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 September 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 (State or other jurisdiction of incorporation)	001-16295 (Commission File Number)	75-2759650 (IRS Employer Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

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

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 October 29, 2004 .............................................32,602,567

ENCORE ACQUISITION COMPANY
TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003		1
Consolidated Statements of Operations for the three and nine months ended September 30, 2004 and 2003		2
Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2004		3
Consolidated Statements of Cash Flows for the nine months ended September 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		12
Item 3. Quantitative and Qualitative Disclosures About Market Risk		23
Item 4. Controls and Procedures		23
PART II. OTHER INFORMATION
Item 6. Exhibits		24
Signatures		25
Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer)
Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer)
Section 1350 Certification (Principal Executive Officer)
Section 1350 Certification (Principal Financial Officer)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands except shares)


	September 30,			December 31,
	2004			2003
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,092		$	431
Hedge margin deposit		5,580			—
Accounts receivable		41,434			27,640
Inventory		6,304			6,019
Derivatives		1,792			5,588
Deferred taxes		15,602			3,592
Other		3,226			1,673

Total current assets		75,030			44,943

Properties and equipment, at cost — successful efforts method:
Proved properties		1,066,189			739,288
Unproved properties		31,353			921
Accumulated depletion, depreciation, and amortization		(156,855	)		(124,646	)

		940,687			615,563

Other property and equipment		10,199			3,831
Accumulated depreciation		(3,184	)		(2,586	)

		7,015			1,245

Goodwill		38,591			—
Debt issuance costs		9,612			5,304
Other		5,092			5,083

Total assets	$	1,076,027		$	672,138

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	23,876		$	10,668
Derivatives		38,545			8,026
Accrued and other		41,200			26,301

Total current liabilities		103,621			44,995

Derivatives		35,848			3,514
Future abandonment costs		6,953			5,341
Deferred taxes		131,729			80,313
Long-term debt		365,000			179,000

Total liabilities		643,151			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, 32,584,317 and 30,335,693 issued and outstanding		326			303
Additional paid-in capital		313,827			253,865
Deferred compensation		(5,169	)		(2,528	)
Retained earnings		173,272			117,365
Accumulated other comprehensive income		(49,380	)		(10,030	)

Total stockholders’ equity		432,876			358,975

Total liabilities and stockholders’ equity	$	1,076,027		$	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						Nine months ended
	September 30,						September 30,
	2004			2003			2004			2003
Revenues:
Oil	$	58,243		$	44,538		$	157,892		$	131,674
Natural gas		21,009			11,186			50,773			31,080

Total revenues		79,252			55,724			208,665			162,754

Expenses:
Production —
Lease operations		12,589			9,795			33,752			27,888
Production, ad valorem, and severance taxes		8,117			5,449			21,117			16,713
Depletion, depreciation, and amortization		12,750			8,471			33,262			23,957
General and administrative (excluding non-cash stock based compensation)		2,858			2,006			7,616			6,796
Derivative fair value (gain) loss		2,301			18			3,424			(1,818	)
Exploration		462			—			2,159			—
Non-cash stock based compensation		796			165			1,413			460
Other operating		1,369			1,031			3,462			1,913

Total expenses		41,242			26,935			106,205			75,909

Operating income		38,010			28,789			102,460			86,845

Other income (expenses):
Interest		(6,547	)		(4,016	)		(16,761	)		(12,226	)
Other		78			82			235			168

Total other income (expenses)		(6,469	)		(3,934	)		(16,526	)		(12,058	)

Income before income taxes and cumulative effect of accounting change		31,541			24,855			85,934			74,787
Current income tax provision		(1,042	)		(289	)		(3,046	)		(1,647	)
Deferred income tax provision		(9,485	)		(8,798	)		(26,981	)		(26,024	)

Income before cumulative effect of accounting change		21,014			15,768			55,907			47,116
Cumulative effect of accounting change, net of income taxes of $529		—			—			—			863

Net income	$	21,014		$	15,768		$	55,907		$	47,979

Income before cumulative effect of accounting change per common share:
Basic	$	0.65		$	0.52		$	1.80		$	1.57
Diluted		0.64			0.52			1.78			1.56
Net income per common share:
Basic	$	0.65		$	0.52		$	1.80		$	1.60
Diluted		0.64			0.52			1.78			1.58
Weighted average common shares outstanding:
Basic		32,297			30,103			31,074			30,071
Diluted		32,735			30,332			31,481			30,274

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

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
September 30, 2004
(in thousands)
(unaudited)


			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		2,833		—			—		—			2,834
Issuance of common stock		20		53,077		—			—		—			53,097
Deferred compensation:
Issuance of restricted common stock		2		3,332		(3,334	)		—		—			—
Amortization of expense		—		—		1,413			—		—			1,413
Other changes		—		720		(720	)		—		—			—
Components of comprehensive income:
Net income		—		—		—			55,907		—			55,907
Change in deferred hedge loss, net of income taxes of $24,118		—		—		—			—		(39,350	)		(39,350	)

Total comprehensive income														16,557

Balance at September 30, 2004	$	326	$	313,827	$	(5,169	)	$	173,272	$	(49,380	)	$	432,876

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

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)


	Nine months ended
	September 30,
	2004			2003
Operating activities
Net income	$	55,907		$	47,979
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization		33,262			23,957
Deferred taxes		26,981			26,179
Exploration expense		1,866			—
Non-cash derivative fair value (gain) loss		10,257			(874	)
Non-cash stock based compensation		1,413			460
Other non-cash		418			4,987
Cumulative effect of accounting change		—			(863	)
Loss on disposition of assets		179			362
Changes in operating assets and liabilities:
Hedge margin deposit		(5,580	)		—
Accounts receivable		(8,219	)		(853	)
Other current assets		(8,580	)		(1,752	)
Other assets		(341	)		(2,662	)
Accounts payable and accrued liabilities		19,537			(2,114	)

Cash provided by operating activities		127,100			94,806

Investing activities
Proceeds from disposition of assets		581			1,144
Purchases of other property and equipment		(7,900	)		(444	)
Acquisition of oil and natural gas properties		(111,532	)		(52,900	)
Acquisition of Cortez Oil & Gas, Inc. (net of cash acquired)		(123,792	)		—
Development of oil and natural gas properties		(123,171	)		(71,662	)

Cash used by investing activities		(365,814	)		(123,862	)

Financing activities
Proceeds from issuance of common stock		53,900			—
Payment of offering costs of common stock		(677	)		—
Proceeds from long-term debt		240,000			77,500
Payments on long-term debt		(204,000	)		(62,500	)
Proceeds from issuance of 6¼% notes		150,000			—
Payment of debt issuance costs		(4,792	)		—
Other		4,944			1,652

Cash provided by financing activities		239,375			16,652

Increase (decrease) in cash and cash equivalents		661			(12,404	)
Cash and cash equivalents, beginning of period		431			13,057

Cash and cash equivalents, end of period	$	1,092		$	653

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

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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 September 30, 2004, results of operations for the three and nine months ended September 30, 2004 and 2003, and cash flows for the nine months ended September 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.

The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive. All costs associated with both development and exploratory wells are shown as ‘Development of oil and natural gas properties’ in the ‘Investing activities’ section of the Consolidated Statement of Cash Flows. If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs are expensed in the Consolidated Statement of Operations and shown as a non-cash adjustment to net income in the ‘Operating activities’ section of the Consolidated Statement of Cash Flows in the period in which the determination was made. If a determination cannot be made within one year of the exploration well being drilled and no other drilling or exploration activities to evaluate the discovery are firmly planned, all previously capitalized costs associated with the exploratory well are expensed and shown as a non-cash adjustment to net income at that time. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different or additional proven or unproven reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Internal costs directly associated with the development and exploitation of properties are capitalized as a cost of the property and are classified accordingly in our consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable.

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.” 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 nine months ended September 30, 2004, the Company awarded 124,657 shares of restricted stock under the Company’s 2000 Incentive Stock Plan, of which 57,161 shares vest in equal annual installments over the next three years

and 67,496 shares vest in equal annual installments in years three, four and five. The vesting of these grants is contingent only upon continued employment. There were no grants of restricted stock in the third quarter of 2004. Deferred compensation of $3.3 million was reclassified within equity from additional paid in capital during the nine months ended September 30, 2004 in conjunction with the grants, and will be expensed over the related periods from the grant dates to the vesting dates.

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				Nine months ended
	September 30,				September 30,
	2004		2003		2004		2003
As Reported:
Non-cash stock based compensation (net of taxes) (a)	$	494	$	102	$	876	$	285
Net income		21,014		15,768		55,907		47,979
Basic net income per common share		0.65		0.52		1.80		1.60
Diluted net income per common share		0.64		0.52		1.78		1.58
Pro Forma:
Non-cash stock based compensation (net of taxes)	$	814	$	516	$	1,738	$	1,459
Net income		20,694		15,354		55,045		46,805
Basic net income per common share		0.64		0.51		1.77		1.56
Diluted net income per common share		0.63		0.51		1.75		1.55

(a)

During the three months ended September 30, 2004, no employee stock options or shares of restricted stock were forfeited. During the nine months ended September 30, 2004, employee stock options with respect to 6,509 shares of common stock and 9,236 shares of restricted stock that 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 $127.0 million, which includes cash paid to Cortez’ former shareholders of $85.8 million, the repayment of $39.4 million of Cortez’ debt, and transaction costs incurred of $1.8 million.

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 Encore beginning on April 1, 2004.

The calculation of the total purchase price and the estimated allocation as of September 30, 2004 to 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		1,758

Total purchase price	$	127,000

Allocation of purchase price to the fair value of net assets acquired:
Cash	$	3,209
Current assets		5,644
Proved oil and gas properties		120,503
Unproved oil and gas properties		3,011
Goodwill		38,591

Total assets acquired		170,958

Current liabilities		(5,195	)
Non-current liabilities		(996	)
Deferred income taxes		(37,767	)

Total liabilities assumed		(43,958	)

Fair value of net assets acquired	$	127,000

The purchase price allocation resulted in $38.6 million of goodwill primarily as the result of the difference between the fair value of acquired oil and gas properties and their lower carryover tax basis, which resulted in deferred taxes of $37.8 million. 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 instead tested for impairment on a quarterly basis, using estimates related to the fair market value of the business operations of the reporting unit with which goodwill is associated. Currently, Encore has one reporting level. Losses, if any, resulting from impairment tests would be reflected in operating income in the Consolidated Statement of Operations.

4. Debt

Issuance of 6¼% 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 Company 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 Oil & Gas and repay amounts outstanding under our revolving credit facility. The offering was made through a private placement with the Company agreeing at that time to file a registration statement offering to exchange the 6¼% Notes for publicly registered notes with substantially identical terms. The Company filed an exchange offer registration statement on Form S-4 on June 30, 2004. The registration statement was subsequently declared effective by the SEC on July 14, 2004, and the related offer to exchange the outstanding 6¼% Notes for registered notes was launched on July 21, 2004. The exchange offer expired at 5:00 p.m., New York City time, on August 19, 2004 with 100% of the 6¼% Notes being tendered for exchange.

The publicly registered 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 publicly registered Notes contains certain affirmative, negative, and financial covenants identical to those of the 6¼% Notes, which include limitations on incurrence of additional debt, restrictions on asset dispositions and restricted payments, maintenance of a 1.0 to 1.0 current ratio, and maintenance of EBIDTA, as defined, to interest expense ratio of 2.5 to 1.0. As of September 30, 2004, the Company was in compliance with all covenants in the indenture.

Line of Credit Facility

On August 19, 2004, the Company entered into an amended and restated five-year senior secured credit facility with a bank syndicate comprised of Bank of America, N.A. and other lenders. Availability under the amended and restated credit facility is determined through semi-annual borrowing base determinations and may be increased or decreased. The initial borrowing base is $400 million and may be increased to up to $750 million. The initial borrowing base of $400 million reflects an increase of $130 million as compared to the Company’s $270 million borrowing base at December 31, 2003 and during the period of 2004 prior to August 19, 2004. The amended and restated credit facility matures on August 19, 2009. The amended and restated credit facility replaces the Company’s previous $300 million credit facility, which would have matured in June 2006.

Encore’s obligations under the amended and restated credit facility are guaranteed by its restricted subsidiaries and secured by a first priority-lien on substantially all of its proved oil and natural gas reserves and a pledge of the capital stock and equity interests of Encore’s restricted subsidiaries.

Amounts outstanding under the amended and restated credit facility are subject to varying rates of interest based on (1) the amount outstanding under the amended and restated credit facility in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. The following table summarizes the calculation of the various interest rates for both Eurodollar and Base Rate loans:


Ratio of Total Outstanding to Borrowing Base	Eurodollar Loans (a)	Base Rate Loans (b)
Less than .40 to 1	LIBOR + 1.000%	Base Rate + 0.000%
From .40 to 1 but less than .75 to 1	LIBOR + 1.250%	Base Rate + 0.000%
From .75 to 1 but less than .90 to 1	LIBOR + 1.500%	Base Rate + 0.250%
.90 to 1 or greater	LIBOR + 1.750%	Base Rate + 0.500%

(a)		The LIBOR rate is equal to the rate determined by Bank of America, N.A. to be the British Bankers Association Interest Settlement Rate for deposits in dollars for a similar interest period (either one, two, three or six months, or such other period as selected by Encore, subject to availability at each lender).

(b)		The Base Rate is calculated as the highest of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5%.

The borrowing base will be redetermined each June 1 and December 1, commencing June 1, 2005. The bank syndicate has the ability to request one additional borrowing base redetermination per year, and Encore is permitted to request two additional borrowing base redeterminations per year. Generally, if amounts outstanding ever exceed the borrowing base, Encore must reduce the amounts outstanding to the redetermined borrowing base within six months, provided that if amounts outstanding exceed the borrowing base as a result of any sale of Encore’s assets or permitted subordinated debt, Encore must reduce the amounts outstanding immediately upon consummation of the sale.

Borrowings under the amended and restated credit facility may be repaid from time to time without penalty.

The amended and restated credit facility contains certain affirmative, negative, and financial covenants which include limitations on incurrence of additional debt, restrictions on asset dispositions and restricted payments, maintenance of a 1.0 to 1.0 current ratio, and maintenance of EBIDTA, as defined, to interest expense ratio of 2.5 to 1.0. As of September 30, 2004, the Company was in compliance with all covenants in the amended and restated credit facility.

As of September 30, 2004, Encore had $65.0 million outstanding under the facility. This reflects an increase of $36.0 million to the outstanding balance under the facility at December 31, 2003.

Letters of Credit

The Company had $30.4 million of outstanding letters of credit at September 30, 2004. These letters of credit are posted primarily with two counterparties to the Company’s commodity derivative contracts and are used in lieu of cash margin deposits with those counterparties.

5. Asset Retirement Obligations

Under SFAS 143, “Accounting for Asset Retirement Obligations,” the Company must 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.

The Company adopted SFAS 143 on January 1, 2003 and recorded 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):


	Nine months ended
	September 30,
	2004		2003
As Reported:
Net income	$	55,907	$	47,979
Basic net income per common share		1.80		1.60
Diluted net income per common share		1.78		1.58
Pro Forma:
Net income	$	55,907	$	47,116
Basic net income per common share		1.80		1.57
Diluted net income per common share		1.78		1.56

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 September 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 December 31, 2003 through September 30, 2004 (in thousands):


Future abandonment liability at December 31, 2003	$	5,341
Property acquisitions		1,164
Wells drilled		318
Accretion expense		231
Plugging and abandonment costs incurred		(101	)

Future abandonment liability at September 30, 2004	$	6,953

6. Income Taxes

The Company’s effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax paying companies. Currently, the Company’s effective tax rate varies primarily as the amount of Section 43 income tax credits generated varies from period to period. These credits are generated by paying or incurring certain costs in connection with a qualifying enhanced oil recovery project, such as the Company’s current high-pressure air injection projects underway in the CCA. The Company’s effective tax rate is also affected by changes in the allocation of property, payroll, and revenues between states in which the Company owns property as rates vary from state to state.

Reconciliation of income tax expense for the nine months ended September 30, 2004 and 2003 with tax at the Federal statutory rate is as follows (in thousands):


	Nine months ended
	September 30,
	2004			2003
Income before income taxes and cumulative effect of accounting change	$	85,934		$	74,787

Tax at statutory rate		30,077			26,175
State income taxes, net of federal benefit		2,578			2,244
Section 43 credits generated		(2,507	)		(805	)
Other		(121	)		57

Total	$	30,027		$	27,671

7. Earnings Per Share (“EPS”)

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2004		2003		2004		2003
Numerator:
Income before cumulative effect of accounting change	$	21,014	$	15,768	$	55,907	$	47,116
Cumulative effect of accounting change		—		—		—		863

Net income	$	21,014	$	15,768	$	55,907	$	47,979

Denominator:
Denominator for basic earnings per share – weighted average shares outstanding		32,297		30,103		31,074		30,071
Effect of dilutive options and dilutive restricted stock (a)		438		229		407		203

Denominator for diluted earnings per share		32,735		30,332		31,481		30,274

Basic earnings per common share:
Income before cumulative effect of accounting change	$	0.65	$	0.52	$	1.80	$	1.57
Cumulative effect of accounting change, net of income taxes		—		—		—		0.03

Net income	$	0.65	$	0.52	$	1.80	$	1.60

Diluted earnings per common share:
Income before cumulative effect of accounting change	$	0.64	$	0.52	$	1.78	$	1.56
Cumulative effect of accounting change, net of income taxes		—		—		—		0.02

Net income	$	0.64	$	0.52	$	1.78	$	1.58

(a)

There were no shares of antidilutive restricted stock outstanding for the three months ended September 30, 2004 and 2003. For the quarter ended September 30, 2004, outstanding employee stock options of 25,000 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 September 30, 2004:

Oil Derivative Instruments at September 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)
Oct – Dec 2004		15,500	$	24.23		6,000	$	29.37		500	$	26.48	$	(11,819	)
Jan – June 2005		15,500		27.55		3,500		31.89		1,000		25.12		(12,973	)
July – Dec 2005		12,500		27.84		2,500		31.07		1,000		25.12		(7,958	)
Jan – Dec 2006		1,000		27.50		1,000		29.88		2,000		25.03		(13,840	)
Jan – Dec 2007		—		—		—		—		2,000		25.11		(8,208	)

Natural Gas Derivative Instruments at September 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)
Oct – Dec 2004		15,000	$	4.02		7,500	$	6.03		15,000	$	5.47	$	(1,876	)
Jan – Dec 2005		10,000		4.84		5,000		5.97		12,500		4.99		(9,470	)
Jan – Dec 2006		5,000		4.85		5,000		5.68		12,500		5.08		(5,782	)
Jan – Dec 2007		—		—		—		—		10,000		4.99		(1,786	)

Encore recognizes in the Consolidated Statement of Operations derivative fair value gains and losses for the following: changes in the mark-to-market value of the Company’s basis swaps and certain other commodity derivatives that are not designated as hedges for accounting purposes; ineffectiveness of commodity derivative contracts designated as cash flow hedges for accounting purposes; 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 September 30, 2004, the mark-to-market value of these contracts was $(0.1) million.

Additionally, at September 30, 2004, the Company had oil put contracts for 2,500 Bbls per day and natural gas put contracts for 5,000 Mcf per day in the last quarter of 2004 that had not been designated as hedges for accounting purposes. As of September 30, 2004, the mark-to-market value of these contracts was nominal.

Interest Rate Derivative

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


				Encore			Fair Value
Contract Expiration	Notional Amount		Encore Pays	Receives			(000s)
June 2005	$	80,000,000	LIBOR + 3.89%		8.375	%	$	1,371

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 September 30, 2004, a loss of $0.4 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 September 30, 2004 due to fluctuation of prices in the commodities markets.

9. Financial Statements of Subsidiary Guarantors

As of September 30, 2004, all of the Company’s subsidiaries were subsidiary guarantors of the Company’s outstanding 8 3/8% notes 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.

Third Quarter 2004 Highlights

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

•

During the third quarter of 2004, we had quarterly net income of $21.0 million ($0.64 per diluted share), which represents an increase of 33% over third quarter 2003 net income of $15.8 million ($0.52 per diluted share). Higher production volumes and commodity prices resulted in record oil and natural gas revenues of $79.3 million for the third quarter of 2004. This represents a 42% increase over the $55.7 million of oil and natural gas revenues reported for the third quarter of 2003. Our average net combined price rose to $33.42 per BOE for the third quarter of 2004 over the $26.73 per BOE reported in the third quarter of 2003. The oil and natural gas industry has benefited from escalating commodity prices in 2004. This can be seen in the rise in the average NYMEX oil price from $30.20 per Bbl in the third quarter of 2003 to $43.92 per Bbl in the third quarter of 2004. The average natural gas NYMEX price rose from $4.89 per Mcf in the third quarter of 2003 to $5.56 per Mcf in the third quarter of 2004.

•

Our earnings were driven by record production volumes averaging 25,779 BOE per day in the third quarter of 2004 as compared to 22,663 BOE per day in the third quarter of 2003, an increase of 14%. During the current quarter, oil production averaged 18,419 Bbls per day and natural gas production averaged 44,160 Mcf per day. Natural gas production volumes in the current quarter reflect an increase of 67% over the level reported in the third quarter of 2003 as a result of our Elm Grove, Cortez, and Overton acquisitions.

•

Lease operations expense increased from $4.70 per BOE reported in the third quarter of 2003 to $5.31 per BOE in the third 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, acquisitions we made with higher per BOE expenses, and an increase in prices paid for outside services. General and administrative expense increased from $0.96 per BOE in the third quarter of 2003 to $1.21 per BOE in the third quarter of 2004 as we have increased staffing levels to manage our growing asset base and compliance services incurred in connection with Sarbanes-Oxley. DD&A expense per BOE of $5.38 for the third quarter of 2004 increased, as expected, from the $4.06 per BOE recorded for the third quarter of 2003 resulting from higher than historical finding, development, and acquisition costs.

•

We invested $52.8 million in development and exploitation projects during the third 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 remaining capital was invested primarily in 32 (29.4 net) new operated vertical producing wells, 7 (6.5 net) horizontal wells, 8 (7.9 net) operated horizontal re-entry wells, and 6 (5.6 net) operated service/injection wells. We also participated in the drilling of 19 (2.7 net) non-operated vertical producing wells and 1 (0.02 net) non-operated service well.

•

Recent acquisitions include the acquisition of natural gas properties in the Overton Field located in Smith County, Texas which closed on June 16, 2004 and has been included in our Consolidated Statement of Operations beginning in July 2004.

•

On August 19, 2004 we entered into an amended and restated five-year senior secured credit facility with an initial borrowing base of $400 million.

Results of Operations

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


	Three months ended						Nine months ended
	September 30,						September 30,
					Increase /						Increase /
	2004		2003		(Decrease)		2004		2003		(Decrease)
Operating results (in thousands):
Oil and natural gas revenues	$	79,252	$	55,724	$	23,528	$	208,665	$	162,754	$	45,911
Lease operations expense		12,589		9,795		2,794		33,752		27,888		5,864
Production, ad valorem, and severance taxes		8,117		5,449		2,668		21,117		16,713		4,404
Daily production volumes:
Oil (Bbls)		18,419		18,255		164		18,226		18,172		54
Natural gas (Mcf)		44,160		26,447		17,713		35,751		23,278		12,473
Combined (BOE)		25,779		22,663		3,116		24,184		22,052		2,132
Average prices:
Oil (per Bbl)	$	34.37	$	26.52	$	7.85	$	31.62	$	26.54	$	5.08
Natural gas (per Mcf)		5.17		4.60		0.57		5.18		4.89		0.29
Combined (per BOE)		33.42		26.73		6.69		31.49		27.04		4.45
Selected operating expenses per BOE:
Lease operations	$	5.31	$	4.70	$	0.61	$	5.09	$	4.63	$	0.46
Production, ad valorem, and severance taxes		3.42		2.61		0.81		3.19		2.78		0.41
DD&A		5.38		4.06		1.32		5.02		3.98		1.04
G&A (excluding non-cash stock based compensation)		1.21		0.96		0.25		1.15		1.13		0.02

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

Set forth below is our comparison of operations during the third quarter of 2004 with the third 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 September 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 September 30,
													Increase /
	2004						2003						(Decrease)
	Revenue			$/Unit			Revenue			$/Unit			Revenue			$/Unit
Revenues:
Oil wellhead	$	68,484		$	40.41		$	47,123		$	28.07		$	21,361		$	12.34
Oil hedges		(10,241	)		(6.04	)		(2,585	)		(1.55	)		(7,656	)		(4.49	)

Total Oil Revenues	$	58,243		$	34.37		$	44,538		$	26.52		$	13,705		$	7.85

Natural gas wellhead	$	21,551		$	5.30		$	11,375		$	4.68		$	10,176		$	0.62
Natural gas hedges		(542	)		(0.13	)		(189	)		(0.08	)		(353	)		(0.05	)

Total Natural Gas Revenues	$	21,009		$	5.17		$	11,186		$	4.60		$	9,823		$	0.57

Combined wellhead	$	90,035		$	37.97		$	58,498		$	28.06		$	31,537		$	9.91
Combined hedges		(10,783	)		(4.55	)		(2,774	)		(1.33	)		(8,009	)		(3.22	)

Total Combined Revenues	$	79,252		$	33.42		$	55,724		$	26.73		$	23,528		$	6.69


			Average				Average				Average
			NYMEX				NYMEX				NYMEX
	Production		$/Unit		Production		$/Unit		Production		$/Unit
Other data:
Oil (Bbls)		1,695	$	43.92		1,679	$	30.20		16	$	13.72
Natural Gas (Mcf)		4,063		5.56		2,433		4.89		1,630		0.67
Combined (BOE)		2,372				2,085				287

Oil revenues increased from third quarter of 2003 to third quarter of 2004 by $13.7 million, primarily due to higher realized average oil prices. Our realized average oil price increased $7.85 per Bbl in the third quarter of 2004 over the same period in 2003 primarily as a result of a $12.34 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 $13.72 per Bbl increase in the average NYMEX price during the third quarter of 2004 over the same period in 2003. We did not realize the entire benefit from the rise in NYMEX oil prices, however, because of a $4.49 per Bbl reduction resulting from our hedge positions. We strive to protect against a portion of the downside commodity risk while maintaining exposure to upside potential from rising commodity prices.

Natural gas revenues increased by $9.8 million in the third quarter of 2004 compared to the third quarter of 2003 due to an increase in volumes and an increase in our realized average natural gas price. Production volumes increased 1,630 MMcf in the third quarter of 2004 as compared to the third quarter of 2003 due to the Elm Grove acquisition, which was completed during the third quarter of 2003 and the Cortez and Overton acquisitions, which were completed in the second quarter of 2004. The third quarter of 2004 was the first period the Overton acquisition was included in our Consolidated Statement of Operations. Consistent with the $0.67 per Mcf increase in the average NYMEX price, our wellhead price increased $0.62 per Mcf during the third quarter of 2004, of which we realized $0.57 per Mcf. The $0.05 per Mcf difference is due to hedging.

Lease operations expense. Lease operations expense for the third quarter of 2004 increased as compared to the third quarter of 2003 by $2.8 million. The increase is primarily attributable to an increase in production volumes attributable to the Elm Grove, Cortez, and Overton acquisitions. Lease operations expense per BOE increased by $0.61 during the third quarter of 2004 which contributed to the overall increase in expense. 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, acquisitions we have made with higher per BOE expenses, and an increase in prices paid for outside services.

Production, ad valorem, and severance taxes. Production, ad valorem, and severance taxes for the third quarter of 2004 increased as compared to the same period in 2003 by approximately $2.7 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 third quarter of 2004 decreased slightly when compared to the third quarter of 2003, down to 9.0% from 9.3%. The decrease is attributable to the addition of the Elm Grove, Cortez and Overton properties, 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.

Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense for the third quarter of 2004 increased by $4.3 million as compared to the third quarter of 2003, due to a $1.32 increase in the per BOE rate and an increase in production. The per BOE rate increased, as expected, from the $4.06 per BOE recorded in the third quarter of 2003 to $5.38 in the third quarter of 2004 as a result of higher than historical finding, development, and acquisition costs primarily related to our recent acquisitions.

General and administrative (“G&A”) expense. G&A expense (excluding non-cash stock based compensation) increased $0.9 million for the third quarter of 2004 as compared to the third quarter of 2003. The overall increase is primarily a result of increased staffing levels to manage our growing asset base and mostly nonrecurring compliance services for 2004 incurred resulting from new requirements of the Sarbanes-Oxley Act of 2002. G&A expense (excluding non-cash stock based compensation) also increased on a per BOE basis from $0.96 in the third quarter of 2003 to $1.21 per BOE in the third quarter of 2004.

Derivative fair value (gain) loss. During the third quarter of 2004, we recorded a $2.3 million derivative fair value loss as compared to a nominal loss recorded in the third 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 September 30,
							Increase /
	2004			2003			(Decrease)
Designated cash flow hedges:
Ineffectiveness – Commodity contracts	$	2,740		$	27		$	2,713
Undesignated derivative contracts:
Mark-to-market (gain) loss – Interest rate swap		(383	)		134			(517	)
Mark-to-market (gain) loss – Commodity contracts		(56	)		(143	)		87

Derivative fair value (gain) loss	$	2,301		$	18		$	2,283

Exploration expense. Exploration expense was $0.5 million for the three months ended September 30, 2004 as compared to zero for the same period in 2003. This expense is mainly attributable to impairment of unproved acreage.

Non-cash stock based compensation expense. Non-cash stock based compensation expense increased $0.6 million from the three months ended September 30, 2003 to the three months ended September 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 the number of shares rewarded and an increase in our stock price.

Other operating expense. Other operating expense for the third quarter of 2004 increased by $0.3 million as compared to the third quarter of 2003. This increase is primarily attributable to higher third party transportation expenses and higher accretion expense related to our future abandonment liability.

Interest expense. Interest expense increased $2.5 million in the quarter ended September 30, 2004 compared to the quarter ended September 30, 2003. The increase in interest expense is primarily due to the issuance of the 6¼% Notes in the second quarter of 2004. The weighted average interest rate, net of hedges, for the third quarter of 2004 was 7.1% compared to 9.0% for the third quarter of 2003, as the 6¼% rate on the notes issued in the second quarter of 2004 is lower than our historical average rate. The following table illustrates the components of interest expense for the three months ended September 30, 2004 and 2003 (in thousands):


	Three months ended September 30,
					Increase /
	2004		2003		(Decrease)
8⅜% notes due 2012	$	3,141	$	3,141	$	—
6¼% notes due 2014		2,344		—		2,344
Revolving credit facility		467		161		306
Interest rate hedges (a)		109		414		(305	)
Letters of credit		77		—		77
Debt issuance cost amortization		248		179		69
Banking fees and other		161		121		40

Total	$	6,547	$	4,016	$	2,531

(a)

Amount represents non-cash amortization of the deferred loss on interest rate swaps from other comprehensive income to interest expense. This deferred 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 third quarter of 2004 increased as compared to the third quarter of 2003 by $1.4 million. This increase is due in part to the $6.7 million increase in income before income taxes, offset by a decrease in our effective tax rate from 36.6% in the third quarter of 2003 to 33.4% in the third 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 third quarter of 2004 as compared to the third quarter of 2003. Section 43 credits increased from $1.25 million during the third quarter of 2003 to $1.36 million during the third quarter of 2004. The Section 43 credits earned on qualifying expenditures in 2005 may be phased out ratably if the average wellhead price of uncontrolled domestic oil during 2004 exceeds $36.27 per Bbl up to a complete phase-out at $42.27. As the average wellhead price of uncontrolled domestic oil during 2004 has not yet been published by the Internal Revenue Service, we do not currently know with certainty what effect this phase-out will have on our future income tax expense.

Comparison of Nine Months Ended September 30, 2004 to Nine Months Ended September 30, 2003

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

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


	Nine months ended September 30,
													Increase /
	2004						2003						(Decrease)
	Revenue			$/Unit			Revenue			$/Unit			Revenue			$/Unit
Revenues:
Oil wellhead	$	181,500		$	36.35		$	142,599		$	28.74		$	38,901		$	7.61
Oil hedges		(23,608	)		(4.73	)		(10,925	)		(2.20	)		(12,683	)		(2.53	)

Total Oil Revenues	$	157,892		$	31.62		$	131,674		$	26.54		$	26,218		$	5.08

Natural gas wellhead	$	52,420		$	5.35		$	32,728		$	5.15		$	19,692		$	0.20
Natural gas hedges		(1,647	)		(0.17	)		(1,648	)		(0.26	)		1			0.09

Total Natural Gas Revenues	$	50,773		$	5.18		$	31,080		$	4.89		$	19,693		$	0.29

Combined wellhead	$	233,920		$	35.30		$	175,327		$	29.12		$	58,593		$	6.18
Combined hedges		(25,255	)		(3.81	)		(12,573	)		(2.08	)		(12,682	)		(1.73	)

Total Combined Revenues	$	208,665		$	31.49		$	162,754		$	27.04		$	45,911		$	4.45



			Average				Average				Average
			NYMEX				NYMEX				NYMEX
	Production		$/Unit		Production		$/Unit		Production		$/Unit
Other data:
Oil (Bbls)		4,994	$	39.13		4,961	$	30.99		33	$	8.14
Natural Gas (Mcf)		9,796		5.78		6,355		5.51		3,441		0.27
Combined (BOE)		6,626				6,020				606

Oil revenues increased from the first nine months of 2003 to the first nine months of 2004 by $26.2 million, primarily due to a higher realized average oil price. Our realized average oil price increased $5.08 per Bbl for the nine months ended September 30, 2004 over the same period in 2003 primarily as a result of an increase in our average wellhead price. The $7.61 per Bbl increase in our average wellhead price during the first nine months of 2004 is in line with the increase in the overall market price for oil as reflected in the $8.14 per Bbl increase in the average NYMEX price over the same period in 2003. We did not realize the entire benefit from the rise in NYMEX oil prices because of the $2.53 per Bbl reduction resulting from our hedge positions. We strive to protect against a portion of the downside commodity risk while maintaining exposure to upside potential from rising commodity prices.

Natural gas revenues increased by $19.7 million for the nine months ended September 30, 2004 over the same period in 2003 primarily due to an increase in volumes. Production volumes increased 3,441 MMcf for the nine months ended September 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 and Overton acquisitions, which were 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. The third quarter of 2004 was the first period operating results of properties acquired in the Overton acquisition was included in our Consolidated Statement of Operations.

Lease operations expense. Lease operations expense for the nine months ended September 30, 2004 increased as compared to the same period in 2003 by $5.9 million. The increase is primarily attributable to the production from the Elm Grove, Cortez and Overton acquisitions. Lease operations expense per BOE increased by $0.46, which contributed to the overall increase in expense. 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, acquisitions we made with higher per BOE expenses and an increase in prices paid for outside services.

Production, ad valorem, and severance taxes. Production, ad valorem, and severance taxes increased by approximately $4.4 million for the nine months ended September 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 nine months of 2004 decreased when compared to the same period in 2003, down to 9.0% from 9.5%. The decrease is attributable to the addition of the Elm Grove, Cortez and Overton properties, 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.

Depletion, depreciation, and amortization expense. DD&A expense for the first nine months of 2004 increased by $9.3 million as compared to the same period in 2003, due to a $1.04 increase in the per BOE rate and an increase in production. The per BOE rate increased, as expected, from the $3.98 per BOE recorded for the nine months ended September 30, 2003 to $5.02 for the nine months ended September 30, 2004 as a result of higher than historical finding, development, and acquisition costs related primarily to our recent acquisitions.

General and administrative expense. G&A expense (excluding non-cash stock based compensation) increased by $0.8 million for the nine months ended September 30, 2004 over the same period in 2003. The overall increase is primarily a result of increased staffing levels and professional assistance added to maintain the Company’s larger asset base and mostly nonrecurring compliance services for 2004 incurred resulting from new requirements of the Sarbanes-Oxley Act of 2002. G&A expense (excluding non-cash stock based compensation) also increased 2% on a per BOE basis from $1.13 in the nine months ended September 30, 2003 to $1.15 per BOE in the nine months ended September 30, 2004.

Derivative fair value (gain) loss. During the first nine months of 2004, we recorded a $3.4 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 nine month periods are as follows (in thousands):


	Nine months ended September 30,
						Increase /
	2004		2003			(Decrease)
Designated cash flow hedges:
Ineffectiveness – Commodity contracts	$	3,195	$	177		$	3,018
Undesignated derivative contracts:
Mark-to-market (gain) loss – Interest rate swap		37		(2,308	)		2,345
Mark-to-market (gain) loss – Commodity contracts		192		313			(121	)

Derivative fair value (gain) loss	$	3,424	$	(1,818	)	$	5,242

Exploration expense. Exploration expense was $2.2 million for the nine months ended September 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 in the second quarter of 2004 and impairment of unproved acreage.

Non-cash stock based compensation expense. Non-cash stock based compensation expense increased $1.0 million from the nine months ended September 30, 2003 to the nine months ended September 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 the number of shares rewarded and an increase in our stock price. During the nine months ended September 30, 2004, we awarded 124,657 shares of restricted stock under the Company’s 2000 Incentive Stock Plan, of which 57,161 shares vest in equal annual installments over the next three years, and 67,496 shares vest in equal annual installments in years three, four and five. The vesting of these grants is contingent only upon continued employment. Deferred compensation of $3.3 million was reclassified within equity from additional paid in capital during the nine months ended September 30, 2004 in conjunction with the grants, and will be expensed over the related periods from the grant dates to the vesting dates.

Other operating expense. Other operating expense for the nine months ended September 30, 2004 increased by $1.5 million as compared to the same period in 2003. This increase is attributable to higher third party expenses related to transportation of our products to market in 2004, 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 $4.5 million in the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003. The increase in interest expense is due to the issuance of the 6¼% Notes, offset somewhat 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 nine months of 2004 was 7.7% compared to 9.9% in the same period in 2003 as our average interest rate benefited from the issuance of the 6¼% Notes during the second quarter of 2004. The following table illustrates the components of interest expense for the nine months ended September 30, 2004 and 2003 (in thousands):


	Nine months ended September 30,
					Increase /
	2004		2003		(Decrease)
8⅜% notes due 2012	$	9,422	$	9,422	$	—
6¼% notes due 2014		4,661		—		4,661
Revolving credit facility		908		278		630
Interest rate hedges (a).		475		1,612		(1,137	)
Letters of credit		99		—		99
Debt issuance cost		706		531		175
Banking fees and other		490		383		107

Total	$	16,761	$	12,226	$	4,535

(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 first nine months of 2004 increased as compared to the first nine months of 2003 by $2.4 million. This increase is due in part to the $11.1 million increase in income before income taxes offset by a decrease in our effective tax rate from 37.0% in the first nine months of 2003 to 34.9% in the first nine months 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 Cedar Creek Anticline properties during the first nine months of 2004 as compared to the same period in 2003. Section 43 credits increased from $1.3 million during the first nine months of 2003 to $4.0 million during the same period in 2004. The Section 43 credits earned on qualifying expenditures in 2005 may be phased out ratably if the average wellhead price of uncontrolled domestic oil during 2004 exceeds $36.27 per Bbl up to a complete phase-out at $42.27. As the average wellhead price of uncontrolled domestic oil during 2004 has not yet been published by the Internal Revenue Service, we do not currently know with certainty what effect this phase-out will have on our future income tax expense.

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 6¼% notes on April 2, 2004 and the issuance of 2 million shares on June 10, 2004 with net proceeds of approximately $53.2 million.

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 development and exploitation during the nine months ended September 30, 2004 totaled $122.1 million, including $26.2 million of capital expenditures for high-pressure air injection. For the remainder of 2004, we expect to invest approximately $53.0 million in development and exploitation, including $5.0 million for the HPAI projects. We also began a drilling program in the second half of 2004 primarily to test for shallow gas producing zones in the Rockies region of Montana. We expect to incur exploratory expenditures for geological and geophysical expenses, impairment of unproved acreage, and dry hole costs for the remainder of 2004 related to the program.

High-Pressure Air Injection. Our capital expenditures for high-pressure air injection during the first nine months of 2004 totaled $26.2 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 to 18 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 in the third quarter of 2005. For the remainder of 2004, we expect to invest approximately $5.0 million in high-pressure air injection.

Acquisitions. Our capital expenditures for acquisitions of proved oil and natural gas properties during the nine months ended September 30, 2004 totaled $204.8 million, which included $126.7 million related to the Cortez acquisition, $63.5 million related to the Overton Field acquisition, and $14.6 million related to other acquisitions.

Leasehold and Acreage Costs. Our capital expenditures for unproved property during the first nine months of 2004 totaled $30.4 million. Of the $30.4 million of capital expenditures for unproved property, $3.0 million and $18.4 million relate to the Cortez and Overton acquisitions respectively, $7.6 million relates to leases acquired in our Rockies region, and the remaining $1.4 million relates to unproved acreage spread over in our other core areas.

For the remainder of 2004, we expect to invest an additional $1.0 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 significant oil and natural gas production in 2004.

Other General Property and Equipment. Our capital expenditures for other general property and equipment during the first nine months of 2004 totaled $7.9 million. For the remainder of 2004, we expect to invest $0.5 million in other general property and equipment.

Working Capital. At September 30, 2004, our working capital was $(28.6) million while at December 31, 2003 working capital was $(0.1) million, a decrease of $28.5 million. The decrease is primarily attributable to changes in the fair value of outstanding derivative contracts. As of September 30, 2004, we have $5.6 million in cash and $30.0 in letters of credit posted with counterparties to our derivative contracts.

For the remainder of 2004, we expect working capital to remain relatively flat compared to the third quarter of 2004. 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 remaining 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 $175.0 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 September 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		79,696		466		3,730		3,730		71,770
Derivative obligations		75,956		16,889		49,072		9,995		—
Development commitments under AFE (1)		57,305		53,298		3,407		600		—
Operating leases		12,829		268		2,763		3,007		6,791

Totals	$	720,401	$	82,254	$	102,847	$	61,207	$	474,093

(1)

Development commitments represent authorized purchases not placed to vendors. These purchases are authorized and expected to be made unless circumstances change. Above amounts also include minimum transmission payments for electricity.

Capital Resources and Liquidity

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 nine months of 2004, cash provided by operating activities increased by $32.3 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. The oil and natural gas industry has benefited from escalating commodity prices in 2004. This can be seen in the rise in the average NYMEX oil price from $30.20 in the third quarter of 2003 to $43.92 in the third quarter of 2004. The average natural gas NYMEX price rose from $4.89 in the third quarter of 2003 to $5.56 in the third quarter of 2004.

Financing Activities. On April 2, 2004, we increased the level of debt outstanding as a result of the issuance of $150.0 million of 6¼% Notes. The offering was made through a private placement. The notes were subsequently exchanged for registered notes with substantially identical terms. 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 $53.2 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.

Our primary source of short-term liquidity is our revolving credit facility. On August 19, 2004, we entered into an amended and restated five-year senior secured credit facility with Bank of America, N.A., as administrative agent and line of credit issuer, Fortis Capital Corp. and Wachovia Bank, N.A., as co-syndication agents, BNP Paribas and Citibank, N.A., as co-documentation agents, and other lenders. Availability under the amended and restated credit facility is determined through semi-annual borrowing base determinations and may be increased or decreased. The initial borrowing base is $400 million and may be increased to up to $750 million. The amended and restated credit facility matures on August 19, 2009. The amended and restated credit facility replaces our previous $300 million credit facility, which had a $270 million borrowing base and would have matured in June 2006. As of October 29, 2004, we had $75.5 million outstanding under the facility.

Our obligations under the amended and restated credit facility are guaranteed by our restricted subsidiaries and secured by a first priority-lien on substantially all of our proved oil and natural gas reserves and a pledge of the capital stock and equity interests of our restricted subsidiaries.

Amounts outstanding under the amended and restated credit facility are subject to varying rates of interest based on (1) the amount outstanding under the amended and restated credit facility in relation to our borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. The following table summarizes the varying rates of interest under the amended and restated credit facility:


Ratio of Total Outstanding to Borrowing Base	Eurodollar Loans	Base Rate Loans
Less than .40 to 1	LIBOR + 1.000%	Base Rate + 0.000%
From .40 to 1 but less than .75 to 1	LIBOR + 1.250%	Base Rate + 0.000%
From .75 to 1 but less than .90 to 1	LIBOR + 1.500%	Base Rate + 0.250%
.90 to 1 or greater	LIBOR + 1.750%	Base Rate + 0.500%

The “LIBOR rate” is equal to the rate determined by Bank of America, N.A. to be the British Bankers Association Interest Settlement Rate for deposits in dollars for a similar interest period (either one, two, three or six months, or such other period as selected by Encore, subject to availability at each lender). The “base rate” is calculated as the highest of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5%.

The borrowing base is redetermined each June 1 and December 1, commencing June 1, 2005. The bank syndicate has the ability to request one additional borrowing base redetermination per year, and we are permitted to request two additional borrowing base redeterminations per year. Generally, if amounts outstanding ever exceed the borrowing base, we must reduce the amounts outstanding to the redetermined borrowing base within six months, provided that if amounts outstanding exceed the borrowing base as

a result of any sale of our assets or permitted subordinated debt, we must reduce the amounts outstanding immediately upon consummation of the sale.

Borrowings under the amended and restated credit facility may be repaid from time to time without penalty.

The amended and restated credit facility contains the following covenants, among others:

	•		a prohibition against incurring debt in excess of $30.0 million, except for borrowings under the amended and restated credit facility, up to $150 million of certain subordinated debt (which, if issued, could reduce our borrowing base by an amount equal to 33.33% of such debt), debt under hedge transactions and intercompany debt;

	•		a prohibition against paying dividends or purchasing or redeeming capital stock or prepaying indebtedness, subject to permitted exceptions;

	•		a restriction on creating liens on our assets, subject to permitted exceptions;

	•		restrictions on merging and selling assets outside the ordinary course of business;

	•		restrictions on use of proceeds, investments, transactions with affiliates, changing our principal business and incurring funding obligations under ERISA;

	•		a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75% of anticipated production from proved reserves;

	•		a requirement that we maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and

	•		a requirement that we maintain a ratio of consolidated EBITDA (as defined in the amended and restated credit facility) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.

The amended and restated credit facility contains customary events of default. If a default occurs and is continuing, we must repay all amounts outstanding under the amended and restated credit facility.

During the third quarter of 2004 we increased our outstanding letters of credit to $30.4 million at September 30, 2004, and $50.4 million at October 29, 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.

Capitalization. At September 30, 2004, Encore had total assets of $1.1 billion. Total capitalization was $797.9 million, of which 54.3% was represented by stockholders’ equity and 45.7% 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%.

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 nine months ended September 30, 2004 and 2003. Average equivalent prices for the first nine months of 2004 and 2003 were decreased by $3.81 and $2.08 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 September 30, 2004	$	34.37	$	5.17	$	33.42
Quarter ended September 30, 2003		26.52		4.60		26.73
Nine months ended September 30, 2004		31.62		5.18		31.49
Nine months ended September 30, 2003		26.54		4.89		27.04


	Oil		Natural Gas		Equiv. Oil
	(per Bbl)		(per Mcf)		(per BOE)
Average Wellhead Price
Quarter ended September 30, 2004	$	40.41	$	5.30	$	37.97
Quarter ended September 30, 2003		28.07		4.68		28.06
Nine months ended September 30, 2004		36.35		5.35		35.30
Nine months ended September 30, 2003		28.74		5.15		29.12

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, but as we started to maintain an active exploratory drilling program during the second half of 2004, the following update is necessary.

Successful efforts method. We utilize the successful efforts method of accounting for all of our oil and natural gas properties as opposed to the full cost method. Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive. All cost associated with both development and exploratory wells are shown as ‘Development of oil and natural gas properties’ in the ‘Investing activities’ section of the Consolidated Statement of Cash Flows. If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs are expensed in the Consolidated Statement of Operations and shown as a non-cash adjustment to net income in the ‘Operating activities’ section of the Consolidated Statement of Cash Flows in the period in which the determination was made. If a determination cannot be made within one year of the exploration well being drilled and no other drilling or exploration activities to evaluate the discovery are firmly planned, all previously capitalized costs associated with the exploratory well are expensed and shown as a non-cash adjustment to net income at that time. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different or additional proven or unproven reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Internal costs directly associated with the development and exploitation of properties are capitalized as a cost of the property and are classified accordingly in our consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable.

Forward-Looking Statements

This Form 10-Q includes forward-looking statements, which give Encore’s current expectations or forecasts of future events based on currently available information. Forward-looking statements in this Form 10-Q relate to, among other things, the following: expected capital expenditures and the focus of the Company’s capital program; the results of our HPAI program; the availability of Section 43 tax credits; our plans to pursue leases and acreage in our core areas; expectations regarding working capital; and borrowings under our credit facility. However, the assumptions of management and the future performance of Encore are subject to a wide range of business risks and uncertainties and there is no assurance that these statements and projections will be met. Factors that could affect Encore’s business include, but are not limited to: diversion of management’s attention from existing operations while pursuing acquisitions; difficulties completing and integrating acquisitions; complications resulting from increasing the scope and geographic diversity of Encore’s operations; inaccuracies in the assessment of reserves or daily or annual production with respect to acquisitions; inaccuracies in Encore’s assumptions regarding the expected revenues, lease operations expense, production taxes and other items of income and expense related to acquisitions; the amount, nature, and timing of capital expenditures and the drilling of wells; the timing and amount of future production of oil and natural gas; operating hazards; operating costs and other expenses; marketing of oil and natural gas; and other factors detailed in Encore’s most recent Form 10-K and other filings with the Securities and Exchange Commission. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. Encore undertakes no obligation to publicly update or revise any forward-looking statements.

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 September 30, 2004 are discussed in Note 8 to the accompanying consolidated financial statements in this quarterly report. As of September 30, 2004, the fair value of our open commodity and interest rate derivative contracts is $(73.6) 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. At any point in time, we have hedge margin deposits and letters of credit equal to the amount by which the current mark-to-market liability of our commodity derivative contracts 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 October 29, 2004, we had $6.0 million in cash deposited and $50.0 million in letters of credit posted with two of our 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 September 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 September 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 6. Exhibits


10.1		Amended and Restated Credit Agreement, dated as of August 19, 2004, among Encore Acquisition Company, as the Borrower, Encore Operating, L.P., as a Guarantor, Bank of America, N.A., as Administrative Agent and L/C Issuer, Fortis Capital Corp. and Wachovia Bank, N.A., as Co-Syndication Agents, BNP Paribas and Citibank, N.A., as Co-Documentation Agents, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Encore’s Current Report on Form 8-K dated August 19, 2004 and filed with the Securities and Exchange Commission on August 25, 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)

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: November 5, 2004	By:	/s/ Roy W. Jageman

		Roy W. Jageman
		Chief Financial Officer, Treasurer, Executive Vice President,
		Corporate Secretary, and Principal Financial Officer

Date: November 5, 2004	By:	/s/ Robert C. Reeves

		Robert C. Reeves
		Vice President, Controller and Principal
		Accounting Officer

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