e10vq
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2007
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
 
(Exact name of registrant as specified in its charter)
     
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)
(817) 877-9955
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ           Accelerated filer o           Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes o  No þ
         
Number of shares of common stock, $0.01 par value, outstanding as of October 31, 2007
    54,238,182  
 
 

 


 

ENCORE ACQUISITION COMPANY
INDEX
         
    Page  
       
 
       
       
 
       
    1  
 
       
    2  
 
       
    3  
 
       
    4  
 
       
    5  
 
       
    26  
 
       
    41  
 
       
    41  
 
       
       
 
       
    42  
 
       
    42  
 
       
    42  
 
       
    43  
 Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer)
 Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer)
 Section 1350 Certification (Principal Executive Officer)
 Section 1350 Certification (Principal Financial Officer)
 Statement Showing Computation of Ratios of Earnings to Fixed Charges
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
     Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and other materials filed with the Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. These forward-looking statements give our current expectations or forecasts of future events. You can identify our forward-looking statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “may,” “will,” “could,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “predict,” “potential,” “pursue,” “target,” “continue,” and other words and terms of similar meaning. Our actual results may differ significantly from the results discussed in the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006 and in our other filings with the SEC. If one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

i


Table of Contents

ENCORE ACQUISITION COMPANY
GLOSSARY OF CERTAIN TERMS
     The following are abbreviations and definitions of certain terms used in this Report. The definitions of proved developed reserves and proved reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-3) of Regulation S-X.
    Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
 
    Bbl/D. One Bbl per day.
 
    BOE. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
 
    BOE/D. One BOE per day.
 
    Council of Petroleum Accountants Societies, or 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.
 
    EAC. Encore Acquisition Company, a Delaware corporation, together with its subsidiaries.
 
    ENP. Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.
 
    Gross Wells. The total number of wells in which we own a working interest.
 
    High-Pressure Air Injection (“HPAI”). HPAI involves utilizing compressors to force air under high pressure into previously produced oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production.
 
    LIBOR. London Interbank Offered Rate.
 
    MBbls. One thousand Bbls.
 
    MBOE. One thousand BOE.
 
    Mcf. One thousand cubic feet of natural gas.
 
    Mcf/D. One Mcf per day.
 
    Net Wells. Gross wells multiplied by the percentage of the working interest owned by us.
 
    NGLs. Natural gas liquids.
 
    NYMEX. New York Mercantile Exchange.
 
    Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
 
    Proved Reserves. The estimated quantities of oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions.

ii


Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)
                 
    September 30,     December 31,  
    2007     2006  
    (unaudited)          
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 8,467     $ 763  
Accounts receivable
    105,871       81,470  
Inventory
    19,149       18,170  
Derivatives
    13,533       17,349  
Deferred taxes
    18,851       24,978  
Prepaid expenses and other
    6,769       2,988  
 
           
Total current assets
    172,640       145,718  
 
           
 
               
Properties and equipment, at cost — successful efforts method:
               
Proved properties, including wells and related equipment
    2,740,805       2,033,914  
Unproved properties
    56,427       47,548  
Accumulated depletion, depreciation, and amortization
    (442,393 )     (364,780 )
 
           
 
    2,354,839       1,716,682  
 
           
Other property and equipment
    20,539       18,231  
Accumulated depreciation
    (10,041 )     (7,791 )
 
           
 
    10,498       10,440  
 
           
 
               
Goodwill
    60,606       60,606  
Derivatives
    25,020       40,715  
Long-term receivables
    47,031       19,642  
Other
    29,166       13,097  
 
           
Total assets
  $ 2,699,800     $ 2,006,900  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 32,913     $ 18,204  
Accrued liabilities:
               
Lease operations expense
    12,265       8,582  
Development capital
    34,911       44,492  
Interest
    13,365       11,273  
Production, ad valorem, and severance taxes
    23,434       10,915  
Oil purchases
    705       11,191  
Derivatives
    44,002       60,448  
Other
    23,980       21,358  
 
           
Total current liabilities
    185,575       186,463  
 
               
Derivatives
    27,915       38,688  
Future abandonment cost
    28,177       19,205  
Deferred taxes
    294,971       282,825  
Long-term debt
    1,139,099       661,696  
Other
    1,326       1,158  
 
           
Total liabilities
    1,677,063       1,190,035  
 
           
 
               
Commitments and contingencies (see Note 14)
               
 
               
Minority interest in consolidated partnership
    181,412        
 
           
 
               
Stockholders’ equity:
               
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding
           
Common stock, $.01 par value, 144,000,000 shares authorized, 53,217,560 and 53,028,866 issued and outstanding, respectively
    533       531  
Additional paid-in capital
    458,989       457,201  
Treasury stock, at cost, none and 17,809 shares, respectively
          (457 )
Retained earnings
    391,980       394,917  
Accumulated other comprehensive loss
    (10,177 )     (35,327 )
 
           
Total stockholders’ equity
    841,325       816,865  
 
           
Total liabilities and stockholders’ equity
  $ 2,699,800     $ 2,006,900  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

1


Table of Contents

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
Revenues:
                               
Oil
  $ 159,295     $ 99,516     $ 377,514     $ 268,066  
Natural gas
    32,439       32,177       110,548       109,050  
Marketing
    3,282       46,004       27,139       106,036  
 
                       
Total revenues
    195,016       177,697       515,201       483,152  
 
                       
 
                               
Expenses:
                               
Production:
                               
Lease operations
    37,114       24,478       105,186       70,332  
Production, ad valorem, and severance taxes
    20,003       13,560       51,750       38,382  
Depletion, depreciation, and amortization
    49,026       27,471       136,372       82,479  
Exploration
    8,920       12,322       23,856       18,347  
General and administrative
    12,668       6,250       26,216       18,199  
Marketing
    4,089       48,001       27,607       105,661  
Derivative fair value loss (gain)
    15,786       (33,363 )     68,166       (20,263 )
Other operating
    6,351       976       13,667       3,573  
 
                       
Total expenses
    153,957       99,695       452,820       316,710  
 
                       
 
                               
Operating income
    41,059       78,002       62,381       166,442  
 
                       
 
                               
Other income (expenses):
                               
Interest
    (23,933 )     (11,261 )     (68,040 )     (33,766 )
Other
    857       463       1,889       1,012  
 
                       
Total other income (expenses)
    (23,076 )     (10,798 )     (66,151 )     (32,754 )
 
                       
 
                               
Income (loss) before income taxes and minority interest
    17,983       67,204       (3,770 )     133,688  
Income tax provision
    (8,986 )     (25,069 )     (1,490 )     (51,382 )
Minority interest in loss of consolidated partnership
    2,988             2,988        
 
                       
 
                               
Net income (loss)
  $ 11,985     $ 42,135     $ (2,272 )   $ 82,306  
 
                       
 
                               
Net income (loss) per common share:
                               
Basic
  $ 0.23     $ 0.80     $ (0.04 )   $ 1.60  
Diluted
  $ 0.22     $ 0.78     $ (0.04 )   $ 1.57  
 
                               
Weighted average common shares outstanding:
                               
Basic
    53,198       52,968       53,140       51,481  
Diluted
    54,179       53,776       53,140       52,375  
The accompanying notes are an integral part of these consolidated financial statements.

2


Table of Contents

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(in thousands)
(unaudited)
                                                                 
    Issued                                             Accumulated        
    Shares of             Additional     Shares of                     Other     Total  
    Common     Common     Paid-in     Treasury     Treasury     Retained     Comprehensive     Stockholders’  
    Stock     Stock     Capital     Stock     Stock     Earnings     Loss     Equity  
 
                                                               
Balance at December 31, 2006
    53,047     $ 531     $ 457,201       (18 )   $ (457 )   $ 394,917     $ (35,327 )   $ 816,865  
Exercise of stock options and vesting of restricted stock
    210       2       1,597                               1,599  
Purchase of treasury stock
                      (21 )     (546 )                 (546 )
Cancellation of treasury stock
    (39 )           (338 )     39       1,003       (665 )            
Non-cash stock-based compensation
                11,513                               11,513  
EAC’s share of ENP’s offering costs
                (10,984 )                             (10,984 )
Components of comprehensive income:
                                                               
Net loss
                                  (2,272 )           (2,272 )
Amortization of deferred hedge losses, net of tax of $15,041
                                        25,150       25,150  
 
                                                             
Total comprehensive income
                                                            22,878  
 
                                               
Balance at September 30, 2007
    53,218     $ 533     $ 458,989           $     $ 391,980     $ (10,177 )   $ 841,325  
 
                                               
The accompanying notes are an integral part of these consolidated financial statements.

3


Table of Contents

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited
                 
    Nine months ended  
    September 30,  
    2007     2006  
Cash flows from operating activities:
               
Net income (loss)
  $ (2,272 )   $ 82,306  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depletion, depreciation, and amortization
    136,372       82,479  
Non-cash exploration expense
    22,511       12,542  
Deferred taxes
    1,374       48,673  
Non-cash stock-based compensation expense
    12,790       6,797  
Non-cash derivative
    87,108       (13,013 )
Loss on disposition of assets
    5,918       395  
Minority interest in loss of consolidated partnership
    (2,988 )      
Other
    6,055       5,644  
Changes in operating assets and liabilities, net of effects from acquisitions:
               
Accounts receivable
    (31,064 )     11,579  
Current derivatives
    (15,303 )     (1,221 )
Other current assets
    (1,858 )     (3,472 )
Long-term derivatives
    (22,301 )     (29,097 )
Other assets
    (4,428 )     (4 )
Accounts payable
    4,416       (2,047 )
Other current liabilities
    17,810       19,188  
Other noncurrent liabilities
    (496 )     13,633  
 
           
Net cash provided by operating activities
    213,644       234,382  
 
           
 
               
Cash flows from investing activities:
               
Proceeds from disposition of assets
    291,339       666  
Purchases of other property and equipment
    (2,443 )     (3,450 )
Acquisition of oil and natural gas properties
    (839,945 )     (22,809 )
Development of oil and natural gas properties
    (259,457 )     (241,502 )
Net advances to working interest partners
    (22,644 )     (8,667 )
Other
          (1,509 )
 
           
Net cash used in investing activities
    (833,150 )     (277,271 )
 
           
 
               
Cash flows from financing activities:
               
Proceeds from issuance of common stock, net of issuance costs
          127,101  
Proceeds from issuance of ENP common units, net of issuance costs
    171,220        
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases
    1,053       3,151  
Proceeds from long-term debt, net of issuance costs
    1,269,291       164,853  
Payments on long-term debt
    (805,428 )     (245,000 )
Change in cash overdrafts
    10,293       (8,331 )
Payment of deferred hedge premiums
    (19,219 )      
 
           
Net cash provided by financing activities
    627,210       41,774  
 
           
 
               
Increase (decrease) in cash and cash equivalents
    7,704       (1,115 )
Cash and cash equivalents, beginning of period
    763       1,654  
 
           
Cash and cash equivalents, end of period
  $ 8,467     $ 539  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

4


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)
Note 1. About Encore
     EAC is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has 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. EAC’s properties — and oil and natural gas reserves — are located in four core areas: the Cedar Creek Anticline (“CCA”) in the Williston Basin of Montana and North Dakota; the Permian Basin of West Texas and southeastern New Mexico; the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins of Wyoming, Montana, and North Dakota, and the Paradox Basin of southeastern Utah; and the Mid-Continent area, which includes the Arkoma and Anadarko Basins of Oklahoma, the North Louisiana Salt Basin, the East Texas Basin, and the Barnett Shale of northern Texas.
Note 2. Basis of Presentation
     EAC’s consolidated financial statements include the accounts of wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.
     In February 2007, EAC formed ENP to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. In September 2007, ENP completed its initial public offering (“IPO”) of 9,000,000 common units, representing a 37.4 percent limited partner interest, at a price to the public of $21.00 per unit. On September 30, 2007, EAC owned approximately 61 percent of ENP’s common units, as well as all of the interests of ENP’s general partner, which is a wholly owned subsidiary of EAC. Considering the presumption of control of the general partner in accordance with Emerging Issues Task Force Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights”, the financial position, results of operations, and cash flows of ENP are consolidated within EAC’s operations. EAC elected not to recognize a gain on ENP’s IPO as permitted by Staff Accounting Bulletin Topic 5H, “Accounting for Sales of Stock by a Subsidiary”. See “Note 16. ENP” for additional discussion.
     In the opinion of management, the accompanying unaudited consolidated financial statements of EAC include all adjustments necessary to present fairly, in all material respects, its financial position as of September 30, 2007, results of operations for the three and nine months ended September 30, 2007 and 2006, and cash flows for the nine months ended September 30, 2007 and 2006. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.
     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes thereto included in EAC’s 2006 Annual Report on Form 10-K.
Variable Interest Entity
     On April 11, 2007, EAC completed the purchase of certain oil and natural gas properties and related assets in the Williston Basin of Montana and North Dakota from certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”). Prior to closing, EAC assigned all of its rights and duties under the purchase and sale agreement to Encore Operating, L.P., a Texas limited partnership and indirect wholly owned guarantor subsidiary of EAC (“Encore Operating”), which further assigned all of its rights and duties under the purchase and sale agreement to Encore Exchange, LLC, a Delaware limited liability company unaffiliated with EAC or Encore Operating (“Encore Exchange”).
     The Williston Basin acquisition was structured to qualify as the first step of a reverse like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended, and I.R.S. Revenue Procedure 2000-37. The Williston Basin assets were acquired by Encore Exchange as an “exchange accommodation titleholder”. Encore Exchange held the assets pursuant to a qualified exchange accommodation agreement until the second step of the like-kind exchange was completed. During the period the assets were held by Encore Exchange, Encore Operating operated the Williston Basin assets pursuant to a management agreement with Encore Exchange. The second step of the like-kind exchange was completed in July 2007 upon the completion of the disposition of certain of EAC’s Mid-Continent properties and the Williston Basin assets were transferred to EAC. See “Note 3. Acquisitions and Dispositions” for additional discussion of the Mid-Continent disposition.
     In connection with the like-kind exchange described above, EAC (through Encore Operating) loaned an amount equal to the

5


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
purchase price to Encore Exchange. Based on the provisions of Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 46(R), “Consolidation of Variable Interest Entities”, EAC determined that Encore Exchange was a variable interest entity for which EAC was the primary beneficiary. During the third quarter of 2007, the like-kind exchange was completed, and Encore Exchange was dissolved.
Minority Interest
     As presented in the accompanying Consolidated Balance Sheets, “Minority interest in consolidated partnership” as of September 30, 2007 of $181.4 million represents third-party ownership interests in ENP. For financial reporting purposes, the assets and liabilities of ENP are consolidated with those of EAC, with any third-party ownership interests in such amounts being presented as minority interest.
     As presented in the accompanying Consolidated Statements of Operations, “Minority interest in loss of consolidated partnership” for the three and nine months ended September 30, 2007 of $3.0 million represents the net loss of ENP attributable to third-party owners.
Reclassifications
     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, certain amounts on the accompanying Consolidated Statements of Cash Flows have been either combined or classified in more detail.
New Accounting Pronouncements
Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS 157”)
     In September 2006, the FASB issued SFAS 157. SFAS 157 standardizes the definition of fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value measurements. SFAS 157 is prospectively effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. EAC does not expect the adoption of SFAS 157 to have a material impact on its results of operations or financial condition.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115” (“SFAS 159”)
     In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 allows entities to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. EAC does not expect the adoption of SFAS 159 to have a material impact on its results of operations or financial condition.
FASB Staff Position (“FSP”) on FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”)
     In April 2007, the FASB issued FSP FIN 39-1. FSP FIN 39-1 amends FIN No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007. EAC does not expect the adoption of FSP FIN 39-1 to have a material impact on its results of operations or financial condition.
Note 3. Acquisitions and Dispositions
Acquisitions
     On January 23, 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil

6


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
and natural gas properties and related assets in the Williston Basin of Montana and North Dakota. The closing of the Williston Basin acquisition occurred on April 11, 2007 after which time the operations have been included with those of EAC.
     The total purchase price for the Williston Basin assets was approximately $392.0 million, including estimated transaction costs of approximately $1.3 million. Based on currently available information, the calculation of the total purchase price and the estimated allocation to the fair value of the Williston Basin assets acquired and liabilities assumed from Anadarko are as follows as of September 30, 2007 (in thousands):
         
Calculation of total purchase price:
       
Cash paid to Anadarko
  $ 390,728  
Estimated transaction costs
    1,298  
 
     
Total purchase price
  $ 392,026  
 
     
 
       
Allocation of purchase price to the fair value of net assets acquired:
       
Proved properties, including wells and related equipment
  $ 383,741  
Unproved properties
    16,134  
Accounts receivable
    2,910  
Inventory
    743  
 
     
Total assets acquired
    403,528  
 
     
Current liabilities
    (7,996 )
Future abandonment cost
    (3,506 )
 
     
Total liabilities assumed
    (11,502 )
 
     
Fair value of net assets acquired
  $ 392,026  
 
     
     On January 16, 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included oil and natural gas properties and related assets in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas properties and related assets in the Gooseberry field in Park County, Wyoming. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, and the rights and duties under the purchase and sale agreement relating to the Gooseberry assets to Encore Operating. The closing of the Big Horn Basin acquisition occurred on March 7, 2007 after which time the operations have been included with those of EAC.
     The total purchase price for the Big Horn Basin assets was approximately $393.2 million, including estimated transaction costs of approximately $1.3 million. The calculation of the total purchase price and the estimated allocation to the fair value of the Big Horn Basin assets acquired and liabilities assumed from Anadarko are as follows as of September 30, 2007 (in thousands):
         
Calculation of total purchase price:
       
Cash paid to Anadarko
  $ 391,943  
Estimated transaction costs
    1,288  
 
     
Total purchase price
  $ 393,231  
 
     
 
       
Allocation of purchase price to the fair value of net assets acquired:
       
Proved properties, including wells and related equipment
  $ 395,598  
Intangibles
    4,225  
Accounts receivable
    1,673  
 
     
Total assets acquired
    401,496  
 
     
Current liabilities
    (1,292 )
Future abandonment cost
    (6,973 )
 
     
Total liabilities assumed
    (8,265 )
 
     
Fair value of net assets acquired
  $ 393,231  
 
     
     The properties and equipment amount in the Big Horn Basin purchase price allocation includes the fair value of proved leasehold costs, lease and well equipment (including flue gas reinjection facilities used to maintain reservoir pressure by

7


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
compressing and reinjecting the gas produced), and an oil pipeline and natural gas pipeline used primarily to transport production from the acquired fields. NGLs are produced as a byproduct of the flue gas tertiary recovery project and are sold at market prices. The revenues generated by these hydrocarbon liquids are included in “Oil revenues” in the accompanying Consolidated Statements of Operations. Third-party revenues and expenses related to the pipelines are included in “Marketing revenues” and “Marketing expenses”, respectively, in the accompanying Consolidated Statements of Operations.
     EAC and ENP financed the acquisitions of the Big Horn Basin and Williston Basin assets through borrowings under revolving credit facilities. As of December 31, 2006, estimated total proved reserves associated with the Big Horn Basin and Williston Basin acquisitions were 38,934 MBOE, 92 percent of which were oil and 90 percent of which were proved developed.
     See “Note 8. Debt” for additional discussion of EAC’s and ENP’s revolving credit facilities. See “Note 13. Financial Statements of Subsidiary Guarantors” for a discussion of EAC’s guarantor and non-guarantor subsidiaries.
Dispositions
     On June 29, 2007, EAC completed the sale of certain oil and natural gas properties in the Mid-Continent. In July 2007, additional Mid-Continent properties that were subject to preferential rights were sold. The total net proceeds were approximately $289.7 million, including estimated transactions costs of approximately $3.5 million, and EAC recorded a loss on sale of approximately $5.8 million, which is included in “Other operating expense” in the accompanying Consolidated Statements of Operations. The disposed properties included certain properties in the Anadarko and Arkoma fields of Oklahoma. EAC retained a material oil and natural gas interest in other properties in the Anadarko and Arkoma fields and remains active in those areas.
     Proceeds from the Mid-Continent disposition were used to reduce outstanding borrowings under EAC’s revolving credit facility. As of December 31, 2006, estimated total proved reserves associated with the Mid-Continent disposition were 17,416 MBOE, 92 percent of which were natural gas and 75 percent of which were proved developed.
Pro Forma
     The following unaudited pro forma condensed financial data for the three and nine months ended September 30, 2007 and 2006 was derived from the historical financial statements of EAC and from the accounting records of Anadarko to give effect to the Big Horn Basin and Williston Basin asset acquisitions and the Mid-Continent disposition as if they had occurred on January 1, 2006. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Big Horn Basin and Williston Basin acquisitions and the Mid-Continent disposition taken place as of the dates indicated and are not intended to be a projection of future results.
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
    (in thousands, except per share amounts)  
 
                               
Pro forma total revenues
  $ 195,016     $ 219,653     $ 522,778     $ 595,728  
 
                       
 
                               
Pro forma net income
  $ 14,171     $ 46,257     $ 4,879     $ 86,590  
 
                       
 
                               
Pro forma net income per common share:
                               
Basic
  $ 0.27     $ 0.87     $ 0.09     $ 1.68  
Diluted
  $ 0.26     $ 0.86     $ 0.09     $ 1.65  
Note 4. Inventory
     Inventory is comprised principally of materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. EAC’s inventory consisted of the following as of the dates indicated:

8


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
                 
    September 30,     December 31,  
    2007     2006  
    (in thousands)  
 
               
Materials and supplies
  $ 13,018     $ 11,784  
Oil in pipelines
    6,131       6,386  
 
           
Total inventory
  $ 19,149     $ 18,170  
 
           
Note 5. Proved Properties
     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties” include leasehold costs and wells and related equipment, both completed and in process, and consisted of the following as of the dates indicated:
                 
    September 30,     December 31,  
    2007     2006  
    (in thousands)  
 
               
Proved leasehold costs
  $ 1,325,112     $ 796,932  
Wells and related equipment — Completed
    1,373,207       1,200,938  
Wells and related equipment — In process
    42,486       36,044  
 
           
Total proved properties
  $ 2,740,805     $ 2,033,914  
 
           
Note 6. Derivative Financial Instruments
     EAC had $48.6 million of deferred premiums payable recorded at September 30, 2007, of which $21.7 million is considered long-term and recorded in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $26.9 million is considered current and recorded in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from October 2007 to January 2010. EAC recorded these amounts at their net present value at the time the contract was entered into and accretes that value up to the eventual settlement price by recording interest expense each period.
Commodity Contracts — Mark-to-Market Accounting: Previously designated as hedges
     Prior to July 2006, EAC used hedge accounting for certain of its derivative contracts, whereby the effective portion of changes in the fair value of the contract was deferred, until the hedged production occurred, in accumulated other comprehensive loss (“AOCL”) included in stockholders’ equity in the accompanying Consolidated Balance Sheets rather than recognized currently in earnings. In the third quarter of 2006, EAC elected to discontinue hedge accounting prospectively for all remaining commodity derivatives which were previously accounted for as hedges. While this change has no effect on 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. The deferred loss in AOCL at the time of dedesignation is being amortized to oil and natural gas revenues over the original term of the contracts. The amortization of these amounts is included in oil and natural gas revenues with the revenues from the hedged production. All mark-to-market gains and losses from July 2006 forward are recognized in earnings through “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations rather than deferring such amounts in AOCL.

9


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
     The following tables summarize EAC’s open commodity derivative instruments as of September 30, 2007:
Oil Derivative Instruments
                                                                                 
                                                                            Asset  
    Daily     Average       Daily     Average       Daily     Average       Daily     Average       (Liability)  
    Floor     Floor       Short Floor     Short Floor       Cap     Cap       Swap     Swap       Fair Market  
Period   Volume     Price       Volume     Price       Volume     Price       Volume     Price       Value  
    (Bbl)     (per Bbl)       (Bbl)     (per Bbl)       (Bbl)     (per Bbl)       (Bbl)     (per Bbl)       (in thousands)  
 
                                                                               
Oct. — Dec. 2007
    14,500     $ 56.72             $             $         3,000     $ 36.75       $ (11,847 )
Jan. — June 2008
    18,500       62.84         (4,000 )     50.00                       1,000       58.59         256  
July — Dec. 2008
    14,500       63.62         (4,000 )     50.00                                     6,395  
Jan. — Dec. 2009
    8,750       67.63         (5,000 )     50.00                       1,000       68.70         11,381  
Jan. — Dec. 2010
    2,000       65.00                       1,000       77.23                       1,496  
 
                                                                             
 
                                                                          $ 7,681  
 
                                                                             
Natural Gas Derivative Instruments
                                                                                 
    Daily     Average       Daily     Average       Daily     Average       Daily     Average       Asset  
    Floor     Floor       Short Floor     Short Floor       Cap     Cap       Swap     Swap       Fair Market  
Period   Volume     Price       Volume     Price       Volume     Price       Volume     Price       Value  
    (Mcf)     (per Mcf)       (Mcf)     (per Mcf)       (Mcf)     (per Mcf)       (Mcf)     (per Mcf)       (in thousands)  
 
                                                                               
Oct. — Dec. 2007
    36,500     $ 6.85             $         2,000     $ 9.85         10,000     $ 4.99       $ 1,562  
Jan. — Dec. 2008
    24,000       6.58                       2,000       9.85                       5,019  
Jan. — Dec. 2009
    4,000       7.70                       2,000       9.85                       992  
 
                                                                             
 
                                                                          $ 7,573  
 
                                                                             
Commodity Contracts — Mark-to-Market Accounting: Floor Spreads
     In order to partially finance the cost of premiums on certain purchased floors, EAC may sell floors with a strike price below the strike price of the purchased floor. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. EAC has entered into floor spreads with a $70 per Bbl purchased floor and a $50 per Bbl short floor for 4,000 Bbls/D in 2008 and 5,000 Bbls/D in 2009. As with EAC’s other derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. In the above table, the purchased floor component of these floor spreads has been included with EAC’s other floor contracts and the short floor component is shown separately as negative volumes.
Commodity Contracts — Current Period Impact
     EAC recognized a pre-tax reduction in oil and natural gas revenues of approximately $13.4 million and $14.4 million during the three months ended September 30, 2007 and 2006, respectively, and $40.2 million and $45.7 million during the nine months ended September 30, 2007 and 2006, respectively, related to commodity derivative contracts which were previously designated as hedges. EAC also recognized derivative fair value gains and losses related to (i) changes in the market value since the date of dedesignation of derivative contracts which were previously designated as hedges, (ii) changes in the market value of certain other commodity derivatives that were never designated as hedges, (iii) settlements on derivative contracts not designated as hedges, and (iv) ineffectiveness of derivative contracts designated as hedges prior to July 2006. The following table summarizes the components of derivative fair value loss (gain) for the three and nine months ended September 30, 2007 and 2006:

10


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
            (in thousands)          
 
                               
Ineffectiveness on designated cash flow hedges
  $     $     $     $ 1,748  
Mark-to-market loss (gain) on commodity contracts
    9,686       (37,729 )     56,122       (30,639 )
Premium amortization
    10,462       3,449       28,151       9,820  
Settlements on commodity contracts
    (4,362 )     917       (16,107 )     (1,192 )
 
                       
Total derivative fair value loss (gain)
  $ 15,786     $ (33,363 )   $ 68,166     $ (20,263 )
 
                       
Commodity Contracts — Future Period Impact
     At September 30, 2007 and December 31, 2006, AOCL consisted entirely of deferred losses on commodity derivatives which were previously designated as hedges of $10.2 million and $35.3 million, respectively.
     EAC expects to reclassify the remaining $16.3 million of deferred losses associated with its dedesignated commodity contracts from AOCL to oil and natural gas revenues by June 30, 2008. EAC also expects to reclassify the remaining $6.1 million of net deferred tax assets from AOCL to income tax benefit by June 30, 2008.
Note 7. Asset Retirement Obligations
     EAC’s primary asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. EAC does not include a market risk premium in its risk estimates because a reliable estimate cannot be determined. As of September 30, 2007, EAC had $6.0 million held in an escrow account from which funds are released only for reimbursement of plugging and abandonment expenses on its Bell Creek property. This amount is included in “Other assets” in the accompanying Consolidated Balance Sheets. The following table summarizes the changes in EAC’s future abandonment liability, the long-term portion of which is recorded in “Future abandonment cost” on the accompanying Consolidated Balance Sheets, for the nine months ended September 30, 2007 (in thousands):
         
Future abandonment liability at January 1, 2007
  $ 19,841  
Wells drilled
    89  
Accretion of discount
    867  
Plugging and abandonment costs incurred
    (497 )
Revision of estimates
    (604 )
Disposition of properties
    (959 )
Acquisition of properties
    10,745  
 
     
Future abandonment liability at September 30, 2007
  $ 29,482  
 
     
Note 8. Debt
     EAC’s long-term debt consisted of the following as of the dates indicated:
                 
    September 30,     December 31,  
    2007     2006  
    (in thousands)  
Revolving credit facilities
  $ 545,000     $ 68,000  
6 1/4% Senior Subordinated Notes due due April 15, 2014
    150,000       150,000  
6% Senior Subordinated Notes due July 15, 2015, net of unamortized discount of $4,555 and $4,892, respectively
    295,445       295,108  
7 1/4% Senior Subordinated Notes due December 1, 2017, net of unamortized discount of $1,346 and $1,412, respectively
    148,654       148,588  
 
           
Total
  $ 1,139,099     $ 661,696  
 
           

11


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
Revolving Credit Facilities
     Encore Acquisition Company Senior Secured Credit Agreement
     On March 7, 2007, EAC entered into a five-year amended and restated credit agreement (the “EAC Credit Agreement”) with a bank syndicate comprised of Bank of America, N.A. and other lenders, which amended and restated EAC’s Amended and Restated Credit Agreement dated as of August 19, 2004.
     The EAC Credit Agreement provides for revolving credit loans to be made to EAC from time to time and letters of credit to be issued from time to time for the account of EAC or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. Upon the contribution of certain assets in the Permian Basin to ENP at the closing of its IPO in September 2007, the borrowing base was reduced to $870 million. See “Note 16. ENP” for additional discussion.
     The EAC Credit Agreement matures on March 7, 2012. EAC’s obligations under the EAC Credit Agreement are secured by a first-priority security interest in EAC’s and its restricted subsidiaries’ proved oil and natural gas reserves and in the equity interests of EAC’s restricted subsidiaries. In addition, EAC’s obligations under the EAC Credit Agreement are guaranteed by its restricted subsidiaries.
     Loans under the EAC Credit Agreement are subject to varying rates of interest based on (i) the total amount outstanding in relation to the borrowing base and (ii) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:
                 
    Applicable Margin for   Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base   Eurodollar Loans   Base Rate Loans
Less than .50 to 1
    1.000 %     0.000 %
Greater than or equal to .50 to 1 but less than .75 to 1
    1.250 %     0.000 %
Greater than or equal to .75 to 1 but less than .90 to 1
    1.500 %     0.250 %
Greater than or equal to .90 to 1
    1.750 %     0.500 %
     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (ii) the federal funds effective rate plus 0.5 percent.
     As of September 30, 2007, the aggregate principal amount of loans outstanding under the EAC Credit Agreement was $478.5 million and the aggregate face amount of outstanding letters of credit was $20 million, all of which related to EAC’s joint development agreement with ExxonMobil Corporation (“ExxonMobil”). See “Note 14. Commitments and Contingencies” for additional discussion of this agreement. Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.
     The EAC Credit Agreement contains covenants that include, among others:
    a prohibition against incurring debt, subject to permitted exceptions;
 
    a prohibition against paying dividends or making distributions, purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;
 
    a restriction on creating liens on EAC’s and its restricted subsidiaries’ assets, subject to permitted exceptions;
 
    restrictions on merging and selling assets outside the ordinary course of business;
 
    restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;
 
    a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;
 
    a requirement that EAC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and

12


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
    a requirement that EAC maintain a ratio of consolidated EBITDA (as defined in the EAC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.
     The EAC Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable. EAC was in compliance with all of the debt covenants under the EAC Credit Agreement as of September 30, 2007.
     EAC incurs a commitment fee on the unused portion of the EAC Credit Agreement determined based on the ratio of amounts outstanding under the EAC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the calculation of the commitment fee under the EAC Credit Agreement:
         
    Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base   Fee Percentage
Less than .50 to 1
    0.250 %
Greater than or equal to .50 to 1 but less than ..75 to 1
    0.300 %
Greater than or equal to .75 to 1 but less than ..90 to 1
    0.375 %
Greater than or equal to .90 to 1
    0.375 %
     Encore Energy Partners Operating LLC Credit Agreement
     OLLC is a party to a five-year credit agreement dated March 7, 2007 (the “OLLC Credit Agreement”) with a bank syndicate comprised of Bank of America, N.A. and other lenders. On August 22, 2007, OLLC entered into the First Amendment to the OLLC Credit Agreement, which revised certain financial covenants. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.
     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As a result of the contribution of certain assets in the Permian Basin from EAC to OLLC at the closing of ENP’s IPO in September 2007, the borrowing base was increased to $145 million.
     The OLLC Credit Agreement matures on March 7, 2012. OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s and its restricted subsidiaries’ proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the OLLC Credit Agreement are guaranteed by its direct parent, ENP, and OLLC’s restricted subsidiaries. EAC consolidates the debt of ENP with that of its own; however, obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.
     Loans under the OLLC Credit Agreement are subject to varying rates of interest based on the same provisions as the EAC Credit Agreement.
     As of September 30, 2007, the aggregate principal amount of loans outstanding under the OLLC Credit Agreement was $66.5 million and there were no outstanding letters of credit. Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.
     The OLLC Credit Agreement contains covenants that include, among others:
    a prohibition against incurring debt, subject to permitted exceptions;
 
    a prohibition against paying dividends or making distributions prior to the IPO Effective Date (as defined in the OLLC Credit Agreement), purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;
 
    a restriction on creating liens on the assets of ENP, OLLC and its restricted subsidiaries, subject to permitted exceptions;
 
    restrictions on merging and selling assets outside the ordinary course of business;
 
    restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

13


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
    a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;
 
    a requirement that OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;
 
    a requirement that OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;
 
    a requirement that OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and
 
    a requirement that OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA (as defined in the OLLC Credit Agreement) of not more than 3.5 to 1.0.
     The OLLC Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable. At September 30, 2007, OLLC was in compliance with all of the debt covenants under the OLLC Credit Agreement, as amended.
     OLLC incurs a commitment fee on the unused portion of the OLLC Credit Agreement determined based on the same provisions as the EAC Credit Agreement.
Note 9. Income Taxes
     The components of the income tax provision were as follows for the nine months ended September 30, 2007 and 2006:
                 
    Nine months ended  
    September 30,  
    2007     2006  
    (in thousands)  
Federal:
               
Current
  $ (116 )   $ (1,361 )
Deferred
    (679 )     (45,405 )
 
           
Total federal
    (795 )     (46,766 )
 
           
 
               
State, net of federal benefit/expense:
               
Current
          (1,348 )
Deferred
    (695 )     (3,268 )
 
           
Total state
    (695 )     (4,616 )
 
           
Income tax provision
  $ (1,490 )   $ (51,382 )
 
           
     The following table reconciles income tax provision with income tax at the Federal statutory rate for the nine months ended September 30, 2007 and 2006:
                 
    Nine months ended  
    September 30,  
    2007     2006  
    (in thousands)  
Income (loss) before income taxes
  $ (782 )   $ 133,688  
 
           
Tax at statutory rate
  $ 274     $ (46,791 )
State income taxes, net of federal benefit/expense
    19       (3,118 )
Enactment of the Texas margin tax
          (1,389 )
Change in estimated future tax rate
    (597 )      
ENP minority interest in deferred compensation
    (1,238 )      
Permanent and other
    52       (84 )
 
           
Income tax provision
  $ (1,490 )   $ (51,382 )
 
           
     On January 1, 2007, EAC adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes

14


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. EAC and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, EAC is no longer subject to U.S. federal, state, and local income tax examinations for years prior to 2003.
     EAC has performed its evaluation of tax positions and has determined that the adoption of FIN 48 did not have a material impact on EAC’s financial condition, results of operations, or cash flows. This evaluation is a review of the appropriate recognition threshold for each tax position recognized in EAC’s financial statements. The evaluation included, but was not limited to:
    a review of documentation of tax positions taken on previous returns including an assessment of whether EAC followed industry practice or the applicable requirements under the tax code;
 
    a review of open tax returns (on a jurisdiction by jurisdiction basis) as well as supporting documentation used to support those tax returns;
 
    a review of the results of past tax examinations;
 
    a review of whether tax returns have been filed in all appropriate jurisdictions;
 
    a review of existing permanent and temporary differences; and
 
    consideration of any tax planning strategies that may have been used to support realization of deferred tax assets.
Based on this evaluation, EAC did not identify any tax positions that did not meet the “highly certain positions” threshold. As a result, no additional tax expense, interest, or penalties have been accrued as a result of the review.
     EAC includes interest assessed by the taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. For the nine months ended September 30, 2007 and 2006, EAC recorded only a nominal amount of interest and penalties on certain tax positions.
Note 10. Earnings Per Share (“EPS”)
     The following table reflects EPS computations for the three and nine months ended September 30, 2007 and 2006:
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
            (in thousands, except per share data)  
 
                               
Numerator:
                               
Net income (loss)
  $ 11,985     $ 42,135     $ (2,272 )   $ 82,306  
 
                       
 
                               
Denominator:
                               
Denominator for basic EPS:
                               
Weighted average shares outstanding
    53,198       52,968       53,140       51,481  
Effect of dilutive options and diluted restricted stock (a)
    981       808             894  
 
                       
Denominator for diluted EPS
    54,179       53,776       53,140       52,375  
 
                       
 
                               
Net income (loss) per common share:
                               
Basic
  $ 0.23     $ 0.80     $ (0.04 )   $ 1.60  
Diluted
  $ 0.22     $ 0.78     $ (0.04 )   $ 1.57  
 
(a)   For the three months ended September 30, 2007 and 2006, options to purchase 95,253 shares of common stock and 106,274 shares of common stock, respectively, were outstanding but not included in the above calculation of diluted EPS because their effect would have been antidilutive. For the nine months ended September 30, 2007 and 2006, options to purchase 1,422,350 shares of common stock and 95,395 shares of common stock, respectively, were outstanding but not included in the above calculation of diluted EPS because their effect would have been antidilutive. The effect of dilutive options and diluted restricted stock for the nine months ended September 30, 2007 and 2006 is an average of the effect of the dilutive options and diluted restricted stock for the first three quarters of each respective year.

15


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
Note 11. Incentive Stock Plan
     During 2000, EAC’s Board of Directors (the “Board”) and stockholders approved the 2000 Incentive Stock Plan (the “EAC Plan”). The EAC Plan was amended and restated effective March 18, 2004. The purpose of the EAC Plan is to attract, motivate, and retain selected employees of EAC and to provide EAC with the ability to provide incentives more directly linked to the profitability of the business and increases in shareholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the EAC Plan. The total number of shares of common stock reserved for issuance pursuant to the EAC Plan is 4,500,000. As of September 30, 2007, there were 849,538 shares available for issuance under the EAC Plan. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax withholding, or shares subject to options or other awards that expire or are terminated and restricted shares that are forfeited will again become available for issuance under the EAC Plan. The EAC Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Board. The Board also has a Restricted Stock Award Committee having Jon S. Brumley, EAC’s Chief Executive Officer and President, as its sole member. The Restricted Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual basis to non-executive employees at its discretion.
     The EAC Plan contains the following individual limits:
    an employee may not be granted awards covering or relating to more than 225,000 shares of common stock in any calendar year;
 
    a non-employee director may not be granted awards covering or relating to more than 15,000 shares of common stock in any calendar year; and
 
    an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having a value determined on the grant date in excess of $1.0 million.
     All options that have been granted under the EAC Plan have a strike price equal to the fair market value of EAC’s common stock on the date of grant. Additionally, all options have a ten-year life and vest equally over a three-year period. Restricted stock granted under the EAC Plan vests over varying periods from one to five years, subject to performance-based vesting for certain members of senior management.
     The compensation cost related to the EAC Plan that has been recorded in the accompanying Consolidated Statements of Operations for the nine months ended September 30, 2007 and 2006 was $7.0 million and $6.6 million, respectively. The income tax benefit related to the EAC Plan that has been recorded in the accompanying Consolidated Statements of Operations for the nine months ended September 30, 2007 and 2006 was $2.6 million and $2.4 million, respectively. During each of the nine months ended September 30, 2007 and 2006, EAC also capitalized $0.9 million of non-cash stock-based compensation cost as a component of “Properties and equipment” in the accompanying Consolidated Balance Sheets. Non-cash stock-based compensation expense has been allocated to lease operations expense, general and administrative expense, and exploration expense based on the allocation of the respective employees’ cash compensation.
     See “Note 16. ENP” for a discussion of ENP’s unit-based compensation plan.
Stock Options
     The fair value of each option award granted during the nine months ended September 30, 2007 and 2006 was estimated on the date of grant using the Black-Scholes option valuation model based on the assumptions noted in the following table. The expected volatility is based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the award. EAC uses the “simplified” method prescribed by SEC Staff Accounting Bulletin No. 107 to estimate the expected term of the options, which is calculated as the average midpoint between each vesting date and the life of the option. The risk-free rate is based on the U.S Treasury yield curve in effect at the time of grant for periods commensurate with the expected terms of the options.

16


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
                 
    Nine months ended September 30,
    2007   2006
Expected volatility
    35.7 %     42.8 %
Expected dividend yield
    0.0 %     0.0 %
Expected term (in years)
    6.0       6.0  
Risk-free interest rate
    4.8 %     4.6 %
     The following table summarizes the change in the number of outstanding options and the related weighted average strike prices during the nine months ended September 30, 2007:
                                 
                    Weighted    
            Weighted   Average   Aggregate
    Number of   Average   Remaining   Intrinsic
    Options   Strike Price   Contractual Term   Value
    (in thousands)
Outstanding at January 1, 2007
    1,337,118     $ 14.44                  
Granted
    200,059       25.73                  
Forfeited
    (23,118 )     28.30                  
Exercised
    (91,709 )     13.10                  
 
                               
Outstanding at September 30, 2007
    1,422,350       15.89       5.8     $ 22,415  
 
                               
Exercisable at September 30, 2007
    1,141,977       13.16       5.0       21,111  
 
                               
     The weighted average fair value per share of individual options granted during the nine months ended September 30, 2007 and 2006 was $11.16 and $14.96, respectively. The total intrinsic value of options exercised during the nine months ended September 30, 2007 and 2006 was $1.3 million and $2.4 million, respectively. During the nine months ended September 30, 2007 and 2006, EAC received proceeds from the exercise of stock options of $1.0 million and $2.3 million, respectively, and realized tax benefits related to stock options of $0.4 million and $0.9 million, respectively. At September 30, 2007, EAC had $1.6 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 2.0 years.
Restricted Stock
     During the nine months ended September 30, 2007 and 2006, EAC recognized expense related to restricted stock of $5.8 million and $5.6 million, respectively, and realized tax benefits related to restricted stock of $2.2 million and $2.1 million, respectively. A summary of the status of EAC’s unvested restricted stock outstanding as of September 30, 2007, and changes during the nine months then ended, is presented below:
                 
            Weighted
            Average
    Number of   Grant Date
    Shares   Fair Value
 
               
Outstanding at January 1, 2007
    828,619     $ 26.17  
Granted
    342,133       25.90  
Vested
    (118,273 )     25.40  
Forfeited
    (61,145 )     26.22  
 
               
Outstanding at September 30, 2007
    991,334       26.17  
 
               
     As of September 30, 2007, there were 819,059 shares of unvested restricted stock outstanding, dependent only on the passage of time and continued employment for vesting, 159,869 shares of which were granted during the nine months ended September 30, 2007. Additionally, as of September 30, 2007, there were 172,275 shares of unvested restricted stock outstanding that not only depend on the passage of time and continued employment, but on certain performance measures for vesting, all of which were granted during the nine months ended September 30, 2007. None of EAC’s unvested restricted stock outstanding are subject to variable accounting.

17


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
     As of September 30, 2007, EAC had $11.3 million of total unrecognized compensation cost related to unvested, outstanding restricted stock, which is expected to be recognized over a weighted average period of 2.7 years. During the nine months ended September 30, 2007 and 2006, there were 118,273 shares and 27,909 shares, respectively, of restricted stock that vested and employees elected to satisfy minimum tax withholding obligations related to these shares by allowing EAC to withhold 5,545 shares and 6,553 shares of common stock, respectively. These shares are treated as treasury stock by EAC until the shares are formally retired and have been reflected as such in the accompanying consolidated financial statements.
Note 12. Comprehensive Income
     Components of comprehensive income, net of related tax, are as follows:
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
    (in thousands)  
Net income (loss)
  $ 11,985     $ 42,135     $ (2,272 )   $ 82,306  
Amortization of deferred loss on commodity derivatives
    8,596       8,894       25,150       28,448  
Amortization of deferred gain on interest rate swap
          (63 )           (92 )
 
                       
Comprehensive income
  $ 20,581     $ 50,966     $ 22,878     $ 110,662  
 
                       
Note 13. Financial Statements of Subsidiary Guarantors
     In February 2007, EAC formed certain non-guarantor subsidiaries in connection with the formation of ENP. See “Note 16. ENP” for additional discussion of ENP’s formation and other matters. As of September 30, 2007, certain of EAC’s wholly owned subsidiaries were subsidiary guarantors of EAC’s outstanding notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. In accordance with SEC rules, EAC has prepared condensed consolidating financial statements in order to quantify the assets and results of operations of the subsidiary guarantors. The following Condensed Consolidating Balance Sheet as of September 30, 2007, Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) for the three and nine months ended September 30, 2007, and Condensed Consolidating Statement of Cash Flows for the nine months ended September 30, 2007 present consolidating financial information for Encore Acquisition Company (“Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. The guarantor subsidiaries are:
    EAP Energy, Inc.;
 
    EAP Properties Inc.;
 
    EAP Operating Inc.;
 
    EAP Energy Services, L.P.;
 
    Encore Operating; and
 
    Encore Operating Louisiana, LLC.
The non-guarantor subsidiaries are:
    ENP;
 
    OLLC;
 
    Encore Partners GP Holdings LLC;
 
    Encore Partners LP Holdings LLC;
 
    Encore Energy Partners GP LLC; and
 
    Encore Clear Fork Pipeline LLC.
     All intercompany investments in, loans due to/from, subsidiary equity, income and expenses between the Parent, the guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to final consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements of EAC. Prior to February 2007, all of EAC’s subsidiaries were subsidiary guarantors of EAC’s outstanding senior notes. Therefore, comparative condensed consolidating financial statements are not presented as of December 31, 2006 or for the three and nine months ended September 30, 2006.
     Income taxes in the Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) are shown as an expense of the Parent as EAC files a consolidated return. Additionally, EAC’s net current deferred tax asset and net long-term deferred tax liability have been included in the balance sheet of the Parent in the Condensed Consolidating Balance Sheet.

18


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
CONDENSED CONSOLIDATING BALANCE SHEET
September 30, 2007

(in thousands)
                                         
            Guarantor     Non-Guarantor             Consolidated  
    Parent     Subsidiaries     Subsidiaries     Eliminations     Total  
ASSETS
                                       
 
                                       
Current assets:
                                       
Cash and cash equivalents
  $     $ 1,353     $ 7,114     $     $ 8,467  
Other current assets
    134,385       135,252       15,791       (121,255 )     164,173  
 
                             
Total current assets
    134,385       136,605       22,905       (121,255 )     172,640  
 
                             
 
                                       
Properties and equipment, at cost — successful efforts method:
                                       
Proved properties, including wells and related equipment
          2,369,011       371,794             2,740,805  
Unproved properties
          56,427                   56,427  
Accumulated depletion, depreciation, and amortization
          (411,883 )     (30,510 )           (442,393 )
 
                             
 
          2,013,555       341,284             2,354,839  
 
                             
 
                                       
Other property and equipment, net
          10,436       62             10,498  
Other assets, net
    15,571       142,649       13,960       (10,357     161,823  
Investment in subsidiaries
    2,266,381                   (2,266,381 )      
 
                             
Total assets
  $ 2,416,337     $ 2,303,245     $ 378,211     $ (2,397,993 )   $ 2,699,800  
 
                             
 
                                       
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                       
 
                                       
Current liabilities
  $ 15,795     $ 278,283     $ 12,752     $ (121,255 )   $ 185,575  
Deferred taxes
    294,849             122             294,971  
Long-term debt
    1,082,956             66,500       (10,357 )     1,139,099  
Other liabilities
          46,363       11,055             57,418  
 
                             
Total liabilities
    1,393,600       324,646       90,429       (131,612 )     1,677,063  
 
                                       
Commitments and contingencies (see Note 14)
                                       
 
                                       
Minority interest in consolidated partnership
    181,412                         181,412  
 
                                       
Total stockholders’ equity
    841,325       1,978,599       287,782       (2,266,381 )     841,325  
 
                             
Total liabilities and stockholders’ equity
  $ 2,416,337     $ 2,303,245     $ 378,211     $ (2,397,993 )   $ 2,699,800  
 
                             

19


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended September 30, 2007

(in thousands)
                                         
            Guarantor     Non-Guarantor             Consolidated  
    Parent     Subsidiaries     Subsidiaries     Eliminations     Total  
Revenues:
                                       
Oil
  $     $ 141,185     $ 18,110     $     $ 159,295  
Natural gas
          29,523       2,916             32,439  
Marketing
          1,148       2,134             3,282  
 
                             
Total revenues
          171,856       23,160             195,016  
 
                             
 
                                       
Expenses:
                                       
Production:
                                       
Lease operations
          32,722       4,392             37,114  
Production, ad valorem, and severance taxes
          17,432       2,571             20,003  
Depletion, depreciation, and amortization
          40,668       8,358             49,026  
Exploration
          8,914       6             8,920  
General and administrative
    20       6,072       6,576             12,668  
Marketing
          2,789       1,300             4,089  
Derivative fair value loss
          12,797       2,989             15,786  
Other operating
    41       6,073       237             6,351  
 
                             
Total expenses
    61       127,467       26,429             153,957  
 
                             
 
                                       
Operating income (loss)
    (61 )     44,389       (3,269 )           41,059  
 
                             
 
                                       
Other income (expenses):
                                       
Interest
    (10,601 )     (14,052 )     (4,829 )     5,549       (23,933 )
Equity income (loss) from subsidiaries
    25,775                   (25,775 )      
Other
    2,794       3,565       47       (5,549 )     857  
 
                             
Total other income (expenses)
    17,968       (10,487 )     (4,782 )     (25,775 )     (23,076 )
 
                             
 
                                       
Income (loss) before income taxes and minority interest
    17,907       33,902       (8,051 )     (25,775 )     17,983  
Income tax provision
    (8,910 )     (61 )     (15 )           (8,986 )
Minority interest in loss of consolidated partnership
    2,988                         2,988  
 
                             
 
                                       
Net income (loss)
    11,985       33,841       (8,066 )     (25,775 )     11,985  
Amortization of deferred hedge (gains) losses, net of tax
    (4,801     13,397                   8,596  
 
                             
Comprehensive income (loss)
  $ 7,184     $ 47,238     $ (8,066 )   $ (25,775 )   $ 20,581  
 
                             

20


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2007

(in thousands)
                                         
            Guarantor     Non-Guarantor             Consolidated  
    Parent     Subsidiaries     Subsidiaries     Eliminations     Total  
Revenues:
                                       
Oil
  $     $ 338,935     $ 38,579     $     $ 377,514  
Natural gas
          101,728       8,820             110,548  
Marketing
          20,153       6,986             27,139  
 
                             
Total revenues
          460,816       54,385             515,201  
 
                             
 
                                       
Expenses:
                                       
Production:
                                       
Lease operations
          95,843       9,343             105,186  
Production, ad valorem, and severance taxes
          45,893       5,857             51,750  
Depletion, depreciation, and amortization
          117,602       18,770             136,372  
Exploration
          23,847       9             23,856  
General and administrative
    57       18,491       7,668             26,216  
Marketing
          21,952       5,655             27,607  
Derivative fair value loss
          58,680       9,486             68,166  
Other operating
    124       13,018       525             13,667  
 
                             
Total expenses
    181       395,326       57,313             452,820  
 
                             
 
                                       
Operating income (loss)
    (181 )     65,490       (2,928 )           62,381  
 
                             
 
                                       
Other income (expenses):
                                       
Interest
    (63,182 )     (6,415 )     (11,273 )     12,830       (68,040 )
Equity income (loss) from subsidiaries
    53,098                   (53,098 )      
Other
    6,419       8,226       74       (12,830 )     1,889  
 
                             
Total other income (expenses)
    (3,665 )     1,811       (11,199 )     (53,098 )     (66,151 )
 
                             
 
                                       
Income (loss) before income taxes and minority interest
    (3,846 )     67,301       (14,127 )     (53,098 )     (3,770 )
Income tax provision
    (1,414 )     (22     (54 )           (1,490 )
Minority interest in loss of consolidated partnership
    2,988                         2,988  
 
                             
 
                                       
Net income (loss)
    (2,272 )     67,279       (14,181 )     (53,098 )     (2,272 )
Amortization of deferred hedge (gains) losses, net of tax
    (15,041     40,191                   25,150  
 
                             
Comprehensive income (loss)
  $ (17,313   $ 107,470     $ (14,181 )   $ (53,098 )   $ 22,878  
 
                             

21


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2007

(in thousands)
                                         
            Guarantor     Non-Guarantor             Consolidated  
    Parent     Subsidiaries     Subsidiaries     Eliminations     Total  
Cash flows from operating activities:
                                       
Net cash provided by operating activities
  $     $ 199,333     $ 14,311     $     $ 213,644  
 
                             
 
                                       
Cash flows from investing activities:
                                       
Proceeds from disposition of assets
          291,339                   291,339  
Acquisition of oil and natural gas properties
          (509,630 )     (330,315 )           (839,945 )
Development of oil and natural gas properties
          (256,797 )     (2,660 )           (259,457 )
Investments in subsidiaries
    (400,158 )                 400,158        
Other
          (25,013 )     (74 )           (25,087 )
 
                             
Net cash provided by (used in) investing activities
    (400,158 )     (500,101 )     (333,049 )     400,158       (833,150 )
 
                             
 
                                       
Cash flows from financing activities:
                                       
Proceeds from issuance of ENP common units, net of issuance costs
                171,220             171,220  
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases
    1,053                         1,053  
Proceeds from long-term debt, net of issuance costs
    1,020,533             248,758             1,269,291  
Payments on long-term debt
    (621,428 )           (184,000 )           (805,428 )
Net equity contributions
          306,500       93,658       (400,158 )      
Other
          (5,142 )     (3,784 )           (8,926 )
 
                             
Net cash provided by (used in) financing activities
    400,158       301,358       325,852       (400,158 )     627,210  
 
                             
 
                                       
Increase in cash and cash equivalents
          590       7,114             7,704  
Cash and cash equivalents, beginning of period
          763                   763  
 
                             
Cash and cash equivalents, end of period
  $     $ 1,353     $ 7,114     $     $ 8,467  
 
                             
Note 14. Commitments and Contingencies
Litigation
     EAC is a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these proceedings will have a material adverse effect on EAC.
ExxonMobil
     In March 2006, EAC entered into a joint development agreement with ExxonMobil to develop legacy natural gas fields in West Texas. Under the terms of the agreement, EAC will have the opportunity to develop approximately 100,000 gross acres. EAC will earn 30 percent of ExxonMobil’s working interest and 22.5 percent of ExxonMobil’s net revenue interest in each well drilled. EAC will operate each well during the drilling and completion phase, after which ExxonMobil will assume operational control of the well.
     EAC will earn the right to participate in all fields by drilling a total of 24 commitment wells. During the commitment phase, ExxonMobil will have the option to receive non-recourse advanced funds from EAC attributable to ExxonMobil’s 70 percent working interest in each commitment well. Once a commitment well is producing, ExxonMobil will repay 95 percent of the advanced funds plus accrued interest assessed on the unpaid balance through EAC’s monthly receipt of future proceeds of oil and natural gas sales. As an alternative to receiving advanced funds during the commitment phase, ExxonMobil can elect to pay their share of capital costs for each well. After EAC has fulfilled its obligations under the commitment phase, it will be entitled to a 30 percent working interest in future drilling locations. EAC will have the right to propose and drill wells for as long as it is engaged in continuous drilling operations.
     During the nine months ended September 30, 2007 and the year ended December 31, 2006, EAC advanced $30.8 million and $22.4 million, respectively, to ExxonMobil for its portion of capital related to drilling commitment wells, of which $48.0 million and $21.0 million remained outstanding at September 30, 2007 and December 31, 2006, respectively. At September 30,

22


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
2007, $2.5 million is included in “Accounts receivable” and $45.5 million is included in “Long-term receivables” on the accompanying Consolidated Balance Sheet based on when EAC expects repayment. At December 31, 2006, $3.0 million is included in “Accounts receivable” and $18.0 million is included in “Long-term receivables” on the accompanying Consolidated Balance Sheet. As of September 30, 2007, EAC had seven additional wells to drill in order to fulfill its drilling obligation under the joint development agreement at a minimum cost of $1.0 million per well.
Note 15. Related Party Transactions
     EAC paid $1.3 million and $2.8 million to affiliates of Hanover Compressor Company (“Hanover”) during the nine months ended September 30, 2007 and 2006, respectively, for compressors and field compression services. Mr. I. Jon Brumley, EAC’s Chairman of the Board, served as a director of Hanover until August 2007.
     EAC also received $47.2 million and $5.9 million from affiliates of Tesoro Corporation (“Tesoro”) during the nine months ended September 30, 2007 and 2006, respectively, related to its working interest in wells operated by EAC. Mr. John V. Genova, a member of the Board, is employed by Tesoro.
Note 16. ENP
     On September 17, 2007, ENP completed its IPO of 9,000,000 common units, representing a 37.4 percent limited partner interest, at a price to the public of $21.00 per unit. The net proceeds of $171.2 million, after deducting the underwriters’ discount and a structuring fee of $13.2 million, in the aggregate, and estimated offering expenses of $4.6 million, were used to repay in full the $126.4 million of outstanding indebtedness under ENP’s subordinated credit agreement with EAP Operating Inc., and $43.5 million of outstanding borrowings under the OLLC Credit Agreement.
     In connection with the closing of the IPO, EAC, ENP, and certain of their respective subsidiaries entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) and an amended and restated administrative services agreement (the “Administrative Services Agreement”), each as more fully described below. In addition, prior to the IPO, Encore Energy Partners GP LLC approved a long-term incentive plan (the “ENP Plan”) for employees, consultants, and directors of Encore Operating, Encore Energy Partners GP LLC, and any of their affiliates who perform services for ENP, as more fully described below.
Contribution, Conveyance and Assumption Agreement
     ENP entered into the Contribution Agreement with Encore Energy Partners GP LLC, ENP’s general partner and wholly owned subsidiary of EAC, OLLC, EAC, Encore Operating, and Encore Partners LP Holdings LLC. At the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:
    Encore Operating transferred certain assets in the Permian Basin, as described in the ENP’s final prospectus (the “Prospectus”) dated September 11, 2007 (File No. 333-142847) and filed with the SEC on September 12, 2007, to ENP in exchange for 4,043,478 common units; and
 
    EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities, and title defects, as well as defects relating to retained assets and liabilities, occurring or existing before the closing.
     These transfers and distributions were made in a series of steps outlined in the Contribution Agreement.
     In connection with the issuance of the common units by ENP in exchange for the Permian Basin assets, the IPO, and the exercise of the underwriters’ option to purchase additional common units, Encore Energy Partners GP LLC exchanged such number of common units for general partner units as was necessary to enable it to maintain its two percent general partner interest. Encore Energy Partners GP LLC received the common units through capital contributions from EAC and its subsidiaries of common units they owned.
Administrative Services Agreement
     ENP entered into the Administrative Services Agreement with Encore Energy Partners GP LLC, OLLC, Encore Operating,

23


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
and EAC. As more fully described in the Prospectus, Encore Operating will perform administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering. In addition, Encore Operating will provide all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by the Partnership. Encore Operating will receive an administrative fee of $1.75 per BOE of ENP’s production for such services and reimbursement of actual third-party expenses incurred on ENP’s behalf.
     In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well. Most joint operating agreements provide for an annual increase or decrease in the COPAS overhead rate for drilling and producing wells. The rate change, which occurs in April, is based on the change in average weekly earnings as measured by an index published by the United States Department of Labor, Bureau of Labor Statistics. The COPAS overhead cost is charged to all non-operating interest owners under a joint operating agreement each month.
     ENP will also reimburse EAC for any additional state income, franchise, or similar tax paid by EAC resulting from the inclusion of ENP (and its subsidiaries) in a combined state income, franchise, or similar tax report with EAC as required by applicable law. The amount of any such reimbursement will be limited to the tax that ENP (and its subsidiaries) would have paid had it not been included in a combined group with EAC.
     ENP does not have any employees. The employees supporting the operation of ENP are employees of Encore Operating. Accordingly, EAC recognizes all employee-related liabilities in its consolidated financial statements. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. ENP also pays its share of expenses that are directly chargeable to wells under joint operating agreements. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the Administrative Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.
Long-Term Incentive Plan
     The ENP Plan is for employees, consultants, and directors of Encore Operating, Encore Energy Partners GP LLC, and any of their affiliates who perform services for ENP. As more fully described in the Prospectus, the ENP Plan provides for the grant of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. An aggregate of 1,150,000 common units may be delivered pursuant to awards under the ENP Plan. The ENP Plan will be administered by the board of directors of Encore Energy Partners GP LLC or a committee thereof, referred to as the plan administrator.
     As of September 30, 2007, no awards had been granted under the ENP Plan.
Management Incentive Units
     In May 2007, the board of directors of Encore Energy Partners GP LLC issued 550,000 management incentive units to the executive officers of Encore Energy Partners GP LLC. A management incentive unit is a limited partner interest in ENP that entitles the holder to an initial quarterly distribution of $0.35 (or $1.40 on an annualized basis) to the extent paid to ENP’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in ENP’s distribution rate to common unitholders. A management incentive unit is also convertible into common units upon the occurrence of certain events. The management incentive units are subject to a maximum limit on the aggregate number of common units issuable to, and the aggregate distributions payable to, holders of management incentive units as follows:
    the holders of management incentive units are not entitled to receive, in the aggregate, common units upon conversion of the management incentive units that exceed a maximum limit of 5.1 percent of all ENP’s then-outstanding common units; and
 
    the holders of management incentive units are not entitled to receive, in the aggregate, distributions of ENP’s available cash in an amount that exceeds a maximum limit of 5.1 percent of all such distributions to all unitholders at the time of any such distribution.
     The holders of management incentive units do not have any voting rights with respect to the unit.

24


Table of Contents

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)
     The management incentive units vest in three equal installments. The first installment vested upon the closing of the IPO, and the subsequent vesting will occur on the first and second anniversary of such closing date. For the three and nine months ended September 30, 2007, ENP recognized total compensation expense for the management incentive units of $5.7 million, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of September 30, 2007, ENP had $5.8 million of total unrecognized compensation cost related to unvested, outstanding management incentive units, which is expected to be recognized over a weighted average period of 1.5 years. For the fourth quarter 2007 through the third quarter of 2008, the expense will be approximately $1.1 million per quarter, and for the fourth quarter 2008 through the third quarter of 2009, the expense will be approximately $0.4 million per quarter. There have been no additional issuances or forfeitures of management incentive units since the initial issuance.
Note 17. Subsequent Events
     On October 11, 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units of ENP, representing an additional 2.9 percent limited partner interest, which closed on October 16, 2007. The Company expects to use the net proceeds of $22.4 million, after deducting the underwriters’ discount of $1.7 million, to repay outstanding borrowings under the OLLC Credit Agreement.
     On October 29, 2007, ENP issued 20,000 phantom units to members of the Encore Energy Partners GP LLC board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. The phantom units vest in four equal installments beginning on the first anniversary of the date of grant. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle the grantee to receive cash equal to the amount of any cash distributions made by the Partnership with respect to a common unit during the period the right is outstanding.
     On October 29, 2007, ENP declared a distribution for the third quarter of 2007 to unitholders of record as of the close of business on November 8, 2007. The $1.3 million total cash distribution will be paid on November 14, 2007 to unitholders at a rate of $0.053 per unit. The prorated quarterly distribution of $0.053 per unit is based on an initial quarterly distribution of $0.35 per unit, prorated for the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007.

25


Table of Contents

ENCORE ACQUISITION COMPANY
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     This document contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results may differ materially from those discussed in our forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report and in “Item 8. Financial Statements and Supplementary Data” of our 2006 Annual Report on Form 10-K.
Introduction
     In this management’s discussion and analysis of financial condition and results of operations, the following will be discussed and analyzed:
    Third Quarter 2007 Highlights
 
    Results of Operations
    Comparison of Quarter Ended September 30, 2007 to Quarter Ended September 30, 2006
 
    Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006
    Capital Resources
 
    Capital Commitments and Contingencies
 
    Liquidity
 
    Critical Accounting Policies and Estimates
 
    New Accounting Pronouncements
Third Quarter 2007 Highlights
     Our financial and operating results for the third quarter of 2007 included the following:
    Our oil and natural gas revenues increased 46 percent to $191.7 million as compared to $131.7 million in the third quarter of 2006. Our oil and natural gas revenues increased as a result of increased production volumes and higher realized average prices.
 
    Our realized average oil price, including the effects of commodity derivative contracts, increased $8.68 per Bbl to $63.48 per Bbl as compared to $54.80 per Bbl in the third quarter of 2006. Our realized average natural gas price, including the effects of commodity derivative contracts, increased $0.21 per Mcf to $6.09 per Mcf as compared to $5.88 per Mcf in the third quarter of 2006.
 
    Production volumes increased 25 percent to 36,917 BOE/D as compared to 29,651 BOE/D for the third quarter of 2006. The rise in production volumes was primarily attributable to our Big Horn Basin and Williston Basin acquisitions and our development programs. Oil represented 74 percent and 67 percent of our total production volumes in the third quarter of 2007 and 2006, respectively.
 
    We invested $124.9 million in oil and natural gas activities (excluding related asset retirement obligations of $0.3 million). Of this amount, we invested $78.0 million in development, exploitation, HPAI expansion, and exploration activities, which yielded 49 gross (15.5 net) productive wells, and $46.9 million in acquisitions. We operated between six and nine drilling rigs, including four to six rigs related to our West Texas joint development agreement.
 
    On September 17, 2007, ENP completed its IPO of 9,000,000 common units, representing a 37.4 percent limited partner interest in ENP, at a price to the public of $21.00 per unit. On October 11, 2007, the underwriters exercised their over- allotment option to purchase 1,148,400 additional ENP common units, representing an additional 2.9 percent limited partner interest in ENP. EAC currently owns approximately 58.0 percent of ENP’s common units, as well as all the interests of ENP’s general partner, which a wholly owned subsidiary of EAC.

26


Table of Contents

ENCORE ACQUISITION COMPANY
Results of Operations
Comparison of Quarter Ended September 30, 2007 to Quarter Ended September 30, 2006
     Oil and natural gas revenues and production. The following table illustrates the primary components of oil and natural gas revenues for the three months ended September 30, 2007 and 2006, as well as each quarter’s respective oil and natural gas production volumes:
                                 
    Three months ended September 30,        
    2007     2006     Increase / (Decrease)  
Revenues (in thousands):
                               
Oil wellhead
  $ 170,118     $ 112,959     $ 57,159          
Oil hedges
    (10,823 )     (13,443 )     2,620          
 
                         
Total oil revenues
  $ 159,295     $ 99,516     $ 59,779       60 %
 
                         
 
                               
Natural gas wellhead
  $ 35,012     $ 33,144     $ 1,868          
Natural gas hedges
    (2,573 )     (967 )     (1,606 )        
 
                         
Total natural gas revenues
  $ 32,439     $ 32,177     $ 262       1 %
 
                         
 
                               
Combined wellhead
  $ 205,130     $ 146,103     $ 59,027          
Combined hedges
    (13,396 )     (14,410 )     1,014          
 
                         
Total combined oil and natural gas revenues
  $ 191,734     $ 131,693     $ 60,041       46 %
 
                         
 
                               
Average realized prices:
                               
Oil wellhead ($/Bbl)
  $ 67.80     $ 62.20     $ 5.60          
Oil hedges ($/Bbl)
    (4.32 )     (7.40 )     3.08          
 
                         
Total oil revenues ($/Bbl)
  $ 63.48     $ 54.80     $ 8.68       16 %
 
                         
 
                               
Natural gas wellhead ($/Mcf)
  $ 6.58     $ 6.06     $ 0.52          
Natural gas hedges ($/Mcf)
    (0.49 )     (0.18 )     (0.31 )        
 
                         
Total natural gas revenues ($/Mcf)
  $ 6.09     $ 5.88     $ 0.21       4 %
 
                         
 
                               
Combined wellhead ($/BOE)
  $ 60.39     $ 53.56     $ 6.83          
Combined hedges ($/BOE)
    (3.94 )     (5.28 )     1.34          
 
                         
Total combined oil and natural gas revenues ($/BOE)
  $ 56.45     $ 48.28     $ 8.17       17 %
 
                         
 
                               
Total production volumes:
                               
Oil (MBbls)
    2,509       1,816       693       38 %
Natural gas (MMcf)
    5,323       5,471       (148 )     -3 %
Combined (MBOE)
    3,396       2,728       668       24 %
 
                               
Average daily production volumes:
                               
Oil (Bbls/D)
    27,275       19,740       7,535       38 %
Natural gas (Mcf/D)
    57,857       59,463       (1,606 )     -3 %
Combined (BOE/D)
    36,917       29,651       7,266       25 %
 
                               
Average NYMEX prices:
                               
Oil (per Bbl)
  $ 75.21     $ 70.62     $ 4.59       6 %
Natural gas (per Mcf)
  $ 6.16     $ 6.58     $ (0.42 )     -6 %
     Oil revenues increased $59.8 million from $99.5 million in the third quarter of 2006 to $159.3 million in the third quarter of 2007. The increase is primarily due to an increase in oil production volumes of 693 MBbls, which contributed approximately $43.1 million in additional oil revenues. The increase in oil production volumes is primarily the result of our Big Horn Basin and Williston Basin acquisitions and our development programs.
     Our average realized oil price increased $8.68 per Bbl as a result of an increase in our wellhead price and a decrease in the effects of commodity derivative contracts included in oil revenues. Our higher average oil wellhead price increased oil revenues by $14.0 million, or $5.60 per Bbl, and the decrease in the effects of commodity derivative contracts, which were previously designated as hedges, increased oil revenues by $2.6 million, or $3.08 per Bbl. Our average oil wellhead price increased as a result of increases in the overall market price for oil, as reflected in the increase in the average NYMEX price from $70.62 per

27


Table of Contents

ENCORE ACQUISITION COMPANY
Bbl in the third quarter of 2006 to $75.21 per Bbl in the third quarter of 2007.
     Our oil wellhead revenue was reduced by $9.8 million and $7.1 million in the third quarter of 2007 and 2006, respectively, for the net profits interests payments related to our CCA properties.
     Natural gas revenues increased $0.3 million from $32.2 million in the third quarter of 2006 to $32.4 million in the third quarter of 2007. The increase is primarily due to an increase in our average realized natural gas price. Our average realized natural gas price increased $0.21 per Mcf as a result of an increase in our wellhead price, partially offset by an increase in the effects of commodity derivative contracts, which were previously designated as hedges, included in natural gas revenues. Our higher average natural gas wellhead price increased natural gas revenues by $2.8 million, or $0.52 per Mcf, while the increase in the effects of commodity derivative contracts reduced natural gas revenues by $1.6 million, or $0.31 per Mcf. Our average natural gas wellhead price increased as a result of the tightening of our natural gas differential despite decreases in the overall market price for natural gas, as reflected in the decrease in the average NYMEX price from $6.58 per Mcf in the third quarter of 2006 to $6.16 per Mcf in the third quarter of 2007.
     Production volumes decreased 148 MMcf, which reduced natural gas revenues by approximately $0.9 million. The decrease in natural gas production volumes is primarily the result of, 18,218 Mcf/D of natural gas production in the third quarter of 2006 associated with our Mid-Continent disposition, partially offset by production added through our development programs on the West Texas joint development agreement with ExxonMobil and in the Mid-Continent area.
     The table below illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices for the three months ended September 30, 2007 and 2006. Management uses the wellhead to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.
                 
    Three months ended September 30,
    2007   2006
Oil wellhead ($/Bbl)
  $ 67.80     $ 62.20  
Average NYMEX ($/Bbl)
  $ 75.21     $ 70.62  
Differential to NYMEX
  $ (7.41 )   $ (8.42 )
Oil wellhead to NYMEX percentage
    90 %     88 %
 
               
Natural gas wellhead ($/Mcf)
  $ 6.58     $ 6.06  
Average NYMEX ($/Mcf)
  $ 6.16     $ 6.58  
Differential to NYMEX
  $ 0.42     $ (0.52 )
Natural gas wellhead to NYMEX percentage
    107 %     92 %
     Our oil wellhead price as a percentage of the average NYMEX price tightened to 90 percent in the third quarter of 2007 as compared to 88 percent in the third quarter of 2006. We expect our oil wellhead differentials to remain approximately constant or to widen slightly in the fourth quarter of 2007 as compared to the third quarter of 2007 due to continued production increases from competing Canadian and Rocky Mountain producers, limited refining and pipeline capacity in the Rocky Mountain area, and corresponding steep pricing discounts.
     Our natural gas wellhead price as a percentage of the average NYMEX price improved to 107 percent in the third quarter of 2007 as compared to 92 percent in the third quarter of 2006. The differential improved because of efforts to reduce natural gas transportation and gathering costs. We expect our natural gas wellhead differentials to remain approximately constant or to widen slightly in the fourth quarter of 2007 as compared to the third quarter of 2007.
     Marketing revenues and expenses. In 2006 and in declining quantities during 2007, 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 assist us in marketing our production by decreasing our dependence on individual markets. These activities allow us to aggregate larger volumes, facilitate our efforts to maximize the prices we receive for production, provide for a greater allocation of future pipeline capacity in the event of curtailments, and enable us to reach other markets.
     In March 2007, we acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin 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.

28


Table of Contents

ENCORE ACQUISITION COMPANY
     The following table summarizes our marketing activities for the three months ended September 30, 2007 and 2006:
                 
    Three months ended September 30,  
    2007     2006  
    (in thousands, except per BOE amounts)  
Marketing revenues
  $ 3,282     $ 46,004  
Marketing expenses
    4,089       48,001  
 
           
 
               
Marketing, net
  $ (807 )   $ (1,997 )
 
           
 
               
Marketing revenues per BOE
  $ 0.97     $ 16.86  
Marketing expenses per BOE
    1.21       17.60  
 
           
 
               
Marketing, net per BOE
  $ (0.24 )   $ (0.74 )
 
           
     Expenses. The following table summarizes our expenses, excluding marketing expenses shown above, for the three months ended September 30, 2007 and 2006:
                                 
    Three months ended September 30,        
    2007     2006     Increase / (Decrease)  
Expenses (in thousands):
                               
Production:
                               
Lease operations
  $ 37,114     $ 24,478     $ 12,636          
Production, ad valorem, and severance taxes
    20,003       13,560       6,443          
 
                         
 
                               
Total production expenses
    57,117       38,038       19,079       50 %
Other:
                               
Depletion, depreciation, and amortization
    49,026       27,471       21,555          
Exploration
    8,920       12,322       (3,402 )        
General and administrative
    12,668       6,250       6,418          
Derivative fair value loss (gain)
    15,786       (33,363 )     49,149          
Other operating
    6,351       976       5,375          
 
                         
 
                               
Total operating
    149,868       51,694       98,174       190 %
Interest
    23,933       11,261       12,672          
Income tax provision
    8,986       25,069       (16,083 )        
 
                         
 
                               
Total expenses
  $ 182,787     $ 88,024     $ 94,763       108 %
 
                         
 
                               
Expenses (per BOE):
                               
Production:
                               
Lease operations
  $ 10.93     $ 8.97     $ 1.96          
Production, ad valorem, and severance taxes
    5.89       4.97       0.92          
 
                         
 
                               
Total production expenses
    16.82       13.94       2.88       21 %
Other:
                               
Depletion, depreciation, and amortization
    14.43       10.07       4.36          
Exploration
    2.63       4.52       (1.89 )        
General and administrative
    3.73       2.29       1.44          
Derivative fair value loss (gain)
    4.65       (12.23 )     16.88          
Other operating
    1.87       0.36       1.51          
 
                         
 
                               
Total operating
    44.13       18.95       25.18       133 %
Interest
    7.05       4.13       2.92          
Income tax provision
    2.65       9.19       (6.54 )        
 
                         
 
                               
Total expenses
  $ 53.83     $ 32.27     $ 21.56       67 %
 
                         

29


Table of Contents

ENCORE ACQUISITION COMPANY
     Production expenses. Total production expenses increased $19.1 million from $38.0 million in the third quarter of 2006 to $57.1 million in the third quarter of 2007. This increase resulted from an increase in total production volumes, as well as a $2.88 increase in production expenses per BOE. Our production margin (defined as oil and natural gas revenues less production expenses) for the third quarter of 2007 increased by $41.0 million (44 percent) to $134.6 million in the third quarter of 2007 as compared to $93.7 million in the third quarter of 2006. Total production expenses per BOE increased by 21 percent while total oil and natural gas revenues per BOE increased by only 17 percent. On a per BOE basis, our production margin increased 15 percent to $39.63 per BOE for the third quarter of 2007 as compared to $34.34 per BOE for the third quarter of 2006.
     The production expense attributable to lease operations expense (“LOE”) increased $12.6 million from $24.5 million in the third quarter of 2006 to $37.1 million in the third quarter of 2007, primarily as a result of an increase in production volumes, which contributed approximately $6.0 million of additional LOE, and an $1.96 increase in the average per BOE rate, which contributed approximately $6.6 million of additional LOE. The increase in production volumes is the result of our Big Horn Basin and Williston Basin acquisitions. The increase in our average LOE per BOE rate was attributable to:
    increases in prices paid to oilfield service companies and suppliers;
 
    increased operational activity to maximize production;
 
    HPAI expensed at the CCA; and
 
    higher salary levels for engineers and other technical professionals.
     The production expense attributable to production, ad valorem, and severance taxes (“production taxes”) increased $6.4 million from $13.6 million in the third quarter of 2006 to $20.0 million in the third quarter of 2007. The increase is due to higher wellhead revenues. As a percentage of oil and natural gas revenues (excluding the effects of commodity derivative contracts), production taxes increased to 9.8 percent in the third quarter of 2007 as compared to 9.3 percent in the third quarter of 2006 as a result of higher rates in the states where the properties associated with the Williston Basin acquisition are located. The effect of commodity derivative contracts is excluded from oil and natural gas revenues in the calculation of these percentages because this method more closely reflects the method used to calculate actual production taxes paid to taxing authorities.
     Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense increased $21.6 million from $27.5 million in the third quarter of 2006 to $49.0 million in the third quarter of 2007 due to an increase in the per BOE rate of $4.36 and increased production volumes. The increase in the per BOE rate was due to the higher cost basis of our recently acquired Big Horn Basin and Williston Basin properties, development of proved undeveloped reserves and higher finding, development, and acquisition costs resulting from increases in rig rates, oilfield services costs, and acquisition costs. These factors resulted in additional DD&A expense of approximately $14.8 million, while the increase in production volumes resulted in additional DD&A expense of approximately $6.7 million.
     Exploration expense. Exploration expense decreased $3.4 million from $12.3 million in the third quarter of 2006 to $8.9 million in the third quarter of 2007. During the third quarter of 2007, we expensed two exploratory dry holes totaling $5.7 million. During the third quarter of 2006, we expensed four exploratory dry holes totaling $10.0 million. However, impairment of unproved acreage in the third quarter of 2007 increased $1.0 million as compared to the third quarter of 2006 as we added additional leasehold costs and refined our estimated success rate in certain areas. The following table details our exploration expenses for the three months ended September 30, 2007 and 2006:
                         
    Three months ended September 30,     Increase /  
    2007     2006     (Decrease)  
    (in thousands)  
Dry holes
  $ 5,683     $ 9,962     $ (4,279 )
Geological and seismic
    153       222       (69 )
Delay rentals
    126       175       (49 )
Impairment of unproved acreage
    2,958       1,963       995  
 
                 
Total
  $ 8,920     $ 12,322     $ (3,402 )
 
                 
     General and administrative (“G&A”) expense. G&A expense increased $6.4 million from $6.3 million in the third quarter of 2006 to $12.7 million in the third quarter of 2007. The overall increase is primarily the result of $5.7 million of non-cash unit-based compensation related to ENP’s management incentive units.

30


Table of Contents

ENCORE ACQUISITION COMPANY
     Derivative fair value loss (gain). To increase clarity in our financial statements by accounting for all commodity derivative contracts under the same method, we elected to discontinue hedge accounting prospectively for all commodity derivative contracts beginning in July 2006. While this change has 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.
     During the third quarter of 2007, we recorded a $15.8 million derivative fair value loss as compared to a $33.4 million derivative fair value gain in the third quarter of 2006, the components of which were as follows:
                         
    Three months ended September 30,     Increase /  
    2007     2006     (Decrease)  
    (in thousands)  
Mark-to-market loss (gain) on commodity contracts
  $ 9,686     $ (37,729 )   $ 47,415  
Premium amortization
    10,462       3,449       7,013  
Settlements on commodity contracts
    (4,362 )     917       (5,279 )
 
                 
Total derivative fair value loss (gain)
  $ 15,786     $ (33,363 )   $ 49,149  
 
                 
     Other operating expense. Other operating expense increased $5.4 million from $1.0 million in the third quarter of 2006 to $6.4 million in the third quarter of 2007. The increase is primarily due to a $3.5 million loss on the sale of the Mid-Continent properties and increases in third-party transportation costs attributable to moving our CCA production into markets outside the immediate area of the production.
     Interest expense. Interest expense increased $12.7 million from $11.3 million in the third quarter of 2006 to $23.9 million the third quarter of 2007. The increase is primarily due to additional debt used to finance the Big Horn Basin and Williston Basin acquisitions. The weighted average interest rate for all long-term debt for the third quarter of 2007 was 7.1 percent as compared to 6.9 percent for the third quarter of 2006.
     The following table illustrates the components of interest expense for the three months ended September 30, 2007 and 2006:
                         
    Three months ended September 30,     Increase /  
    2007     2006     (Decrease)  
    (in thousands)  
6 1/4% Notes
  $ 2,427     $ 2,422     $ 5  
6% Notes
    4,631       4,624       7  
7 1/4% Notes
    2,747       2,745       2  
Revolving credit facilities
    13,186       550       12,636  
Other
    942       920       22  
 
                 
Total
  $ 23,933     $ 11,261     $ 12,672  
 
                 
     Minority interest. After ENP’s IPO in September 2007 and the underwriters’ over-allotment exercise in October 2007, public unitholders have a limited partner interest of approximately 40.2 percent. We include ENP in our consolidated financial statements and show the ownership by the public as a minority interest. The minority interest loss in ENP was $3.0 million for the third quarter of 2007.
     Income taxes. During the third quarter of 2007, we recorded an income tax provision of $9.0 million as compared to $25.1 million in the third quarter of 2006. Our effective tax rate increased to 42.9 percent in the third quarter of 2007 as compared to 37.3 percent in the third quarter of 2006 primarily due to a permanent rate adjustment for ENP’s management incentive units.

31


Table of Contents

ENCORE ACQUISITION COMPANY
Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006
     Oil and natural gas revenues and production. The following table illustrates the primary components of oil and natural gas revenues for the nine months ended September 30, 2007 and 2006, as well as each period’s respective oil and natural gas production volumes:
                                 
    Nine months ended September 30,        
    2007     2006     Increase / (Decrease)  
Revenues (in thousands):
                               
Oil wellhead
  $ 409,985     $ 306,833     $ 103,152          
Oil hedges
    (32,471 )     (38,767 )     6,296          
 
                         
Total oil revenues
  $ 377,514     $ 268,066     $ 109,448       41 %
 
                         
 
                               
Natural gas wellhead
  $ 118,267     $ 115,948     $ 2,319          
Natural gas hedges
    (7,719 )     (6,898 )     (821 )        
 
                         
Total natural gas revenues
  $ 110,548     $ 109,050     $ 1,498       1 %
 
                         
 
                               
Combined wellhead
  $ 528,252     $ 422,781     $ 105,471          
Combined hedges
    (40,190 )     (45,665 )     5,475          
 
                         
Total combined oil and natural gas revenues
  $ 488,062     $ 377,116     $ 110,946       29 %
 
                         
 
                               
Average realized prices:
                               
Oil wellhead ($/Bbl)
  $ 58.35     $ 55.85     $ 2.50          
Oil hedges ($/Bbl)
    (4.62 )     (7.06 )     2.44          
 
                         
Total oil revenues ($/Bbl)
  $ 53.73     $ 48.79     $ 4.94       10 %
 
                         
 
                               
Natural gas wellhead ($/Mcf)
  $ 6.44     $ 6.60     $ (0.16 )        
Natural gas hedges ($/Mcf)
    (0.42 )     (0.39 )     (0.03 )        
 
                         
Total natural gas revenues ($/Mcf)
  $ 6.02     $ 6.21     $ (0.19 )     -3 %
 
                         
 
                               
Combined wellhead ($/BOE)
  $ 52.37     $ 50.21     $ 2.16          
Combined hedges ($/BOE)
    (3.98 )     (5.42 )     1.44          
 
                         
Total combined oil and natural gas revenues ($/BOE)
  $ 48.39     $ 44.79     $ 3.60       8 %
 
                         
 
                               
Total production volumes:
                               
Oil (MBbls)
    7,027       5,494       1,533       28 %
Natural gas (MMcf)
    18,359       17,555       804       5 %
Combined (MBOE)
    10,086       8,420       1,666       20 %
 
                               
Average daily production volumes:
                               
Oil (Bbls/D)
    25,738       20,124       5,614       28 %
Natural gas (Mcf/D)
    67,249       64,304       2,945       5 %
Combined (BOE/D)
    36,946       30,842       6,104       20 %
 
                               
Average NYMEX prices:
                               
Oil (per Bbl)
  $ 66.21     $ 68.23     $ (2.02 )     -3 %
Natural gas (per Mcf)
  $ 6.83     $ 7.39     $ (0.56 )     -8 %
     Oil revenues increased $109.4 million from $268.1 million in the first nine months of 2006 to $377.5 million in the first nine months of 2007. The increase is primarily due to an increase in oil production volumes of 1,533 MBbls, which contributed approximately $85.6 million in additional oil revenues. The increase in oil production volumes is primarily the result of our Big Horn Basin and Williston Basin acquisitions and our development programs.
     Our average realized oil price increased $4.94 per Bbl as a result of an increase in our wellhead price and a decrease in the effects of commodity derivative contracts included in oil revenues. Our higher average oil wellhead price increased oil revenues by $17.6 million, or $2.50 per Bbl, and the decrease in the effects of commodity derivative contracts, which were previously designated as hedges, increased oil revenues by $6.3 million, or $2.44 per Bbl. Our average oil wellhead price increased as a result of the tightening of our oil differential despite decreases in the overall market price for oil, as reflected in the decrease in the average NYMEX price from $68.23 per Bbl in the first nine months of 2006 to $66.21 per Bbl in the first nine months of

32


Table of Contents

ENCORE ACQUISITION COMPANY
2007.
     Our oil wellhead revenue was reduced by $20.0 million and $19.2 million in the first nine months of 2007 and 2006, respectively, for the net profits interests payments related to our CCA properties.
     Natural gas revenues increased $1.5 million from $109.1 million for the first nine months of 2006 to $110.5 million for the first nine months of 2007. The increase is primarily due to an increase in production volumes of 804 MMcf, which contributed approximately $5.3 million in additional natural gas revenues. The increase in natural gas production volumes is the result of our West Texas joint development program with ExxonMobil and our development program in the Mid-Continent area, partially offset by natural gas production sold in conjunction with our Mid-Continent disposition. Our natural gas production volumes would have been 53,445 Mcf/D and 47,258 Mcf/D for the first nine months of 2007 and 2006, respectively, excluding volumes associated with our Mid-Continent disposition.
     Our average realized natural gas price decreased $0.19 per Mcf as a result of a decrease in our wellhead price and an increase in the effects of commodity derivative contracts included in natural gas revenues. Our lower average natural gas wellhead price reduced natural gas revenues by $3.0 million, or $0.16 per Mcf, and the increase in the effects of commodity derivative contracts, which were previously designated as hedges, reduced natural gas revenues by $0.8 million, or $0.03 per Mcf. Our average natural gas wellhead price decreased as a result of decreases in the overall market price for natural gas, as reflected in the decrease in the average NYMEX price from $7.39 per Mcf in the first nine months of 2006 to $6.83 per Mcf in the first nine months of 2007.
     The table below illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices for the nine months ended September 30, 2007 and 2006. Management uses the wellhead to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.
                 
    Nine months ended September 30,
    2007   2006
Oil wellhead ($/Bbl)
  $ 58.35     $ 55.85  
Average NYMEX ($/Bbl)
  $ 66.21     $ 68.23  
Differential to NYMEX
  $ (7.86 )   $ (12.38 )
Oil wellhead to NYMEX percentage
    88 %     82 %
 
               
Natural gas wellhead ($/Mcf)
  $ 6.44     $ 6.60  
Average NYMEX ($/Mcf)
  $ 6.83     $ 7.39  
Differential to NYMEX
  $ (0.39 )   $ (0.79 )
Natural gas wellhead to NYMEX percentage
    94 %     89 %
     Our oil wellhead price as a percentage of the average NYMEX price tightened to 88 percent in the first nine months of 2007 as compared to 82 percent in the first nine months of 2006.
     Our natural gas wellhead price as a percentage of the average NYMEX price tightened to 94 percent in the first nine months of 2007 as compared to 89 percent in the first nine months of 2006.
     Marketing revenues and expenses. The following table summarizes our marketing activities for the nine months ended September 30, 2007 and 2006:

33


Table of Contents

ENCORE ACQUISITION COMPANY
                 
    Nine months ended September 30,  
    2007     2006  
    (in thousands, except per BOE amounts)  
Marketing revenues
  $ 27,139     $ 106,036  
Marketing expenses
    27,607       105,661  
 
           
 
               
Marketing, net
  $ (468 )   $ 375  
 
           
 
               
Marketing revenues per BOE
  $ 2.69     $ 12.59  
Marketing expenses per BOE
    2.74       12.55  
 
           
 
               
Marketing, net per BOE
  $ (0.05 )   $ 0.04  
 
           
     Expenses. The following table summarizes our expenses, excluding marketing expenses shown above, for the nine months ended September 30, 2007 and 2006:
                                 
    Nine months ended September 30,     Increase / (Decrease)  
    2007     2006                  
Expenses (in thousands):
                               
Production:
                               
Lease operations
  $ 105,186     $ 70,332     $ 34,854          
Production, ad valorem, and severance taxes
    51,750       38,382       13,368          
 
                         
 
                               
Total production expenses
    156,936       108,714       48,222       44 %
Other:
                               
Depletion, depreciation, and amortization
    136,372       82,479       53,893          
Exploration
    23,856       18,347       5,509          
General and administrative
    26,216       18,199       8,017          
Derivative fair value loss (gain)
    68,166       (20,263 )     88,429          
Other operating
    13,667       3,573       10,094          
 
                         
 
                               
Total operating
    425,213       211,049       214,164       101 %
Interest
    68,040       33,766       34,274          
Income tax provision
    1,490       51,382       (49,892 )        
 
                         
 
                               
Total expenses
  $ 494,743     $ 296,197     $ 198,546       67 %
 
                         
 
                               
Expenses (per BOE):
                               
Production:
                               
Lease operations
  $ 10.43     $ 8.35     $ 2.08          
Production, ad valorem, and severance taxes
    5.13       4.56       0.57          
 
                         
 
                               
Total production expenses
    15.56       12.91       2.65       21 %
Other:
                               
Depletion, depreciation, and amortization
    13.52       9.80       3.72          
Exploration
    2.37       2.18       0.19          
General and administrative
    2.60       2.16       0.44          
Derivative fair value loss (gain)
    6.76       (2.41 )     9.17          
Other operating
    1.35       0.42       0.93          
 
                         
 
                               
Total operating
    42.16       25.06       17.10       68 %
Interest
    6.75       4.01       2.74          
Income tax provision
    0.15       6.10       (5.95 )        
 
                         
 
                               
Total expenses
  $ 49.06     $ 35.17     $ 13.89       39 %
 
                         
     Production expenses. Total production expenses increased $48.2 million from $108.7 million in the first nine months of 2006 to $156.9 million in the first nine months of 2007. This increase resulted from an increase in total production volumes, as

34


Table of Contents

ENCORE ACQUISITION COMPANY
well as a $2.65 increase in production expenses per BOE. Our production margin for the first nine months of 2007 increased by $62.7 million (23 percent) to $331.1 million in the first nine months of 2007 as compared to $268.4 million for the first nine months of 2006. Total production expenses per BOE increased by 21 percent while total oil and natural gas revenues per BOE increased by only eight percent. On a per BOE basis, our production margin increased three percent to $32.83 per BOE for the first nine months of 2007 as compared to $31.88 per BOE for the first nine months of 2006.
     The production expense attributable to LOE increased $34.9 million from $70.3 million in the first nine months of 2006 to $105.2 million in the first nine months of 2007, primarily as a result of an $2.08 increase in the average per BOE rate, which contributed approximately $20.9 million of additional LOE, and an increase in production volumes, which contributed approximately $13.9 million of additional LOE. The increase in production volumes is the result of our Big Horn Basin and Williston Basin acquisitions. The increase in our average LOE per BOE rate was attributable to:
    increases in prices paid to oilfield service companies and suppliers;
 
    increased operational activity to maximize production;
 
    HPAI expensed at the CCA; and
 
    higher salary levels for engineers and other technical professionals.
     The production expense attributable to production taxes increased $13.4 million from $38.4 million for the first nine months of 2006 to $51.8 million for the first nine months of 2007. The increase is due to higher wellhead revenues. As a percentage of oil and natural gas revenues (excluding the effects of commodity derivative contracts), production taxes increased to 9.8 percent in the first nine months of 2007 as compared to 9.1 percent in the first nine months of 2006 as a result of higher rates in the states where the properties associated with the Big Horn Basin and Williston Basin acquisitions are located.
     DD&A expense. DD&A expense increased $53.9 million from $82.5 million for the first nine months of 2006 to $136.4 million for the first nine months of 2007 due to an increase in the per BOE rate of $3.72 and increased production volumes. The per BOE rate increased due to the higher cost basis of our recently acquired Big Horn Basin and Williston Basin properties, development of proved undeveloped reserves and higher finding, development, and acquisition costs resulting from increases in rig rates, oilfield services costs, and acquisition costs. These factors resulted in additional DD&A expense of approximately $37.6 million, while the increase in production volumes resulted in additional DD&A expense of approximately $16.3 million.
     Exploration expense. Exploration expense increased $5.5 million from $18.3 million in the first nine months of 2006 to $23.9 million in the first nine months of 2007. During the first nine months of 2007, we expensed five exploratory dry holes totaling $14.7 million. During the first nine months of 2006, we expensed 11 exploratory dry holes totaling $12.5 million. In addition, impairment of unproved acreage in the first nine months of 2007 increased $4.0 million as compared to the first nine months of 2006 as we added additional leasehold costs and refined our estimated success rate in certain areas. The following table details our exploration expenses for the nine months ended September 30, 2007 and 2006:
                         
    Nine months ended September 30,     Increase /  
    2007     2006     (Decrease)  
    (in thousands)  
Dry holes
  $ 14,703     $ 12,542     $ 2,161  
Geological and seismic
    878       1,474       (596 )
Delay rentals
    467       530       (63 )
Impairment of unproved acreage
    7,808       3,801       4,007  
 
                 
Total
  $ 23,856     $ 18,347     $ 5,509  
 
                 
     G&A expense. G&A expense increased $8.0 million from $18.2 million in the first nine months of 2006 to $26.2 million in the first nine months of 2007. The overall increase is primarily the result of $5.7 million of non-cash unit-based compensation related to ENP’s management incentive units, increased staffing to manage our larger asset base, higher activity levels, and increased personnel costs due to intense competition for human resources within the industry.
     Derivative fair value loss (gain). During the first nine months of 2007, we recorded a $68.2 million derivative fair value loss as compared to a derivative fair value gain of $20.3 million in the first nine months of 2006, the components of which were as follows:

35


Table of Contents

ENCORE ACQUISITION COMPANY
                         
    Nine months ended September 30,     Increase /  
    2007     2006     (Decrease)  
    (in thousands)  
Ineffectiveness on designated cash flow hedges
  $     $ 1,748     $ (1,748 )
Mark-to-market loss (gain) on commodity contracts
    56,122       (30,639 )     86,761  
Premium amortization
    28,151       9,820       18,331  
Settlements on commodity contracts
    (16,107 )     (1,192 )     (14,915 )
 
                 
Total derivative fair value loss (gain)
  $ 68,166     $ (20,263 )   $ 88,429  
 
                 
     Other operating expense. Other operating expense increased $10.1 million from $3.6 million in the first nine months of 2006 to $13.7 million in the first nine months of 2007. The increase is primarily due to a $5.8 million loss on the sale of the Mid-Continent properties and increases in third-party transportation costs attributable to moving our CCA production into markets outside the immediate area of the production.
     Interest expense. Interest expense increased $34.3 million from $33.8 million in the first nine months of 2006 to $68.0 million in the first nine months of 2007. The increase is primarily due to additional debt used to finance the Big Horn Basin and Williston Basin acquisitions. The weighted average interest rate for all long-term debt for the first nine months of 2007 was 7.0 percent as compared to 6.7 percent for the first nine months of 2006.
     The following table illustrates the components of interest expense for the nine months ended September 30, 2007 and 2006:
                         
    Nine months ended September 30,     Increase /  
    2007     2006     (Decrease)  
          (in thousands)        
6 1/4% Notes
  $ 7,277     $ 7,262     $ 15  
6% Notes
    13,886       13,795       91  
7 1/4% Notes
    8,240       8,238       2  
Revolving credit facilities
    36,208       2,773       33,435  
Other
    2,429       1,698       731  
 
                 
Total
  $ 68,040     $ 33,766     $ 34,274  
 
                 
     Minority interest. After ENP’s IPO in September 2007 and the underwriters’ over-allotment exercise in October 2007, public unitholders have a limited partner interest of approximately 40.2 percent. We include ENP in our consolidated financial statements and show the ownership by the public as a minority interest. The minority interest loss in ENP was $3.0 million for the first nine months of 2007.
     Income taxes. During the first nine months 2007, we recorded an income tax provision of $1.5 million as compared to an income tax provision of $51.4 million in the first nine months of 2006. Our effective tax rate increased to 45.2 percent in the first nine months of 2007 as compared to 38.4 percent in the first nine months of 2006 primarily due to a permanent rate adjustment for ENP’s management incentive units and a state rate adjustment due to larger apportionment of future taxable income to states with higher tax rates, partially offset by a benefit for the true-up to actual tax expense for the filing of our 2006 consolidated tax returns.
     On January 1, 2007, we adopted the provisions of FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We have performed an evaluation of tax positions and have determined that the adoption of FIN 48 did not have a material impact on our financial condition, results of operations, or cash flows.
Capital Resources
     Our primary capital resources are as follows:
    Cash flows from operating activities; and
 
    Cash flows from financing activities.

36


Table of Contents

ENCORE ACQUISITION COMPANY
     Cash flows from operating activities. Cash provided by operating activities decreased $20.7 million from $234.4 million for the first nine months of 2006 to $213.6 million for the first nine months of 2007. The decrease was primarily due to an increase in our net derivative liabilities as a result of increases in our commodity derivative positions and the forward price curve, and an increase in accounts receivable as a result of increased oil and natural gas sales, partially offset by an increase in our production margin.
     Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt and net proceeds received from the sale of additional equity. We periodically draw on our revolving credit facilities to fund acquisitions and other capital commitments. Historically, we have repaid large balances on our revolving credit facilities with proceeds from the issuance of senior subordinated notes in order to extend the maturity date of the debt and fix the interest rate.
     During the first nine months of 2007, we received net cash of $627.2 million from financing activities, including net borrowings on our revolving credit facilities of $463.9 million and net proceeds of $171.2 million from ENP’s issuance of 9,000,000 common units in its IPO. Our net borrowings on our revolving credit facilities resulted in a net increase in outstanding borrowings under our revolving credit facilities from $68 million at December 31, 2006 to $545 million at September 30, 2007, primarily due to borrowings used to finance the Big Horn Basin and Williston Basin acquisitions, which were partially offset by repayments from the net proceeds received from the Mid-Continent disposition and ENP’s IPO.
     During the first nine months of 2006, we received net cash of $41.8 million from financing activities. This consisted primarily of net proceeds of $127.1 million from the issuance of 4,000,000 shares of our common stock in April 2006, which was used to reduce outstanding borrowings under our revolving credit facility, invest in oil and natural gas activities, and to pay general corporate expenses.
     Current capitalization. At September 30, 2007, we had total assets of $2.7 billion and total capitalization of $2.0 billion, of which 42 percent was represented by stockholders’ equity and 58 percent by long-term debt. At December 31, 2006, we had total assets of $2.0 billion and total capitalization of $1.5 billion, of which 55 percent was represented by stockholders’ equity and 45 percent by long-term debt. The percentages of our capitalization represented by stockholders’ equity and long-term debt could vary in the future if debt is used to finance future capital projects or potential acquisitions.
Capital Commitments and Contingencies
     Our primary needs for cash are as follows:
    Cash flows from investing activities including:
    Development, exploitation, and exploration of existing oil and natural gas properties; and
 
    Acquisitions of oil and natural gas properties and leasehold acreage;
    Funding of necessary working capital; and
 
    Contractual obligations.
     Cash flows from investing activities. Cash used in investing activities increased $555.9 million from $277.3 million in the first nine months of 2006 to $833.2 million in the first nine months of 2007. The increase was primarily due to a $817.1 million increase in amounts paid for the acquisition of oil and natural gas properties, namely our Big Horn Basin and Williston Basin acquisitions, partially offset by a $290.7 million increase in amounts received for the disposition of oil and natural gas properties, primarily due to the Mid-Continent disposition.
     Development, exploitation, and exploration of existing oil and natural gas properties. The following table summarizes our costs incurred (excluding asset retirement obligations) related to development, exploitation, and exploration activities during the three and nine months ended September 30, 2007 and 2006:

37


Table of Contents

ENCORE ACQUISITION COMPANY
                                 
    Three months ended September 30,     Nine months ended September 30,  
    2007     2006     2007     2006  
            (in thousands)          
Development and exploitation
  $ 49,291     $ 63,499     $ 185,812     $ 159,394  
Exploration
    27,424       27,289       77,647       65,922  
HPAI
    1,252       4,454       3,248       18,913  
 
                       
Total
  $ 77,967     $ 95,242     $ 266,707     $ 244,229  
 
                       
     Development and exploitation. Our expenditures for development and exploitation investments primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for the third quarter of 2007 included a total of 35 gross (10.1 net) successful wells and one gross (0.9 net) development dry holes. Our development and exploitation capital for the first nine months of 2007 included a total of 123 gross (46.2 net) successful wells and three gross and (2.3 net) development dry holes.
     We currently have eight operated rigs drilling on the onshore continental United States with one rig in the Mid-Continent, one rig in the Northern region, one rig in the New Mexico region, and five rigs in West Texas.
     Exploration. Our expenditures for exploration investments primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. In the third quarter of 2007, our exploration capital yielded 14 gross (5.4 net) successful wells and two gross (1.1 net) exploratory dry holes. During the first nine months of 2007, our exploration capital yielded 42 gross (15.8 net) exploratory wells that were productive and five gross (2.6 net) exploratory dry holes.
     HPAI. During the third quarter of 2007 and 2006, we invested $1.3 million and $4.5 million on our HPAI programs. For the first nine months of 2007 and 2006, we invested $3.2 million and $18.9 million on our HPAI programs.
     Acquisitions of oil and natural gas properties and leasehold acreage. The following table summarizes our costs incurred (excluding asset retirement obligations) for oil and natural gas property acquisitions during the three and nine months ended September 30, 2007 and 2006:
                                 
    Three months ended September 30,     Nine months ended September 30,  
    2007     2006     2007     2006  
            (in thousands)          
Acquisitions of proved property
  $ 30,079     $ 263     $ 791,964     $ 4,315  
Acquisitions of leasehold acreage
    16,832       6,629       40,615       18,494  
 
                       
Total
  $ 46,911     $ 6,892     $ 832,579     $ 22,809  
 
                       
     Acquisitions. On March 7, 2007, we acquired oil and natural gas properties in the Big Horn Basin for a purchase price of approximately $393.2 million, including $1.3 million of estimated transaction costs. On April 11, 2007, we acquired oil and natural gas properties in the Williston Basin for a purchase price of approximately $392.0 million, including $1.3 million of estimated transaction costs. The total purchase price of these acquisitions allocated to proved properties was $779.3 million.
     Leasehold acreage costs. During the three and nine months ended September 30, 2007, our capital expenditures for leasehold acreage totaled $16.8 million and $40.6 million, respectively. During the third quarter of 2007, our capital expenditures for leasehold acreage related to the acquisition of unproved acreage in various areas. During the first nine months of 2007, $16.1 million related to the Williston Basin acquisition and the remainder related to the acquisition of unproved acreage in various areas. During the three and nine months ended September 30, 2006, our capital expenditures for leasehold acreage totaled $6.6 million and $18.5 million, respectively, all of which related to the acquisition of unproved acreage in various areas.
     Funding of necessary working capital. At September 30, 2007, our working capital (defined as total current assets less total current liabilities) was negative $12.9 million while at December 31, 2006 our working capital was negative $40.7 million, an improvement of $27.8 million. The improvement is primarily attributable to an increase in accounts receivable as a result of increased oil and natural gas sales.
     For the remainder of 2007, we expect working capital to remain negative. Negative working capital is expected mainly due to fair values of our commodity derivative contracts (the settlements of which will be offset by cash flows from the sale of

38


Table of Contents

ENCORE ACQUISITION COMPANY
production mitigated against price risk under those contracts) and deferred commodity derivative contract premiums. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and pay down any outstanding borrowings under our revolving credit facilities. We do not plan to pay cash dividends in the foreseeable future. Our production volumes and the overall 2007 commodity prices and our related 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. Assuming moderate to high commodity prices and constant or increasing production volumes, our operating cash flow should remain positive in 2007.
     The Board has approved a capital budget of approximately $385 million for 2007. The level of these and other future expenditures is 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, cash on hand, and borrowings under our revolving credit facilities.
     Contractual obligations. The following table illustrates our contractual obligations and commercial commitments outstanding at September 30, 2007:
                                         
    Payments Due by Period  
            Quarter Ended     Years Ended     Years Ended        
Contractual Obligations           December 31,     December 31,     December 31,        
and Commitments   Total     2007     2008 — 2009     2010 — 2011     Thereafter  
    (in thousands)  
6 1/4% Notes (a)
  $ 215,626     $ 4,688     $ 18,750     $ 18,750     $ 173,438  
6% Notes (a)
    444,000             36,000       36,000       372,000  
7 1/4% Notes (a)
    264,188       5,438       21,750       21,750       215,250  
Revolving credit facilities (a)
    722,841       19,054       76,218       76,218       551,351  
Derivative obligations (b)
    63,910       17,859       45,170       881        
Development commitments (c)
    105,912       55,533       50,379              
Operating leases and commitments (d)
    14,552       738       5,348       4,569       3,897  
Asset retirement obligations (e)
    156,371       358       2,862       2,862       150,289  
 
                             
Total
  $ 1,987,400     $ 103,668     $ 256,477     $ 161,030     $ 1,466,225  
 
                             
 
(a)   Amounts included in the table above include both principal and projected interest payments. Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.
 
(b)   Derivative obligations represent net liabilities for derivatives that were valued as of September 30, 2007. With the exception of $48.6 million of deferred premiums on derivative contracts, the ultimate settlement amounts of the remaining portions of our derivative obligations are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our derivative obligations.
 
(c)   Development commitments include: authorized purchases for work in process of $38.8 million; future minimum payments for drilling rig operations of $60.1 million; and $7.0 million for minimum capital obligations associated with the remaining seven commitment wells to be drilled under the ExxonMobil joint development agreement. Also at September 30, 2007, we had $181.3 million of authorized purchases not placed to vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and expected to be made unless circumstances change.
 
(d)   Operating leases and commitments include office space and equipment obligations that have non-cancelable lease terms in excess of one year of $13.0 million and future minimum payments for other operating commitments of $1.6 million.
 
(e)   Asset retirement obligations represent the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the completion of field life. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our asset retirement obligations.
     Other contingencies and commitments. In order to facilitate ongoing sales of our oil production in the CCA, we ship a portion of our production in pipelines downstream and sell to purchasers at major U.S. market hubs. From time to time, shipping delays, purchaser stipulations, or other conditions may require that we sell our oil production in periods subsequent to the period in which it is produced. In such case, the deferred sale would have an adverse effect in the period of production on reported production volumes, oil and natural gas revenues, and costs as measured on a unit-of-production basis.
     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 Enbridge Pipeline to the Clearbrook, Minnesota hub. In addition, new markets to the west have been identified and a portion of our crude oil is being moved that direction through the Rocky Mountain

39


Table of Contents

ENCORE ACQUISITION COMPANY
Pipeline. To a lesser extent, our production also depends on transportation through Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on Platte Pipeline are currently oversubscribed and have been subject to apportionment since December 2005, we were allocated transportation effective January 1, 2007. However, further restrictions on available capacity to transport oil through any of the above mentioned pipelines, or 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.
     We expect the differential between the NYMEX price of crude oil and the wellhead price we receive to remain approximately constant or to widen slightly in the fourth quarter of 2007 as compared to the third quarter of 2007. 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 gradually widened this differential. We cannot accurately predict crude oil differentials. Natural gas differentials are expected to remain approximately constant or to slightly widen in the fourth quarter of 2007 as compared to the third quarter of 2007. Increases in the 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.
Liquidity
     Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under the EAC Credit Agreement. We also have the ability to adjust our level of capital expenditures. We may use other sources of capital, including the issuance of additional debt or equity securities, to fund any major acquisitions we might secure in the future and to maintain our financial flexibility.
     Internally generated cash flows. Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. Realized oil and natural gas prices for the first nine months 2007 increased by 10 percent and decreased by three percent, respectively, as compared to the first nine months of 2006. These prices have historically fluctuated widely in response to changing market forces. For the first nine months of 2007, approximately 70 percent of our production was oil. As we previously discussed, our oil wellhead differentials during the first nine months of 2007 tightened as compared to the first nine months of 2006, favorably impacting the amount of oil revenues we received on our oil production. We expect our oil and natural gas wellhead differentials to remain approximately constant or to widen slightly in the fourth quarter of 2007 as compared to the third quarter of 2007. To the extent oil and natural gas prices decline or we experience significant widening of our wellhead differentials, our earnings, cash flows from operations, and availability under our revolving credit facilities may be adversely impacted. Prolonged periods of low oil and natural gas prices or sustained wider than historical wellhead differentials could cause us to not be in compliance with financial covenants under our revolving credit facilities and thereby affect our liquidity. We believe that our internally generated cash flows and unused availability under our revolving credit facilities are sufficient to fund our planned capital expenditures for the foreseeable future.
     Revolving credit facilities. Our principal source of short-term liquidity is the EAC Credit Agreement, which matures on March 7, 2012.
     On March 7, 2007, we entered into the EAC Credit Agreement with a bank syndicate comprised of Bank of America, N.A. and other lenders. The EAC Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of August 19, 2004, as amended. The borrowing base is redetermined semi-annually and upon requested special redeterminations and may be increased or decreased, up to a maximum of $1.25 billion. The borrowing base on September 30, 2007 was $870 million.
     Also on March 7, 2007, OLLC entered into the OLLC Credit Agreement with a bank syndicate comprised of Bank of America, N.A. and other lenders. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries. The borrowing base is redetermined semi-annually and upon requested special redeterminations and may be increased or decreased, up to a maximum of $300 million. The borrowing base on September 30, 2007 was $145 million. Amounts borrowed under the OLLC Credit Agreement may only be used to fund the operations of ENP.
     On September 30, 2007 and October 31, 2007, EAC had $478.5 million and $483 million outstanding, respectively, and $371.5 million $367 million available to borrow, respectively, under the EAC Credit Agreement. On September 30, 2007 and October 31, 2007, ENP had $66.5 million and $60 million outstanding, respectively, and $78.5 million $84.9 million available to

40


Table of Contents

ENCORE ACQUISITION COMPANY
borrow, respectively, under the EAC Credit Agreement. Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our revolving credit facilities.
     Debt covenants. At September 30, 2007, we were in compliance with all of our debt covenants.
     Letters of credit. As of September 30, 2007 and October 31, 2007, EAC had $20 million in outstanding letters of credit, all of which related to its ExxonMobil joint development agreement. As of September 30, 2007 and October 31, 2007, ENP had none and $0.1 million in outstanding letters of credit, respectively.
Critical Accounting Policies and Estimates
     On January 1, 2007, we adopted the provisions of FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. See Note 9 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for more information.
     Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our 2006 Annual Report on Form 10-K for more information.
New Accounting Pronouncements
     The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”
Item 3. Quantitative and Qualitative Disclosures About Market Risk
     The information included in “Quantitative and Qualitative Disclosures about Market Risk” in our 2006 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.
Commodity Price Sensitivity
     Our outstanding commodity derivative contracts as of September 30, 2007 are discussed in Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of September 30, 2007, the fair market value of our oil and natural gas derivative contracts was a net asset of $7.7 million and $7.6 million, respectively. Based on our open commodity derivative positions at September 30, 2007, a $1.00 increase in the respective NYMEX prices for oil and natural gas would decrease our net derivative fair value asset by approximately $8.4 million, while a $1.00 decrease in the respective NYMEX prices for oil and natural gas would increase our net derivative fair value assets by approximately $10.7 million.
Interest Rate Sensitivity
     At September 30, 2007, we had total long-term debt of $1.1 billion, which is recorded net of discount of $5.9 million. Of this amount, $150 million bears interest at a fixed rate of 6 1/4 percent, $300 million bears interest at a fixed rate of 6 percent, and $150 million bears interest at a fixed rate of 7 1/4 percent. The remaining outstanding long-term debt balance of $545 million is under our revolving credit facilities and is subject to floating market rates of interest that are linked to LIBOR.
     At this level of floating rate debt, if LIBOR increased one percent, we would incur an additional $5.5 million of interest expense per year, and if the rate decreased one percent, we would incur $5.5 million less. Additionally, if LIBOR increased one percent, we estimate the fair value of our fixed rate debt at September 30, 2007 would decrease from $535.3 million to $501.2 million, and if the rate decreased one percent, we estimate the fair value would increase to $572.4 million.
Item 4. Controls and Procedures
     In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief

41


Table of Contents

ENCORE ACQUISITION COMPANY
Financial Officer, of the effectiveness of our disclosure controls and procedures as of September 30, 2007. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2007 to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
     There were no changes in our internal control over financial reporting that occurred during the third quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. 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 us.
Item 1A. Risk Factors
     In addition to the other information set forth in this Report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2006 Annual Report on Form 10-K, which could materially affect our business, financial condition, and/or future results. The risks described in our 2006 Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.
Item 6. Exhibits
     
Exhibits    
 
   
3.1
  Second Amended and Restated Certificate of Incorporation of Encore Acquisition Company (incorporated by reference from EAC’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, filed with the SEC on November 7, 2001).
 
   
3.1.2
  Certificate of Amendment to Second Amended and Restated Certificate of Incorporation of Encore Acquisition Company (incorporated by reference from EAC’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, filed with the SEC on May 5, 2005).
 
   
3.2
  Second Amended and Restated Bylaws of Encore Acquisition Company (incorporated by reference from EAC’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, filed with the SEC on November 7, 2001).
 
   
10.1
  First Amendment to Credit Agreement, dated August 22, 2007, by and among Encore Energy Partners Operating LLC, Encore Energy Partners LP, Bank of America, N.A., as administrative agent and L/C Issuer, Banc of America Securities LLC, as sole lead arranger and sole book manager and other lenders (incorporated by reference from Exhibit 10.1 to EAC’s Current Report on Form 8-K, filed with the SEC on August 28, 2007).
 
   
10.2
  Contribution, Conveyance and Assumption Agreement, dated as of September 17, 2007, by and among Encore Energy Partners LP, Encore Energy Partners GP LLC, Encore Acquisition Company, Encore Operating, L.P., Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and Encore Energy Partners Operating LLC (incorporated by reference from Exhibit 10.1 to EAC’s Current Report on Form 8-K, filed with the SEC on September 21, 2007).
 
   
10.3
  Amended and Restated Administrative Services Agreement, dated as of September 17, 2007, by and among Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Energy Partners Operating LLC, Encore Acquisition Company and Encore Operating, L.P. (incorporated by reference from Exhibit 10.2 to EAC’s Current Report on Form 8-K, filed with the SEC on September 21, 2007).
 
   
31.1*
  Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer).
 
   
31.2*
  Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer).
 
   
32.1*
  Section 1350 Certification (Principal Executive Officer).
 
   
32.2*
  Section 1350 Certification (Principal Financial Officer).
 
   
99.1*
  Statement showing computation of ratios of earnings to fixed charges.
 
*   Filed herewith.

42


Table of Contents

ENCORE ACQUISITION COMPANY
SIGNATURE
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  ENCORE ACQUISITION COMPANY
 
 
Date: November 6, 2007  /s/ Robert C. Reeves    
  Robert C. Reeves   
  Senior Vice President, Chief Financial Officer, and Treasurer   
 

43