Edgar Filing: ENCORE ACQUISITION CO

e10vq

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

[ ] 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
TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003		1
Consolidated Statements of Operations for the three and six months ended June 30, 2004 and 2003		2
Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2004		3
Consolidated Statements of Cash Flows for the six months ended June 30, 2004 and 2003		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		10
Item 3. Quantitative and Qualitative Disclosures About Market Risk		20
Item 4. Controls and Procedures		20
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders		21
Item 6. Exhibits and Reports on Form 8-K		21
Signatures		23
Rule 13a-14(a)/15d-14(a) Certification
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
Section 1350 Certification

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.

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.

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.

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.

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.

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

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):


	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

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.

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

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.

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	)

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

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

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.

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)

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.

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.

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

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.

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.

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.


	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).

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.

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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