e10vq
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

(Mark One)

[ x ] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2004
or
[   ] 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 1-16295

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)
         
Delaware   001-16295   75-2759650
(State or other jurisdiction   (Commission   (IRS Employer
of incorporation)   File Number)   Identification No.)
     
777 Main Street, Suite 1400, Fort Worth, Texas   76102
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (817) 877-9955

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 [ x ] No [   ]

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2)

Yes [ x ] No [   ]
         
Number of shares of Common Stock, $0.01 par value, outstanding as of July 23, 2004 ..................................................................
    32,559,782  

 


ENCORE ACQUISITION COMPANY
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 Rule 13a-14(a)/15d-14(a) Certification
 Rule 13a-14(a)/15d-14(a) Certification
 Section 1350 Certification
 Section 1350 Certification

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands except shares and per share amounts)
                 
    June 30,   December 31,
    2004
  2003
    (unaudited)        
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 2,791     $ 431  
Accounts receivable
    36,950       27,640  
Inventory
    8,992       6,019  
Derivatives
    3,175       5,588  
Deferred taxes
    5,439       3,592  
Other current
    3,919       1,673  
 
   
 
     
 
 
Total current assets
    61,266       44,943  
 
   
 
     
 
 
Properties and equipment, at cost — successful efforts method:
               
Proved properties
    1,021,181       739,288  
Unproved properties
    10,478       921  
Accumulated depletion, depreciation, and amortization
    (144,282 )     (124,646 )
 
   
 
     
 
 
 
    887,377       615,563  
 
   
 
     
 
 
Other property and equipment
    9,200       3,831  
Accumulated depreciation
    (2,983 )     (2,586 )
 
   
 
     
 
 
 
    6,217       1,245  
 
   
 
     
 
 
Goodwill
    38,623        
Debt issuance costs
    8,632       5,304  
Other assets
    7,557       5,083  
 
   
 
     
 
 
Total assets
  $ 1,009,672     $ 672,138  
 
   
 
     
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 14,966     $ 10,668  
Derivatives
    19,997       8,026  
Accrued and other current
    33,453       26,301  
 
   
 
     
 
 
Total current liabilities
    68,416       44,995  
 
   
 
     
 
 
Derivatives
    19,290       3,514  
Future abandonment costs
    6,559       5,341  
Deferred taxes
    130,256       80,313  
Long-term debt
    353,000       179,000  
 
   
 
     
 
 
Total liabilities
    577,521       313,163  
 
   
 
     
 
 
Commitments and contingencies
           
Stockholders’ equity:
               
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding
           
Common stock, $.01 par value, 60,000,000 authorized, 32,559,842 and 30,335,693 issued and outstanding
    326       303  
Additional paid-in capital
    312,267       253,865  
Deferred compensation
    (5,359 )     (2,528 )
Retained earnings
    152,258       117,365  
Accumulated other comprehensive income
    (27,341 )     (10,030 )
 
   
 
     
 
 
Total stockholders’ equity
    432,151       358,975  
 
   
 
     
 
 
Total liabilities and stockholders’ equity
  $ 1,009,672     $ 672,138  
 
   
 
     
 
 

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

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ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands except per share amounts)
(unaudited)
                                 
    Three months ended   Six months ended
    June 30,
  June 30,
    2004
  2003
  2004
  2003
Revenues:
                               
Oil
  $ 52,885     $ 40,704     $ 99,649     $ 87,136  
Natural gas
    17,237       10,539       29,764       19,894  
 
   
 
     
 
     
 
     
 
 
Total revenues
    70,122       51,243       129,413       107,030  
 
   
 
     
 
     
 
     
 
 
Expenses:
                               
Production —
                               
Lease operations
    10,921       9,140       21,163       18,093  
Production, ad valorem, and severance taxes
    7,161       5,095       13,000       11,264  
Depletion, depreciation, and amortization
    11,249       7,703       20,512       15,486  
Exploration
    1,697             1,697        
General and administrative (excluding non-cash stock based compensation)
    2,530       2,340       4,758       4,790  
Non-cash stock based compensation
    307       150       617       295  
Derivative fair value (gain) loss
    965       (576 )     1,123       (1,836 )
Other operating
    1,091       712       2,093       882  
 
   
 
     
 
     
 
     
 
 
Total expenses
    35,921       24,564       64,963       48,974  
 
   
 
     
 
     
 
     
 
 
Operating income
    34,201       26,679       64,450       58,056  
 
   
 
     
 
     
 
     
 
 
Other income (expenses):
                               
Interest
    (6,308 )     (4,039 )     (10,214 )     (8,210 )
Other
    106       39       157       86  
 
   
 
     
 
     
 
     
 
 
Total other income (expenses)
    (6,202 )     (4,000 )     (10,057 )     (8,124 )
 
   
 
     
 
     
 
     
 
 
Income before income taxes and cumulative effect of accounting change
    27,999       22,679       54,393       49,932  
Current income tax provision
    (919 )     (591 )     (2,004 )     (1,358 )
Deferred income tax provision
    (9,089 )     (7,855 )     (17,496 )     (17,226 )
 
   
 
     
 
     
 
     
 
 
Income before cumulative effect of accounting change
    17,991       14,233       34,893       31,348  
Cumulative effect of accounting change, net of income taxes of $529
                      863  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 17,991     $ 14,233     $ 34,893     $ 32,211  
 
   
 
     
 
     
 
     
 
 
Income before cumulative effect of accounting change per common share:
                               
Basic
  $ 0.59     $ 0.47     $ 1.15     $ 1.04  
Diluted
    0.58       0.47       1.13       1.04  
Net income per common share:
                               
Basic
  $ 0.59     $ 0.47     $ 1.15     $ 1.07  
Diluted
    0.58       0.47       1.13       1.06  
Weighted average common shares outstanding:
                               
Basic
    30,726       30,089       30,456       30,063  
Diluted
    31,120       30,284       30,847       30,253  

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

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ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

June 30, 2004
(in thousands)
(unaudited)
                                                 
                                    Accumulated    
            Additional                   Other   Total
    Common   Paid-In   Deferred   Retained   Comprehensive   Stockholders’
    Stock
  Capital
  Compensation
  Earnings
  Income
  Equity
Balance at December 31, 2003
  $ 303     $ 253,865     $ (2,528 )   $ 117,365     $ (10,030 )   $ 358,975  
Exercise of stock options
    1       1,880                         1,881  
Issuance of common stock
    20       53,076                         53,096  
Deferred compensation:
                                               
Issuance of restricted common stock
    2       3,332       (3,334 )                  
Amortization of expense
                617                   617  
Other changes
          114       (114 )                  
Components of comprehensive income:
                                               
Net income
                      34,893             34,893  
Change in deferred hedge loss, net of income taxes of $10,610
                            (17,311 )     (17,311 )
 
                                           
 
 
Total comprehensive income
                                            17,582  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Balance at June 30, 2004
  $ 326     $ 312,267     $ (5,359 )   $ 152,258     $ (27,341 )   $ 432,151  
 
   
 
     
 
     
 
     
 
     
 
     
 
 

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

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ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)
(unaudited)
                 
    Six months ended
    June 30,
    2004
  2003
Operating activities
               
Net income
  $ 34,893     $ 32,211  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depletion, depreciation, and amortization
    20,512       15,486  
Deferred taxes
    17,496       17,226  
Non-cash stock based compensation
    617       295  
Cumulative effect of accounting change
          (863 )
Non-cash derivative fair value (gain) loss
    6,106       (892 )
Exploration expense
    1,697        
Other non-cash
    779       3,472  
Loss on disposition of assets
    109       129  
Changes in operating assets and liabilities:
               
Accounts receivable
    (3,882 )     (376 )
Other current assets
    (8,357 )     (692 )
Other assets
    (309 )     (7,456 )
Accounts payable and accrued liabilities
    4,829       (7,390 )
 
   
 
     
 
 
Cash provided by operating activities
    74,490       51,150  
 
   
 
     
 
 
Investing activities
               
Proceeds from disposition of assets
    425       590  
Purchases of other property and equipment
    (6,597 )     (292 )
Acquisition of oil and natural gas properties
    (98,608 )     (259 )
Acquisition of Cortez Oil & Gas, Inc. (net of cash acquired)
    (123,023 )      
Development of oil and natural gas properties
    (70,573 )     (46,198 )
 
   
 
     
 
 
Cash used by investing activities
    (298,376 )     (46,159 )
 
   
 
     
 
 
Financing activities
               
Proceeds from issuance of common stock
    53,900        
Payment of offering costs of common stock
    (900 )      
Proceeds from long-term debt
    169,000       24,500  
Payments on long-term debt
    (145,000 )     (40,500 )
Proceeds from issuance of 6¼% notes
    150,000        
Payment of debt issuance costs
    (3,128 )      
Other
    2,374       777  
 
   
 
     
 
 
Cash provided by (used in) financing activities
    226,246       (15,223 )
 
   
 
     
 
 
Increase (decrease) in cash and cash equivalents
    2,360       (10,232 )
Cash and cash equivalents, beginning of period
    431       13,057  
 
   
 
     
 
 
Cash and cash equivalents, end of period
  $ 2,791     $ 2,825  
 
   
 
     
 
 

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

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2004
(unaudited)

1. Formation of Encore

     Encore Acquisition Company (“Encore” or the “Company”), a Delaware corporation, is a growing independent energy company engaged in the acquisition, development and exploitation of North American oil and natural gas reserves. Since the Company’s inception in 1998, Encore has sought to acquire high-quality assets with potential for upside through low-risk development drilling projects. Encore’s properties are currently located in four core areas: the Cedar Creek Anticline (“CCA”), of Montana and North Dakota; the Permian Basin of West Texas and Southeastern New Mexico; 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 near Fort Worth, Texas; and the Rocky Mountains.

2. Basis of Presentation

     In the opinion of management, the accompanying unaudited consolidated financial statements of Encore include all adjustments necessary to present fairly our financial position as of June 30, 2004, results of operations for the three and six months ended June 30, 2004 and 2003, and cash flows for the six months ended June 30, 2004 and 2003. All adjustments are of a 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 Securities and Exchange Commission (“SEC”). Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes thereto included in the Company’s 2003 Annual Report filed on Form 10-K.

     Employee stock options and restricted stock awards are accounted for at intrinsic value in accordance with the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Accordingly, no compensation expense is recorded for stock options that are granted to employees or non-employee directors with an exercise price equal to or above the Company’s stock price on the date of grant. However, compensation expense is recorded for the fair value of the restricted stock granted to employees. During the second quarter of 2004, the Company awarded 57,161 shares of restricted stock under the Company’s 2000 Incentive Stock Plan. The shares vest in equal annual installments over the next three years and are contingent only upon continued employment. Deferred compensation of $1.6 million was recorded in conjunction with the grants, and will be expensed over the related vesting period.

     If employee stock options were accounted for at fair value in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation,” the Company’s reported net income and net income per share amounts would have been adjusted to the pro forma amounts indicated below (in thousands, except per share amounts):

                                 
    Three months ended   Six months ended
    June 30,
  June 30,
    2004
  2003
  2004
  2003
As Reported:
                               
Non-cash stock based compensation (net of taxes) (a)
  $ 190     $ 95     $ 383     $ 186  
Net income
    17,991       14,233       34,893       32,211  
Basic net income per common share
    0.59       0.47       1.15       1.07  
Diluted net income per common share
    0.58       0.47       1.13       1.06  
Pro Forma:
                               
Non-cash stock based compensation (net of taxes)
  $ 518     $ 523     $ 924     $ 946  
Net income
    17,663       13,805       34,352       31,451  
Basic net income per common share
    0.57       0.46       1.13       1.05  
Diluted net income per common share
    0.57       0.46       1.11       1.04  

(a)   For the quarter ended June 30, 2004, 6,509 shares of employee stock options and 1,810 shares of restricted stock, which were issued and outstanding at March 31, 2004, were forfeited. For the first half of 2004, 12,685 shares of employee stock options and 9,176 shares of restricted stock, which were issued and outstanding at December 31, 2003, were forfeited.

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3. Business Combinations

Cortez Acquisition

     On April 14, 2004, the Company purchased all of the outstanding capital stock of Cortez Oil & Gas, Inc. (“Cortez”), a privately held, independent oil and natural gas company, for a total purchase price of $126.3 million, which includes cash paid to Cortez’ former shareholders of $85.8 million, the repayment of $39.4 million of Cortez’s debt, and transition costs incurred of $1.1 million.

     Encore funded the acquisition with a portion of the net proceeds from the issuance of the 6¼ Notes (see Note 4). The net proceeds from the notes were placed in escrow upon the closing of the offering and were released to fund the Cortez acquisition in accordance with the terms of the escrow agreement with the initial purchasers of the 6¼% Notes.

     The acquired oil and natural gas properties are located primarily in the CCA of Montana, the Permian Basin of West Texas and Southeastern New Mexico and in the Mid Continent area, including the Anadarko and Arkoma Basins of Oklahoma and the Barnett Shale north of Fort Worth, Texas. Cortez’ operating results are included in Encore’s Consolidated Statement of Operations for the period April through June 2004.

     The calculation of the total purchase price and the calculation of the fair value of net assets acquired at April 14, 2004, are as follows (in thousands):

         
Calculation of total purchase price:
       
Cash paid to Cortez’ former owners
  $ 85,793  
Cortez debt repaid
    39,449  
Transaction costs
    1,050  
 
   
 
 
Total purchase price
  $ 126,292  
 
   
 
 
Calculation of fair value of net assets acquired:
       
Cash
  $ 3,269  
Current assets
    5,574  
Proved oil and gas properties
    120,503  
Unproved oil and gas properties
    3,011  
Goodwill
    38,623  
 
   
 
 
Total assets required
    170,980  
 
   
 
 
Current liabilities
    (5,426 )
Non-current liabilities
    (996 )
Deferred income taxes
    (38,266 )
 
   
 
 
Total liabilities assumed
    (44,688 )
 
   
 
 
Fair value of net assets acquired
  $ 126,292  
 
   
 
 

     The purchase price allocation resulted in $38.6 million of goodwill primarily as the result of the difference between the fair value of oil and gas properties and their assumed tax basis. None of the goodwill is deductible for income tax purposes. Furthermore, in accordance with SFAS No. 142, “Goodwill and Intangible Assets,” goodwill is not amortized, but is tested for impairment on a quarterly basis, which involves the use of estimates related to the fair market value of the business operations and reporting unit with which goodwill is associated. Currently, Encore has one reporting level. Losses, if any, resulting from impairment tests will be reflected in operating income in the Consolidated Statement of Operations.

4. Debt

Issuance of 6 ¼ % Senior Subordinated Notes

     On April 2, 2004, the Company issued $150.0 million of 6¼% Senior Subordinated Notes maturing April 15, 2014 (the “6¼% Notes”). The offering was made through a private placement. The 6¼% Notes were resold by the initial purchasers pursuant to Rule 144A and Regulation S. The Company estimates net proceeds of approximately $146.2 million after paying all costs associated with the offering. The net proceeds were used to fund the acquisition of Cortez (see Note 3) and repay amounts outstanding under the Company’s revolving credit facility. Concurrently with the issuance of the 6¼% Notes, the Company entered into a registration rights agreement whereby Encore agreed to file a registration statement offering to exchange the 6¼% Notes for registered notes with substantially identical terms. The Company filed the registration statement on June 30, 2004 on Form S-4. The registration statement

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was declared effective by the SEC on July 14, 2004, and the related offer to exchange the outstanding Notes for registered notes was launched on July 21, 2004. The exchange offer expires at 5:00 p.m., New York City time, on August 19, 2004.

     The 6¼% Notes mature on April 15, 2014, and all amounts outstanding will be due and payable at that time. Interest is paid semi-annually on April 15 and October 15. The indenture governing the 6¼% Notes contains substantially the same covenants and restrictions as the 8⅜% Notes.

Letters of Credit

     The Company had $14.4 million of outstanding letters of credit at June 30, 2004. These letters of credit are posted primarily with two counterparties to the Company’s hedging contracts and are used in lieu of cash margin deposits with those counterparties.

5. Asset Retirement Obligations

     In August 2001, the Financial Accounting Standards Board issued SFAS 143, “Accounting for Asset Retirement Obligations,” which the Company adopted as of January 1, 2003. This statement requires the Company to record a liability in the period in which an asset retirement obligation is incurred in an amount equal to the discounted estimated fair value of the obligation. Also, upon initial recognition of the liability, the Company must capitalize an equal amount of asset cost. Thereafter, each quarter, this liability is accreted and, if needed, adjusted up to the final cost. Accretion expense is included in ‘Other operating’ expense in the Company’s Consolidated Statements of Operations.

     The adoption of SFAS 143 on January 1, 2003 resulted in a cumulative effect of accounting change adjustment to record (i) a $4.0 million increase in the carrying values of proved properties, (ii) a $2.1 million decrease in accumulated depletion, depreciation, and amortization, (iii) a $5.2 million increase in non-current liabilities, and (iv) a gain of $0.9 million, net of tax.

     The following table shows net income and basic and diluted net income per common share as reported, as well as pro forma amounts as if the Company had adopted SFAS 143 prior to January 1, 2003 (in thousands, except per common share amounts):

                 
    Six months ended
    June 30,
    2004
  2003
As Reported:
               
Net income
  $ 34,893     $ 32,211  
Basic net income per common share
    1.15       1.07  
Diluted net income per common share
    1.13       1.06  
Pro Forma:
               
Net income
  $ 34,893     $ 31,348  
Basic net income per common share
    1.15       1.04  
Diluted net income per common share
    1.13       1.04  

     The Company’s primary asset retirement obligations relate to future plugging and abandonment expenses on our oil and natural gas properties and related facilities disposal. As of June 30, 2004, the Company had $3.0 million held in an escrow account from which funds are released only for reimbursement of plugging and abandonment expenses on our Bell Creek property. This amount is included in ‘Other assets’ in the accompanying Consolidated Balance Sheet. The following table summarizes the changes in the Company’s future abandonment liability from January 1, 2004 through June 30, 2004 (in thousands):

         
Future abandonment liability at January 1, 2004
  $ 5,341  
Property acquisitions
    995  
Wells drilled
    126  
Accretion expense
    148  
Plugging and abandonment costs incurred
    (51 )
 
   
 
 
Future abandonment liability at June 30, 2004
  $ 6,559  
 
   
 
 

6. Income Taxes

     Reconciliation of income tax expense with tax at the Federal statutory rate is as follows (in thousands):

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    Six months ended
    June 30,
    2004
  2003
Income before income taxes and the cumulative change in accounting
  $ 54,393     $ 49,932  
 
   
 
     
 
 
Tax at statutory rate
    19,038       17,476  
State income taxes, net of federal benefit
    1,632       1,498  
Section 43 credits generated
    (1,663 )     (30 )
Other
    493       (360 )
 
   
 
     
 
 
Total
  $ 19,500     $ 18,584  
 
   
 
     
 
 

7. Earnings Per Share (EPS)

     The following table sets forth basic and diluted EPS computations for the three and six months ended June 30, 2004 and 2003 (in thousands, except per share data):

                                 
    Three months ended   Six months ended
    June 30,
  June 30,
    2004
  2003
  2004
  2003
Numerator:
                               
Income before cumulative effect of accounting change
  $ 17,991     $ 14,233     $ 34,893     $ 31,348  
Cumulative effect of accounting change
                      863  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 17,991     $ 14,233     $ 34,893     $ 32,211  
 
   
 
     
 
     
 
     
 
 
Denominator:
                               
Denominator for basic earnings per share – weighted average shares outstanding
    30,726       30,089       30,456       30,063  
Effect of dilutive options and dilutive restricted stock (a).
    394       195       391       190  
 
   
 
     
 
     
 
     
 
 
Denominator for diluted earnings per share
    31,120       30,284       30,847       30,253  
 
   
 
     
 
     
 
     
 
 
Basic earnings per common share:
                               
Income before cumulative effect of accounting change
  $ 0.59     $ 0.47     $ 1.15     $ 1.04  
Cumulative effect of accounting change, net of income taxes
                      0.03  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 0.59     $ 0.47     $ 1.15     $ 1.07  
 
   
 
     
 
     
 
     
 
 
Diluted earnings per common share:
                               
Income before cumulative effect of accounting change
  $ 0.58     $ 0.47     $ 1.13     $ 1.04  
Cumulative effect of accounting change, net of income taxes
                      0.02  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 0.58     $ 0.47     $ 1.13     $ 1.06  
 
   
 
     
 
     
 
     
 
 

(a)   There were no shares of antidilutive restricted stock outstanding for the three months ended June 30, 2004 and 2003. For the quarter ended June 30, 2004 and 2003, outstanding employee stock options of 25,000 and 240,000 were excluded from the calculation of diluted earnings per share because their effect would have been antidilutive.

8. Derivative Financial Instruments

     The following tables summarize the Company’s open commodity derivative instruments designated as hedges as of June 30, 2004:

Oil Derivative Instruments at June 30, 2004

                                                         
    Daily   Floor   Daily   Cap   Daily   Swap   Fair
    Floor Volume   Price   Cap Volume   Price   Swap Volume   Price   Value
Period
  (Bbls)
  (per Bbl)
  (Bbls)
  (per Bbl)
  (Bbls)
  (per Bbl)
  (000s)
July – Dec 2004
    15,500     $ 24.23       6,000     $ 29.37       500     $ 26.48     $ (9,177 )
Jan – June 2005
    14,500       27.38       3,500       31.89       1,000       25.12       (3,162 )
July – Dec 2005
    11,500       27.65       2,500       31.07       1,000       25.12       (1,217 )
Jan – Dec 2006.
    1,000       27.50       1,000       29.88       2,000       25.03       (6,759 )
Jan – Dec 2007.
                            2,000       25.11       (4,258 )

Natural Gas Derivative Instruments at June 30, 2004

                                                         
    Daily   Floor   Daily   Cap   Daily   Swap   Fair
    Floor Volume   Price   Cap Volume   Price   Swap Volume   Price   Value
Period
  (Mcf)
  (per Mcf)
  (Mcf)
  (per Mcf)
  (Mcf)
  (per Mcf)
  (000s)
July – Dec 2004
    15,000     $ 4.02       7,500     $ 6.03       15,000     $ 5.47     $ (2,520 )
Jan – Dec 2005.
    10,000       4.84       5,000       5.97       12,500       4.99       (4,925 )
Jan – Dec 2006.
    5,000       4.85       5,000       5.68       12,500       5.08       (2,179 )
Jan – Dec 2007.
                            10,000       4.99       127  

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     Encore recognizes in the Consolidated Statement of Operations derivative fair value gains and losses related to changes in the mark-to-market value of the Company’s basis swaps and certain other commodity derivatives that are not designated for hedge accounting; ineffectiveness of commodity derivative contracts designated as hedges; and changes in the mark-to-market value of the Company’s interest rate swap.

     In order to more effectively hedge the cash flows received on oil and natural gas production, the Company enters into financial instruments whereby Encore swaps certain per Bbl or per Mcf floating market indices for a fixed amount. These market indices are a component of the price Encore is paid on its actual production. By fixing this component of the Company’s marketing price, Encore is able to realize a net price with a more consistent differential to NYMEX. Since NYMEX is the basis of all the Company’s derivative oil hedging contracts and some of the natural gas contracts, a more consistent differential results in more effective hedges. However, management has elected not to use hedge accounting for certain of these contracts because it is more cost effective not to designate such derivatives as hedges. Instead, the Company marks these contracts to market each quarter through ‘Derivative fair value (gain) loss’ in the Consolidated Statements of Operations. Thus, as these contracts do not change Encore’s overall hedged volumes, average prices presented in the tables above are exclusive of any effect of these non-hedge instruments. As of June 30, 2004, the mark-to-market value of these contracts was $0.1 million.

     The oil put contracts in place at June 30, 2004 that the Company did not designate as cash flow hedges represented 2,500 Bbls in the second half of 2004. The Company also had natural gas floor contracts not designated as hedges representing 5,000 Mcf per day for 2004.

Interest Rate Derivatives

     The following table summarizes the Company’s only interest rate swap contract at June 30, 2004:

                                 
                    Encore   Fair Value
Contract Expiration
  Notional Amount
  Encore Pays
  Receives
  (000s)
June 2005
  $ 80,000,000     LIBOR + 3.89%     8.375 %   $ 988  

     This contract does not qualify for hedge accounting and, thus, the changes in its fair market value are recorded in ‘Derivative fair value (gain) loss’ on the Consolidated Statements of Operations. During the quarter ended June 30, 2004, a loss of $1.1 million related to the interest rate swap was recorded in the Consolidated Statement of Operations.

     The actual gains or losses the Company realizes from derivative transactions may vary significantly from the deferred loss amount recorded in stockholders’ equity at June 30, 2004 due to fluctuation of prices in the commodities markets.

9. Financial Statements of Subsidiary Guarantors

     As of June 30, 2004, all of the Company’s subsidiaries were subsidiary guarantors of the Company’s outstanding 8⅜% and 6¼% notes. Since (i) each subsidiary guarantor is 100% owned by the Company, (ii) the Company has no assets or operations that are independent of its subsidiaries, (iii) the subsidiary guarantees are full and unconditional and joint and several and (iv) all of the Company’s subsidiaries are subsidiary guarantors, the Company has not included the financial statements of each subsidiary in this report. The subsidiary guarantors may without restriction transfer funds to the Company in the form of cash dividends, loans, and advances.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     This document contains forward-looking statements that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve risks and uncertainties. Actual results may differ materially from those anticipated in our forward-looking statements due to many factors, including, but not limited to, those set forth under “— SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS” contained in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in Encore’s 2003 Annual Report on Form 10-K. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this document and Encore’s 2003 Form 10-K.

Second Quarter 2004 Highlights

     Our financial and operating results for the quarter ended June 30, 2004 included the following highlights:

  During the second quarter of 2004, we had quarterly net income of $18.0 million ($0.58 per diluted share), which represents an increase of 27% over second quarter 2003 net income of $14.2 million ($0.47 per diluted share). Second quarter 2004 net income was negatively impacted by $1.1 million ($0.03 per share) of exploration expense. Higher production volumes and commodity prices resulted in record oil and natural gas revenues of $70.1 million for the second quarter of 2004. This represents a 37% increase over the $51.2 million of oil and natural gas revenues reported for the second quarter of 2003. Our average net combined price rose to $31.54 per BOE for the second quarter of 2004 over the $26.32 per BOE reported in the second quarter of 2003.

  Our earnings were driven by record production volumes averaging 24,434 BOE per day in the second quarter of 2004 as compared to 21,398 BOE per day in the second quarter of 2003, an increase of 14%. During the current quarter, oil production averaged 18,557 Bbls per day and natural gas production averaged 35,260 Mcf per day. Natural gas production volumes in the current quarter reflect an increase of 61% over the level reported in the second quarter of 2003 as a result of our Elm Grove and Cortez acquisitions that closed in the second half of 2003 and the first half of 2004, respectively. Our recently completed Overton acquisition is not reflected in the operating results in the second quarter of 2004.

  Lease operations expense increased from $4.69 per BOE reported in the second quarter of 2003 to $4.91 per BOE in the second quarter of 2004. The increase in our average per BOE rate was attributable to production declines in our fields that have relatively low lease operations expense compared to our other properties and an increase in prices paid for outside services. General and administrative expense decreased from $1.20 per BOE in the second quarter of 2003 to $1.14 per BOE in the second quarter of 2004 as costs were spread over higher production volumes. DD&A expense per BOE of $5.06 for the second quarter of 2004 increased, as expected, from the $3.96 per BOE recorded for the second quarter of 2003 resulting from higher than historical finding, development, and acquisition costs.

  We invested $40.2 million in development projects during the second quarter of 2004, $9.3 million of which was invested in our high-pressure air injection (“HPAI”) tertiary recovery projects in the Little Beaver Unit and the Pennel Unit of the CCA. The capital was invested in 23 (18.6 net) new operated vertical producing wells, 5 (5.0 net) horizontal wells, 15 (14.9 net) operated horizontal re-entry wells and 1 (1.0 net) operated service/injection well. We also participated in the drilling of 19 (2.4 net) non-operated vertical producing wells. We drilled one exploratory dry hole in the Barnett Shale area that was acquired in the Cortez acquisition.

  Recent acquisitions include the acquisition of natural gas properties in Overton Field located in Smith County, Texas, additional interests in Elm Grove Field, and the acquisition of Cortez.

  On June 30, 2004, we filed a new registration statement on Form S-3 with the SEC. The registration statement, which was declared effective by the SEC on July 9, 2004, allows us to issue an aggregate of $500 million of common stock, preferred stock, senior debt and subordinated debt.

  On June 10, 2004, we issued and sold 2,000,000 shares of our common stock to the public at a price of $26.95 per share. The shares were sold under our prior shelf registration statement, which was declared effective by the SEC in August 2003. The net proceeds of the offering, after underwriting discounts and commissions and other expenses of the offering, were approximately $53.0 million. We used the net proceeds of this offering to repay indebtedness under our revolving

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    credit facility and for general corporate purposes, including funding the previously announced purchase of natural gas properties in Overton Field in Smith County, Texas.

  On April 2, 2004, we sold $150 million of 6¼% Senior Subordinated Notes due 2014 in a private placement. We estimate net proceeds of $146.2 million after deducting commissions and paying other costs associated with the offering. Subsequent to the initial offering, we filed a registration statement with the SEC to exchange registered notes for the unregistered notes.

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Results of Operations

     The following table sets forth selected operating information for the periods presented:

                                                 
    Three months ended           Six months ended    
    June 30,
  Increase /   June 30,
  Increase /
    2004
  2003
  (Decrease)
  2004
  2003
  (Decrease)
Operating results (in thousands):
                                               
Oil and natural gas revenues
  $ 70,122     $ 51,243     $ 18,879     $ 129,413     $ 107,030     $ 22,383  
Lease operations expense
    10,921       9,140       1,781       21,163       18,093       3,070  
Production, ad valorem, and severance taxes
    7,161       5,095       2,066       13,000       11,264       1,736  
Daily production volumes:
                                               
Oil (Bbls)
    18,557       17,755       802       18,128       18,130       (2 )
Natural gas (Mcf)
    35,260       21,858       13,402       31,501       21,667       9,834  
Combined (BOE)
    24,434       21,398       3,036       23,378       21,741       1,637  
Average prices:
                                               
Oil (per Bbl)
  $ 31.32     $ 25.19     $ 6.13     $ 30.20     $ 26.55     $ 3.65  
Natural gas (per Mcf)
    5.37       5.30       0.07       5.19       5.07       0.12  
Combined (per BOE)
    31.54       26.32       5.22       30.42       27.20       3.22  
Selected operating expenses per BOE:
                                               
Lease operations
  $ 4.91     $ 4.69     $ 0.22     $ 4.97     $ 4.60     $ 0.37  
Production, ad valorem, and severance taxes
    3.22       2.62       0.60       3.06       2.86       0.20  
DD&A
    5.06       3.96       1.10       4.82       3.94       0.88  
G&A (excluding non-cash stock based compensation)
    1.14       1.20       (0.06 )     1.12       1.22       (0.10 )

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Comparison of Quarter Ended June 30, 2004 to Quarter Ended June 30, 2003

     Set forth below is our comparison of operations during the second quarter of 2004 with the second quarter of 2003.

     Revenues and Production Volumes. The following table illustrates the primary components of oil and natural gas revenue for the three months ended June 30, 2004 and 2003, as well as each quarter’s respective oil and natural gas volumes (in thousands, except per unit amounts):

                                                 
    Three months ended June 30,
  Increase /
    2004
  2003
  (Decrease)
    Revenue
  $/Unit
  Revenue
  $/Unit
  Revenue
  $/Unit
Revenues:
                                               
Oil wellhead
  $ 60,638     $ 35.90     $ 43,262     $ 26.77     $ 17,376     $ 9.13  
Oil hedges
    (7,753 )     (4.58 )     (2,558 )     (1.58 )     (5,195 )     (3.00 )
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total Oil Revenues
  $ 52,885     $ 31.32     $ 40,704     $ 25.19     $ 12,181     $ 6.13  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Natural gas wellhead
  $ 17,948     $ 5.59     $ 11,040     $ 5.55     $ 6,908     $ 0.04  
Natural gas hedges
    (711 )     (0.22 )     (501 )     (0.25 )     (210 )     0.03  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total Natural Gas Revenues
  $ 17,237     $ 5.37     $ 10,539     $ 5.30     $ 6,698     $ 0.07  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Combined wellhead
  $ 78,586     $ 35.35     $ 54,302     $ 27.89     $ 24,284     $ 7.46  
Combined hedges
    (8,464 )     (3.81 )     (3,059 )     (1.57 )     (5,405 )     (2.24 )
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total Combined Revenues
  $ 70,122     $ 31.54     $ 51,243     $ 26.32     $ 18,879     $ 5.22  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
                                                 
                                            Average
            Average           Average           NYMEX
    Production
  NYMEX $/Unit
  Production
  NYMEX $/Unit
  Production
  $/Unit
Other data:
                                               
Oil (Bbls)
    1,689     $ 38.32       1,616     $ 28.91       73     $ 9.41  
Natural Gas (Mcf)
    3,209       6.07       1,989       5.74       1,220       0.33  
Combined (BOE)
    2,223               1,947               276          

     Oil revenues increased from second quarter 2003 to second quarter 2004 by $12.2 million, due to a higher realized average oil price and a slight increase in volumes. Our realized average oil price increased $6.13 per Bbl in the second quarter of 2004 over the same period in 2003 primarily as a result of a $9.13 per Bbl increase in our average wellhead price offset by an increase in hedging payments. This increase in our average wellhead price is in line with the increase in the overall market price for oil as reflected in the $9.41 per Bbl increase in the average NYMEX price over the same period.

     Natural gas revenues increased by $6.7 million in the second quarter of 2004 compared to the second quarter of 2003 due to an increase in volumes and a slight increase in our realized average natural gas price. Production volumes increased 1,220 MMcf in the second quarter of 2004 as compared to the second quarter of 2003 due to the Elm Grove acquisition, which was completed during the third quarter of 2003 and the Cortez acquisition, which was completed in the second quarter of 2004.

     Lease operations expense. Lease operations expense for the second quarter of 2004 increased as compared to the second quarter of 2003 by $1.8 million. The increase is primarily attributable to an increase in production volumes attributable to the Elm Grove and Cortez acquisitions. Lease operations expense per BOE increased by $0.22. The increase in our average per BOE rate was attributable to production declines in our fields that have relatively low lease operations expense compared to our other properties and an increase in prices paid for outside services.

     Production, ad valorem, and severance taxes. Production, ad valorem, and severance taxes for the second quarter of 2004 increased as compared to the same period in 2003 by approximately $2.1 million due to increased revenues. As a percentage of oil and natural gas revenues (excluding the effects of hedges), production, ad valorem, and severance taxes for the second quarter of 2004 decreased slightly when compared to the second quarter of 2003, down to 9.1% from 9.4%. The decrease is attributable to the addition of the Elm Grove properties added in the third quarter of 2003 and the Cortez properties added in the second quarter of 2004, which have a lower rate as a percentage of oil and natural gas revenues than our historical average. The effect of hedges 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, ad valorem, and severance taxes paid to taxing authorities.

     General and administrative (“G&A”) expense. G&A expense (excluding non-cash stock based compensation) increased $0.2 million for the second quarter of 2004 as compared to the second quarter of 2003. The overall increase is primarily a result of increased staffing levels added to maintain the Company’s larger asset base. G&A expense (excluding non-cash stock based

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compensation) decreased 5% on a per BOE basis from $1.20 in the second quarter of 2003 to $1.14 per BOE in the second quarter of 2004 as costs were spread over higher production volumes.

     Non-cash stock based compensation expense. Non-cash stock based compensation expense increased $0.2 million from the three months ended June 30, 2003 to the three months ended June 30, 2004. This expense represents the amortization of deferred compensation which is being amortized to expense over the vesting period of restricted stock granted under the 2000 Incentive Stock Plan. The increase is the result of the increase in total deferred compensation to be recorded, which is due to an increase in the number of shares outstanding and an increase in our stock price.

     Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense for the second quarter of 2004 increased by $3.5 million as compared to the second quarter of 2003, due to a $1.10 increase in the per BOE rate and an increase in production. The per BOE rate increased, as expected, from the $3.96 per BOE recorded in the second quarter of 2003 to $5.06 in the second quarter of 2004 as a result of higher than historical finding, development, and acquisition costs.

     Exploration expense. Exploration expense was $1.7 million for the three months ended June 30, 2004 as compared to zero for the same period in 2003. This expense is mainly attributable to the dry hole drilled in the Barnett Shale area that was acquired in the Cortez acquisition. The well was spudded by Cortez prior to acquisition.

     Derivative fair value (gain) loss. During the second quarter of 2004, we recorded a $1.0 million derivative fair value loss as compared to the $0.6 million gain recorded in the second quarter of 2003. The components of the derivative fair value (gain) loss reported in the quarterly periods are as follows (in thousands):

                         
    Three months ended June 30,
  Increase /
    2004
  2003
  (Decrease)
Designated cash flow hedges:
                       
Ineffectiveness – Commodity contracts
  $ 181     $ 57     $ 124  
Undesignated derivative contracts:
                       
Mark-to-market (gain) loss – Interest rate swaps
    1,130       (1,089 )     2,219  
Mark-to-market (gain) loss – Commodity contracts
    (346 )     456       (802 )
 
   
 
     
 
     
 
 
Derivative fair value (gain) loss
  $ 965     $ (576 )   $ 1,541  
 
   
 
     
 
     
 
 

     Other operating expense. Other operating expense for the second quarter of 2004 increased by $0.4 million as compared to the second quarter of 2003. This increase is attributable to higher third party transportation expenses in the second quarter of 2004 and higher accretion expense related to our future abandonment liability.

     Interest expense. Interest expense increased $2.3 million in the quarter ended June 30, 2004 compared to the quarter ended June 30, 2003. The increase in interest expense is due to the issuance of the 6 ¼% Notes, slightly offset by a decrease in non-cash amortization of the deferred loss on interest rate swaps. The weighted average interest rate, net of hedges, for the second quarter of 2004 was 7.9% compared to 10.7% for the second quarter of 2003, as the 6 ¼% rate on the newly issued bonds is lower than our historical average rate. The following table illustrates the components of interest expense for the three months ended June 30, 2004 and 2003 (in thousands):

                         
    Three months ended June 30,
  Increase /
    2004
  2003
  (Decrease)
8 ⅜% notes due 2012
  $ 3,141     $ 3,141     $  
6 ¼% notes due 2014
    2,318             2,318  
Revolving credit facility
    230       15       215  
Interest rate hedges (a)
    153       544       (391 )
Banking fees and other
    466       339       127  
 
   
 
     
 
     
 
 
Total
  $ 6,308     $ 4,039     $ 2,269  
 
   
 
     
 
     
 
 

(a)   Amount represents non-cash amortization of the deferred loss on interest rate swaps from other comprehensive income to interest expense. This unrealized loss relates to previously outstanding interest rate swaps which no longer qualified for hedge accounting. We have since cash settled these interest rate swaps and the swaps are no longer outstanding.

     Income taxes. Income tax expense for the second quarter of 2004 increased as compared to the second quarter of 2003 by $1.6 million. This increase is due in part to the $5.3 million increase in income before income taxes, offset by a decrease in our effective tax rate from 37.2% in the second quarter of 2003 to 35.7% in the second quarter of 2004. The decrease in our effective tax rate is due to an increase in Section 43 credits generated from investments in high-pressure air injection on our CCA properties during the second

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quarter of 2004 as compared to the second quarter of 2003. Section 43 credits increased from $0.01 million generated during the second quarter of 2003 to $1.5 million generated in the second quarter of 2004.

Comparison of Six Months Ended June 30, 2004 to Six Months Ended June 30, 2003

     Set forth below is our comparison of operations during the first six months of 2004 with the first six months of 2003.

     Revenues and Production Volumes. The following table illustrates the primary components of oil and natural gas revenue for the six months ended June 30, 2004 and 2003, as well as each period’s respective oil and natural gas volumes (in thousands, except per unit amounts):

                                                 
    Six months ended June 30,
  Increase /
    2004
  2003
  (Decrease)
    Revenue
  $/Unit
  Revenue
  $/Unit
  Revenue
  $/Unit
Revenues:
                                               
Oil wellhead
  $ 113,017     $ 34.25     $ 95,476     $ 29.10     $ 17,541     $ 5.15  
Oil hedges
    (13,368 )     (4.05 )     (8,340 )     (2.55 )     (5,028 )     (1.50 )
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total Oil Revenues
  $ 99,649     $ 30.20     $ 87,136     $ 26.55     $ 12,513     $ 3.65  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Natural gas wellhead
  $ 30,870     $ 5.38     $ 21,352     $ 5.44     $ 9,518     $ (0.06 )
Natural gas hedges
    (1,106 )     (0.19 )     (1,458 )     (0.37 )     352       0.18  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total Natural Gas Revenues
  $ 29,764     $ 5.19     $ 19,894     $ 5.07     $ 9,870     $ 0.12  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Combined wellhead
  $ 143,887     $ 33.82     $ 116,828     $ 29.69     $ 27,059     $ 4.13  
Combined hedges
    (14,474 )     (3.40 )     (9,798 )     (2.49 )     (4,676 )     (0.91 )
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total Combined Revenues
  $ 129,413     $ 30.42     $ 107,030     $ 27.20     $ 22,383     $ 3.22  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
                                                 
            Average           Average           Average
            NYMEX           NYMEX           NYMEX
    Production
  $/Unit
  Production
  $/Unit
  Production
  $/Unit
Other data:
                                               
Oil (Bbls)
    3,299     $ 36.73       3,281     $ 31.39       18     $ 5.34  
Natural Gas (Mcf)
    5,733       5.90       3,922       5.82       1,811       0.08  
Combined (BOE)
    4,255               3,935               320          

     Oil revenues increased from the first six months of 2003 to the first six months of 2004 by $12.5 million, primarily due to a higher realized average oil price. Our realized average oil price increased $3.65 per Bbl for the six months ended June 30, 2004 over the same period in 2003 primarily as a result of an increase in our average wellhead price. The $5.15 per Bbl increase in our average wellhead price is in line with the increase in the overall market price for oil as reflected in the $5.34 per Bbl increase in the average NYMEX price over the same period.

     Natural gas revenues increased by $9.9 million for the six months ended June 30, 2004 over the same period in 2003 primarily due to an increase in volumes. Production volumes increased 1,811 MMcf for the six months ended June 30, 2004 as compared to the same period in 2003 due to the Elm Grove acquisition, which was completed during the third quarter of 2003 and the Cortez acquisition, which was completed in the second quarter of 2004. Our average wellhead price received remained relatively flat, which is consistent with the overall market price for natural gas, as reflected in the slight average NYMEX price change over the period.

     Lease operations expense. Lease operations expense for the six months ended June 30, 2004 increased as compared to the same period in 2003 by $3.1 million. The increase is primarily attributable to the production from the Elm Grove and Cortez acquisitions, which closed in the third quarter of 2003 and the second quarter of 2004, respectively. Lease operations expense per BOE increased by $0.37. The increase in our average per BOE rate was attributable to production declines in our fields that have relatively low lease operations expense compared to our other properties and an increase in prices paid for outside services.

     Production, ad valorem, and severance taxes. Production, ad valorem, and severance taxes increased by approximately $1.7 million for the six months ended June 30, 2004 over the same period in 2003 due to increased revenues. As a percentage of oil and natural gas revenues (excluding the effects of hedges), production, ad valorem, and severance taxes for the first half of 2004 decreased when compared to the first half of 2003, down to 9.0% from 9.6%. The decrease is attributable to the addition of the Elm Grove properties added in the third quarter of 2003 and the Cortez properties added in the second quarter of 2004, which have a lower rate as a percentage of oil and natural gas revenues than our historical average. The effect of hedges 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, ad valorem, and severance taxes paid to taxing authorities.

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     General and administrative expense. G&A expense (excluding non-cash stock based compensation) decreased slightly for the six months ended June 30, 2004 over the same period in 2003. G&A expense (excluding non-cash stock based compensation) decreased 8% on a per BOE basis from $1.22 in the six months ended June 30, 2003 to $1.12 per BOE in the six months ended June 30, 2004 as costs were spread over higher production volumes.

     Non-cash stock based compensation expense. Non-cash stock based compensation expense increased $0.3 million from the six months ended June 30, 2003 to the six months ended June 30, 2004. This expense represents the amortization of deferred compensation which is being amortized to expense over the vesting period of restricted stock granted under the 2000 Incentive Stock Plan. The increase is the result of the increase in total deferred compensation to be recorded, which is due to an increase in the number of shares granted and an increase in our stock price.

     Depletion, depreciation, and amortization expense. DD&A expense for the first six months of 2004 increased by $5.0 million as compared to the same period in 2003, due to a $0.88 increase in the per BOE rate and an increase in production. The per BOE rate increased, as expected, from the $3.94 per BOE recorded for the six months ended June 30, 2003 to $4.82 for the six months ended June 30, 2004 as a result of higher than historical finding, development, and acquisition costs.

     Exploration expense. Exploration expense was $1.7 million for the six months ended June 30, 2004 as compared to zero for the same period in 2003. This expense is mainly attributed to the dry hole drilled in the Barnett Shale area that was acquired in the Cortez acquisition. The well was spudded by Cortez prior to acquisition.

     Derivative fair value (gain) loss. During the first six months of 2004, we recorded a $1.1 million derivative fair value loss as compared to the $1.8 million gain recorded in the same period in 2003. The components of the derivative fair value (gain) loss reported in the quarterly periods are as follows (in thousands):

                         
    Six months ended June 30,
  Increase /
    2004
  2003
  (Decrease)
Designated cash flow hedges:
                       
Ineffectiveness – Commodity contracts
  $ 455     $ 150     $ 305  
Undesignated derivative contracts:
                       
Mark-to-market (gain) loss – Interest rate swaps.
    420       (2,442 )     2,862  
Mark-to-market (gain) loss – Commodity contracts.
    248       456       (208 )
 
   
 
     
 
     
 
 
Derivative fair value (gain) loss
  $ 1,123     $ (1,836 )   $ 2,959  
 
   
 
     
 
     
 
 

     Other operating expense. Other operating expense for the six months ended June 30, 2004 increased by $1.2 million as compared to the same period in 2003. This increase is attributable to higher third party transportation expenses in 2004, and higher accretion expense related to our future abandonment liability, and inclusion of $0.5 million gain related to the sale of an Enron receivable in the first quarter of 2003.

     Interest expense. Interest expense increased $2.0 million in the six months ended June 30, 2004 compared to the six months ended June 30, 2003. The increase in interest expense is due to the issuance of the 6 ¼% Notes, slightly offset by a decrease in non-cash amortization of the deferred loss on interest rate swaps. The weighted average interest rate, net of hedges, for the first six months of 2004 was 8.1% compared to 10.4% in the same period in 2003 as our average interest rate benefited from the issuance of the 6 ¼% Notes during the second quarter of 2004. The following table illustrates the components of interest expense for the six months ended June 30, 2004 and 2003 (in thousands):

                         
    Three months ended June 30,
  Increase /
    2004
  2003
  (Decrease)
8 ⅜% notes due 2012
  $ 6,281     $ 6,281     $  
6 ¼% notes due 2014
    2,318             2,318  
Revolving credit facility
    442       117       325  
Interest rate hedges (a).
    365       1,198       (833 )
Banking fees and other
    808       614       194  
 
   
 
     
 
     
 
 
Total
  $ 10,214     $ 8,210     $ 2,004  
 
   
 
     
 
     
 
 

(a)   Amount represents non-cash amortization of the deferred loss on interest rate swaps from other comprehensive income to interest expense. This unrealized loss relates to previously outstanding interest rate swaps which no longer qualified for hedge accounting. We have since cash settled these interest rate swaps and the swaps are no longer outstanding.

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     Income taxes. Income tax expense for the first half of 2004 decreased as compared to the first half of 2003 by $0.9 million. This decrease is due in part to a decrease in our effective tax rate from 37.2% in the first six months of 2003 to 35.9% in the first six months of 2004 offset by the $4.5 million increase in income before income taxes. The decrease in our effective tax rate is due to an increase in Section 43 credits generated from investments in high-pressure air injection on our Cedar Creek Anticline properties during the first half of 2004 as compared to the same period in 2003. Section 43 credits increased from $0.05 million generated during the first half of 2003 to $2.7 million generated in the first half of 2004.

Capital Commitments, Capital Resources and Liquidity

     The following discussion below regarding our future capital commitments, capital resources and liquidity reflects the Cortez acquisition, which closed on April 14, 2004; the Overton acquisition, which closed on June 16, 2004; the issuance of $150.0 million of 6 ¼% notes on April 2, 2004; and assumed base NYMEX commodity prices of $27.00 per Bbl and $4.50 per Mcf.

Capital Commitments

     Our primary needs for cash are as follows:

  Development and exploitation of our existing oil and natural gas properties
 
  High-pressure air injection programs on our CCA properties
 
  Acquisitions of oil and natural gas properties
 
  Leasehold and acreage costs
 
  Other general property and equipment
 
  Funding of necessary working capital
 
  Payment of contractual obligations

     Development and Exploitation. Our capital expenditures for conventional development and exploitation during the six months ended June 30, 2004 totaled $69.3 million. In addition, we spent $1.7 million for exploration during the first half of 2004.

     For the remainder of 2004, we expect to invest approximately $100.0 million in development and exploitation. We have based our revised 2004 capital budget on the assumptions of $27.00 per Bbl and $4.50 per Mcf NYMEX prices. If NYMEX prices trend downward below our base prices, we may reevaluate capital projects and may adjust the capital budgeted for development and exploitation investments accordingly.

     High-Pressure Air Injection. Our capital expenditures for high-pressure air injection during the first half of 2004 totaled $16.9 million. In December 2003, we began implementing our second HPAI program in the Little Beaver unit of the CCA and began injecting air in the reservoir. We have fully implemented the Phase One Little Beaver unit project, and we are currently injecting air. We expect to see uplift sometime in the next 12 months. In 2002, we began a pilot program to inject air into the Red River U4 reservoir in a portion of the Pennel Unit of the CCA. Because of positive results, we are currently expanding the project in the Pennel unit of the CCA, which we expect to complete by early 2005.

     For the remainder of 2004, we expect to invest approximately $22.0 million in high-pressure air injection.

     Acquisitions. Our capital expenditures for proved oil and natural gas properties during the six months ended June 30, 2004 totaled $212.5 million, which included $119.5 million related to the Cortez acquisition, $77.4 million related to the Overton Field acquisition, and $15.6 million related to other acquisitions.

     Leasehold and Acreage Costs. Our capital expenditures for unproved property during the first half of 2004 totaled $9.6 million. Of the $9.6 million of the capital expenditures for unproved property, $3.0 million relates to the Cortez acquisition and the remainder relates to other unproved acreage costs in our core areas.

     For the remainder of 2004, we expect to invest an additional $2.0 million for leasehold and acreage costs. These anticipated investments represent a significant increase from historical capital expenditures for leasehold and acreage costs. We plan to actively pursue leases and acreage in our core areas in which we are currently operating oil and natural gas properties. These investments are not expected to result in oil and natural gas production in 2004.

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     Other General Property and Equipment. Our capital expenditures for other general property and equipment during the first half of 2004 totaled $6.6 million.

     For the remainder of 2004, we expect to invest $0.5 million in other general property and equipment.

     Working Capital. At June 30, 2004, our working capital was $(7.2) million while at December 31, 2003 working capital was $(0.1) million, a decrease of $7.1 million. The decrease is primarily attributable to changes in the fair value of outstanding derivative contracts. As of July 30, 2004, we have $6.4 million cash and $14.0 letters of credit posted related to our derivatives margin account.

     For 2004, we expect working capital to remain relatively flat compared to 2003. We anticipate cash reserves to be close to zero as we use any excess cash to fund capital obligations and any additional excess cash would be used to pay down our existing revolving credit facility. The overall 2004 commodity prices for oil and natural gas will be the largest variable driving the different components of working capital. Our operating cash flow is determined in a large part by commodity prices. Assuming moderate to high commodity prices, our operating cash flow should remain positive for the remainder of 2004. We have revised our budgeted capital expenditures to approximately $175.5 million for 2004, which excludes capital required for acquisitions. The level of these and other future capital expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow, available cash, and our existing revolving credit facility.

     Contractual Obligations. The following table illustrates our contractual obligations and commercial commitments outstanding at June 30, 2004 (in thousands):

                                         
Contractual Obligations   Payments Due by Period
and Commitments
  Total
  2004
  2005 – 2006
  2007 – 2008
  Thereafter
8⅜% Notes, including interest
  $ 250,500     $ 6,281     $ 25,125     $ 25,125     $ 193,969  
6¼% Notes, including interest
    244,115       5,052       18,750       18,750       201,563  
Revolving credit facility, including interest
    56,166       791       55,375              
Derivative obligations
    35,468       11,195       20,142       4,131        
Development commitments
    52,705       50,835       1,270       600        
Operating leases
    2,355       464       1,507       341       43  
 
   
 
     
 
     
 
     
 
     
 
 
Totals
  $ 641,309     $ 74,618     $ 122,169     $ 48,947     $ 395,575  
 
   
 
     
 
     
 
     
 
     
 
 

Capital Resources

     Our primary capital resource is net cash provided by operating activities and proceeds from financing activities, which are used to fund our capital commitments. Our primary needs for cash include development and exploitation of our existing oil and natural gas properties, including our high-pressure air injection program in the CCA; acquisitions of oil and natural gas properties; acquisition of leasehold and acreage interest; funding of necessary working capital; and payment of contractual obligations.

     Operating Activities. For the first half of 2004, cash provided by operating activities increased by $23.3 million as compared to the same period in 2003. This increase resulted mainly from increases in revenues, which resulted from increased volumes and increased commodity prices.

     Financing Activities. In the second quarter of 2004 we increased the level of debt outstanding primarily as a result of issuance of the 6¼% Notes. The offering was made through a private placement. The initial purchasers resold the 6¼% Notes pursuant to Rule 144A and Regulation S. We received net proceeds of approximately $146.2 million after paying all costs associated with the offering. The net proceeds were used to fund the acquisition of Cortez and repay amounts outstanding under our revolving credit facility.

     On June 10, 2004, we issued and sold 2,000,000 shares of our common stock to the public at a price of $26.95 per share. The shares were sold under our prior shelf registration statement, which was declared effective by the SEC in August 2003. The net proceeds of the offering, after underwriting discounts and commissions and other expenses of the offering, were approximately $53.0 million. We used the net proceeds of this offering to repay indebtedness under our revolving credit facility and for general corporate purposes, including funding the previously announced purchase of natural gas properties in Overton Field in Smith County, Texas.

     Capitalization. At June 30, 2004, Encore had total assets of $1.0 billion. Total capitalization was $785.2 million, of which 55.0% was represented by stockholders’ equity and 45.0% by long-term debt. This compares to December 31, 2003 total assets of $672.1 million and total capitalization of $538.0 million. Total capitalization at December 31, 2003 was represented by stockholders’ equity

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of 66.7% and senior debt of 33.3%.

Liquidity

     Our principal source of short-term liquidity is our revolving credit facility. We entered into the current revolving credit facility on June 25, 2002. Borrowings under the facility are secured by a first priority lien on our proved oil and natural gas reserves. Availability under the facility is determined through semi-annual borrowing base determinations and may be increased or decreased. The amount available under our revolving credit facility is $270.0 million, with $53.0 million outstanding as of June 30, 2004. The maturity date of the facility is June 25, 2006.

Inflation and Changes in Prices

     While the general level of inflation affects certain of our costs, factors unique to the petroleum industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and natural gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on us.

     The following table indicates the average oil and natural gas prices realized for the three and six months ended June 30, 2004 and 2003. Average equivalent prices for the first half of 2004 and 2003 decreased by $3.41 and $2.49 per BOE, respectively, as a result of our hedging activities. Average prices per equivalent barrel indicate the composite impact of changes in oil and natural gas prices. Natural gas production volumes are converted to oil equivalents at the conversion rate of six Mcf per Bbl.

                         
    Oil   Natural Gas   Equiv. Oil
    (per Bbl)
  (per Mcf)
  (per BOE)
Net Price Realization with Hedges
                       
Quarter ended June 30, 2004
  $ 31.32     $ 5.37     $ 31.54  
Quarter ended June 30, 2003
    25.19       5.30       26.32  
Six months ended June 30, 2004
    30.20       5.19       30.42  
Six months ended June 30, 2003
    26.55       5.07       27.20  
Average Wellhead Price
                       
Quarter ended June 30, 2004
  $ 35.90     $ 5.59     $ 35.35  
Quarter ended June 30, 2003
    26.77       5.55       27.89  
Six months ended June 30, 2004
    34.26       5.38       33.82  
Six months ended June 30, 2003
    29.10       5.44       29.69  

Description of Critical Accounting Estimates

     For more information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Description of Critical Accounting Estimates” in Encore’s 2003 Annual Report filed on Form 10-K. There have been no material changes to our critical accounting estimates since December 31, 2003.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The information included in “Quantitative and Qualitative Disclosures about Market Risk” in Encore’s 2003 Annual Report filed on Form 10-K includes, among other things, a description of Encore’s potential exposure to market risks, including commodity price risk and interest rate risk. The Company’s outstanding derivative contracts as of June 30, 2004 are discussed in Note 8 to the accompanying consolidated financial statements in this quarterly report. As of June 30, 2004, the fair value of our open commodity and interest rate derivative contracts is $(33.1) million.

     Hedging policy. We have adopted a formal hedging policy. The purpose of our hedging program is to mitigate the negative effects of declining commodity prices on our business. The hedging policy is set by the President with input from the Chief Executive Officer and the Chief Financial Officer. We plan to continue in the normal course of business to hedge our exposure to fluctuating commodity prices. The volumes we have capped or swapped will not exceed 75% of our anticipated production from proved producing reserves. Under our hedging policy, we do not enter into derivatives for speculative purposes. However, not all of our derivatives qualify for hedge accounting and in some instances management has determined it is more cost effective not to designate certain derivatives as hedges.

     Hedging Margin Deposits and Letters of Credit. This amount represents the current mark-to-market liability of our commodity derivative contracts which exceeds the margin maintenance thresholds we have negotiated with our counterparties. Once a margin threshold is reached, we are required to maintain cash reserves in an account with the counterparty or post letters of credit in lieu of cash to ensure future settlement is made pursuant to our contracts. These funds are released back to us as our mark-to-market liability decreases due to either a drop in the futures price of oil and natural gas or due to the passage of time as settlements are made. As of July 30, 2004, we had $6.4 million cash deposited and $14.0 million letters of credit posted with two counterparties.

Item 4. Controls and Procedures

     In accordance with 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 Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2004 to provide reasonable assurance 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.

     There has been no change in our internal control over financial reporting that occurred during the three months ended June 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 4. Submission of Matters to a Vote of Security Holders

     The Company’s annual meeting of stockholders was held Thursday, April 29, 2004. The items submitted to stockholders for vote were the election of eight nominees to serve on the Company’s Board of Directors during 2004 and until the Company’s next annual meeting, and to amend and restate the Company’s 2000 Incentive Stock Plan. Notice of the meeting and proxy information was distributed to stockholders prior to the meeting in accordance with federal securities laws. There were no solicitations in opposition to the nominees or amendment of the 2000 Incentive Stock Plan.

Election of Directors

     Martin C. Bowen and John V. Genova have been elected to serve as new members to Encore’s Board of Directors. All of Encore’s previous directors have been re-elected, with the exception of Arnold L. Chavkin, who did not stand for re-election.

     Out of a total of 30,433,893 shares of the Company’s Common Stock outstanding and entitled to vote, 28,288,876 shares (92.95%) were present at the meeting in person or by proxy. The vote tabulation with respect to each nominee was as follows:

                 
            AUTHORITY
NOMINEE   FOR   WITHHELD
I. Jon Brumley
    28,002,776       286,100  
Jon S. Brumley
    28,090,606       198,270  
Howard H. Newman
    27,516,652       772,224  
Ted A. Gardner
    27,794,769       494,107  
Ted Collins, Jr.
    27,406,402       882,474  
James A. Winne, III
    27,406,502       882,374  
Martin C. Bowen
    28,088,876       200,000  
John V. Genova
    28,088,976       199,900  

Amendment and Restatement the Company’s 2000 Incentive Stock Plan

     The Board of Directors recommended that the Company’s stockholders approve and adopt the amended and restated 2000 Incentive Stock Plan (the “Plan”), which was approved.

     Out of a total of 30,433,893 shares of the Company’s Common Stock outstanding and entitled to vote, 28,288,876 shares (92.95%) were present at the meeting in person or by proxy. The vote tabulation with respect to amendment and restatement of the Plan was as follows:

                         
    FOR   AGAINST   ABSTAIN
Amendment and restatement of the Plan
    23,492,241       3,754,806       1,041,829  

Item 6. Exhibits and Reports on Form 8-K

Exhibits

2.1   Purchase and sale Agreement, dated as of April 26, 2004, among Dale Resources, L.L.C. et. al. and Encore Operating, L.P. (incorporated by reference to Exhibit 2.1 of the Company’s Form 8-K filed with the SEC on June 23, 2004).
 
2.2   Purchase and sale Agreement, dated as of April 26, 2004, between Overton Pipeline Company L.P. and EAP Energy Services, L.P. (incorporated by reference to Exhibit 2.2 of the Company’s Form 8-K filed with the SEC on June 23, 2004).
 
4.1   Indenture, dated as of April 2, 2004, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-4 (Registration No. 333-117025) filed with the SEC on June 30, 2004).

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4.2   Form of 6.25% Senior Subordinated Note to Cede & Co. or its registered assigns (included Exhibit A to Exhibit 4.1 above).
 
4.3   Registration Rights Agreement, dated as of April 2, 2004, among the Company and the other parties thereto (incorporated by reference to Exhibit 4.3 of the Company’s Registration Statement on Form S-4 (Registration No. 333-117025) filed with the SEC on June 30, 2004).
 
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)

Reports on Form 8-K

The Company filed with the SEC the following reports on Form 8-K during the quarter ended June 30, 2004:

On April 20, 2004, the Company filed a current report on Form 8-K under Items 2 and 7 announcing completion of the acquisition of Cortez Oil & Gas, Inc.

On April 28, 2004, the Company filed a current report on Form 8-K under Items 7 and 9 to furnish information regarding an agreement to acquire natural gas properties in Overton Field located in Smith County, Texas for $82 million from a group of private sellers.

On April 30, 2004, the Company filed a current report on Form 8-K under Items 5 and 7 announcing the appointment of Mr. Martin C. Bowen and Mr. John V. Genova to Encore’s Board of Directors.

On May 3, 2004, the Company filed a current report on Form 8-K to furnish information under Items 12 and 7 regarding quarter ended March 31, 2004 financial and operating results.

On June 8, 2004, the Company filed a current report on Form 8-K under Items 5 and 7 to furnish information regarding the issuance and sale of 2,000,000 shares of its common stock to the public at a price of $26.95 per share.

On June 23, 2004, the Company filed a current report on Form 8-K under Items 2 and 7 announcing completion of the acquisition of natural gas properties in Overton Field located in Smith County, Texas.

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SIGNATURES

     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: August 6, 2004  By:   /s/ Roy W. Jageman    
    Roy W. Jageman   
    Chief Financial Officer, Treasurer, Executive Vice President, Corporate Secretary, and Principal Financial Officer   
         
Date: August 6, 2004  By:   /s/ Robert C. Reeves    
    Robert C. Reeves   
    Vice President, Controller and Principal Accounting Officer   

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