     (Decrease)  
    (In thousands)  
 
6.25% Senior Subordinated Notes
  $ 9,727     $ 9,705     $ 22  
6.0% Senior Subordinated Notes
    18,550       18,517       33  
7.25% Senior Subordinated Notes
    10,996       10,988       8  
Revolving credit facilities
    31,038       46,085       (15,047 )
Other
    2,862       3,409       (547 )
                         
Total
  $ 73,173     $ 88,704     $ (15,531 )
                         
 
Income taxes.  In 2008, we recorded an income tax provision of $241.6 million as compared to $14.5 million in 2007. In 2008, we had income before income taxes of $726.7 million as compared to $24.2 million in 2007. Our effective tax rate decreased to 33.2 percent in 2008 as compared to 59.9 percent in 2007 primarily due to the 2007 recognition of non-deductible deferred compensation.
 
Capital Commitments, Capital Resources, and Liquidity
 
Capital commitments.  Our primary uses of cash are:
 
  •  Development, exploitation, and exploration of oil and natural gas properties;
 
  •  Acquisitions of oil and natural gas properties;
 
  •  Funding of working capital; and
 
  •  Contractual obligations.
 
Development, exploitation, and exploration of oil and natural gas properties.  The following table summarizes our costs incurred related to development, exploitation, and exploration activities for the periods indicated:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Development and exploitation
  $ 121,259     $ 362,609     $ 270,161  
Exploration
    165,683       256,437       97,453  
                         
Total
  $ 286,942     $ 619,046     $ 367,614  
                         
 
Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for 2009


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yielded 57 gross (25.9 net) productive wells and one gross (1.0 net) dry holes. Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for 2009 yielded 55 gross (16.4 net) productive wells and 7 gross (5.6 net) dry holes. Please read “Items 1 and 2. Business and Properties — Development Results” for a description of the areas in which we drilled wells during 2009.
 
Acquisitions of oil and natural gas properties and leasehold acreage.  The following table summarizes our costs incurred related to oil and natural gas property acquisitions for the periods indicated:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Acquisitions of proved property
  $ 402,457     $ 28,840     $ 796,239  
Acquisitions of leasehold acreage
    17,087       128,635       52,306  
                         
Total
  $ 419,544     $ 157,475     $ 848,545  
                         
 
In August 2009, we acquired certain oil and natural gas properties from EXCO for approximately $357.4 million in cash (including a deposit of $37.5 million made in June 2009). In May 2009, ENP acquired certain natural gas properties in the Vinegarone Field in Val Verde County, Texas from an independent energy company for approximately $27.5 million in cash. In April 2007, we acquired oil and natural gas properties in the Williston Basin for approximately $392.1 million. In March 2007, we and ENP acquired oil and natural gas properties in the Big Horn Basin, including properties in the Elk Basin and the Gooseberry fields, for approximately $393.6 million.
 
During 2009, our capital expenditures for leasehold acreage related to the acquisition of unproved acreage in various areas. During 2008, $45.2 million of our capital expenditures for leasehold acreage related to the exercise of preferential rights in the Haynesville area and the remainder related to the acquisition of unproved acreage in various areas. During 2007, $16.1 million of our capital expenditures for leasehold acreage related to the Williston Basin asset acquisition and the remainder related to the acquisition of unproved acreage in various areas.
 
Funding of working capital.  As of December 31, 2009 and 2008, our working capital (defined as total current assets less total current liabilities) was a negative $62.9 million and a positive $188.7 million, respectively. The decrease was primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and higher oil prices at December 31, 2009 as compared to December 31, 2008, which negatively impacted the fair value of our outstanding oil derivative contracts.
 
For 2010, we expect working capital to remain negative primarily due to the fair value of our outstanding commodity derivative contracts. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and reduce outstanding borrowings and related interest expense under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. We do not plan to pay cash dividends in the foreseeable future. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Given our current commodity derivative contracts, assuming relatively stable commodity prices and constant production volumes, our operating cash flow should remain positive in 2010.
 
Our capital expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and borrowings under our revolving credit facility.


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Off-balance sheet arrangements.  We have no investments in unconsolidated entities or persons that could materially affect our liquidity or the availability of capital resources. We have no off-balance sheet arrangements that are material to our financial position or results of operations.
 
Contractual obligations.  The following table provides our contractual obligations and commitments at December 31, 2009: