UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

(Mark One)

þ		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2005

o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ___to ___

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware		75-2759650
(State or other jurisdiction		(IRS Employer
of incorporation)		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 þ No o

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

Yes þ No o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)

Yes o No þ

     Number of shares of Common Stock, $0.01 par value, outstanding as of November 4, 2005     49,372,655

 

 

ENCORE ACQUISITION COMPANY
INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004			1
Consolidated Statements of Operations for the three and nine months ended September 30, 2005 and 2004			2
Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2005			3
Consolidated Statements of Cash Flows for the nine months ended September 30, 2005 and 2004			4
Notes to Consolidated Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			13
Item 3. Quantitative and Qualitative Disclosures About Market Risk			28
Item 4. Controls and Procedures			28
PART II. OTHER INFORMATION
Item 6. Exhibits			30
Signatures			31
Certification of the Principal Executive Officer
Certification of the Principal Financial Officer
Certification of Principal Executive Officer
Certification of the Principal Financial Officer

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

     Certain information included in this Quarterly Report on Form 10-Q and other materials filed with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined by the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. These forward-looking statements give our current expectations or forecasts of future events. You can identify our forward-looking statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “forecast,” “budget” and other words and terms of similar meaning. Our actual results may differ significantly from the results discussed in the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in the subsection entitled “Factors That May Affect Future Results and Financial Condition” in our Annual Report on Form 10-K and in our other filings with the Securities and Exchange Commission. If one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands except shares and per share amounts)

		September 30,				December 31,
		2005				2004
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	2,554			$	1,103
Hedge margin deposits			1,600				—
Accounts receivable			69,385				43,839
Inventory			10,252				6,550
Derivatives			6,270				2,665
Deferred taxes			33,490				11,118
Other			4,899				5,842
Total current assets			128,450				71,117
Properties and equipment, at cost — successful efforts method:
Proved properties			1,418,591				1,134,220
Unproved properties			28,750				29,740
Accumulated depletion, depreciation, and amortization			(230,426	)			(171,691	)
			1,216,915				992,269
Other property and equipment			15,037				10,425
Accumulated depreciation			(4,831	)			(3,551	)
			10,206				6,874
Goodwill			37,908				37,995
Derivatives			11,905				1,150
Other			16,992				13,995
Total assets		$	1,422,376			$	1,123,400
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	22,430			$	24,375
Derivatives			84,483				24,270
Accrued and other current			76,069				38,038
Total current liabilities			182,982				86,683
Derivatives			59,920				31,477
Future abandonment costs			11,292				6,601
Other			13,482				—
Deferred taxes			169,907				146,064
Long-term debt			493,581				379,000
Total liabilities			931,164				649,825
Commitments and contingencies			—				—
Stockholders’ equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding			—				—
Common stock, $.01 par value, 144,000,000 authorized, 49,372,347 and 48,982,197 issued and outstanding			494				490
Additional paid-in capital			324,502				314,573
Deferred compensation			(8,964	)			(4,603	)
Retained earnings			265,756				199,512
Accumulated other comprehensive loss			(90,576	)			(36,397	)
Total stockholders’ equity			491,212				473,575
Total liabilities and stockholders’ equity		$	1,422,376			$	1,123,400

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,
		2005				2004				2005				2004
Revenues:
Oil		$	85,559			$	58,243			$	222,254			$	157,892
Natural gas			42,013				21,009				96,616				50,773
Total revenues			127,572				79,252				318,870				208,665
Expenses:
Production —
Lease operations			17,912				12,589				48,501				33,752
Production, ad valorem, and severance taxes			12,526				8,117				31,425				21,117
Depletion, depreciation, and amortization			24,222				12,750				59,943				33,262
Exploration			4,818				462				11,201				2,159
General and administrative (excluding non-cash stock based compensation)			4,030				2,858				11,236				7,616
Non-cash stock based compensation			1,544				796				3,323				1,413
Derivative fair value loss			1,612				2,301				5,713				3,424
Loss on early redemption of debt			19,477				—				19,477				—
Other operating			2,520				1,369				5,822				3,462
Total expenses			88,661				41,242				196,641				106,205
Operating income			38,911				38,010				122,229				102,460
Other income (expenses):
Interest			(9,264	)			(6,547	)			(23,671	)			(16,761	)
Other			580				78				729				235
Total other income (expenses)			(8,684	)			(6,469	)			(22,942	)			(16,526	)
Income before income taxes			30,227				31,541				99,287				85,934
Current income tax benefit (provision)			2,868				(1,042	)			1,478				(3,046	)
Deferred income tax provision			(12,241	)			(9,485	)			(34,459	)			(26,981	)
Net income		$	20,854			$	21,014			$	66,306			$	55,907
Net income per common share:
Basic		$	0.43			$	0.43			$	1.36			$	1.20
Diluted			0.42				0.43				1.34				1.18
Weighted average common shares outstanding:
Basic			48,703				48,446				48,659				46,611
Diluted			49,584				49,103				49,481				47,222

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

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
September 30, 2005
(in thousands)
(unaudited)

																										Accumulated
		Shares of								Additional																Other				Total
		Common				Common				Paid-In				Treasury				Deferred				Retained				Comprehensive				Stockholders’
		Stock				Stock				Capital				Stock				Compensation				Earnings				Loss				Equity
Balance at December 31, 2004			48,982			$	490			$	314,573			$	—			$	(4,603	)		$	199,512			$	(36,397	)		$	473,575
Exercise of stock options			137				1				2,381				—				—				—				—				2,382
Purchase of treasury stock			—				—				—				(195	)			—				—				—				(195	)
Cancellation of treasury stock			(7	)			—				(133	)			195				—				(62	)			—				—
Deferred compensation:
Issuance of restricted Common Stock			270				3				7,106				—				(7,109	)			—				—				—
Amortization to expense			—				—				—				—				3,323				—				—				3,323
Other changes			(10	)			—				575				—				(575	)			—				—				—
Components of comprehensive income:
Net income			—				—				—				—				—				66,306				—				66,306
Change in deferred hedge loss, net of income taxes of $32,275			—				—				—				—				—				—				(54,179	)			(54,179	)
Total comprehensive income																															12,127
Balance at September 30, 2005			49,372			$	494			$	324,502			$	—			$	(8,964	)		$	265,756			$	(90,576	)		$	491,212

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,
		2005				2004
Operating activities
Net income		$	66,306			$	55,907
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization			59,943				33,262
Dry hole expense			6,970				1,866
Deferred taxes			34,459				26,981
Non-cash stock based compensation			3,323				1,413
Non-cash derivative fair value loss			11,159				10,257
Loss on early redemption of debt			19,477				—
Other non-cash			2,799				418
Loss on disposition of assets			328				179
Changes in operating assets and liabilities:
Hedge margin deposit			(1,600	)			(5,580	)
Accounts receivable			(25,500	)			(8,219	)
Other current assets			(10,735	)			(8,580	)
Other assets			(16,359	)			(341	)
Accounts payable and accrued liabilities			53,622				19,537
Cash provided by operating activities			204,192				127,100
Investing activities
Proceeds from disposition of assets			604				581
Purchases of other property and equipment			(5,663	)			(7,900	)
Deposit on acquisition of oil and natural gas properties			(5,186	)			—
Acquisition of oil and natural gas properties			(49,770	)			(111,532	)
Acquisition of Cortez Oil & Gas, Inc. (net of cash acquired)			—				(123,792	)
Development and exploration of oil and natural gas properties			(237,003	)			(123,171	)
Cash used by investing activities			(297,018	)			(365,814	)
Financing activities
Proceeds from issuance of common stock			—				53,900
Payment of offering costs of common stock			—				(677	)
Proceeds from long-term debt			311,000				240,000
Payments on long-term debt			(341,000	)			(204,000	)
Proceeds from issuance of 6% notes			294,480				—
Redemption of 83/8% notes			(165,852	)			—
Proceeds from issuance of 61/4% notes			—				150,000
Payments of debt issuance costs			(739	)			(4,792	)
Cash overdrafts and other			(3,612	)			4,944
Cash provided by financing activities			94,277				239,375
Increase in cash and cash equivalents			1,451				661
Cash and cash equivalents, beginning of period			1,103				431
Cash and cash equivalents, end of period		$	2,554			$	1,092

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

ENCORE ACQUISITION COMPANY

(unaudited)

1. Formation of Encore

     Encore Acquisition Company, a Delaware corporation (“Encore” or the “Company”), is a growing independent energy company engaged in the acquisition, development, exploitation, exploration, and production of onshore 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 currently are located in four core areas: the Cedar Creek Anticline (“CCA”) in the Williston Basin of Montana and North Dakota; the Permian Basin of western Texas and southeastern New Mexico; the Mid-Continent area, which includes the Arkoma and Anadarko Basins of Oklahoma, the ArkLaTx region of northern Louisiana and eastern Texas and the Barnett Shale of northern Texas; and the Rockies, which includes non-CCA assets in the Williston and Powder River Basins of Montana, and the Paradox Basin of southeastern Utah.

2. Basis of Presentation

     In the opinion of management, the accompanying unaudited consolidated financial statements of Encore include all adjustments necessary to present fairly, in all material respects, our financial position as of September 30, 2005, results of operations for the three and nine months ended September 30, 2005 and 2004, and cash flows for the nine months ended September 30, 2005 and 2004. 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. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes thereto included in the Company’s 2004 Annual Report on Form 10-K.

     Certain balances reported in the Company’s 2004 Annual Report on Form 10-K have been reclassified to conform prior year data to the current period presentation.

Presentation of Number of Shares of Common Stock and Per Share Information

     As discussed at Note 11, “Stockholders’ Equity,” on June 15, 2005, the Company announced that its Board of Directors approved a three-for-two split of the Company’s outstanding common stock in the form of a stock dividend. The dividend was distributed on July 12, 2005, to stockholders of record at the close of business on June 27, 2005. All share and per-share information included in the accompanying consolidated financial statements and related notes thereto for all periods presented have been adjusted to retroactively reflect the stock split.

Stock-based Compensation

     Employee stock options and restricted stock awards are accounted for under the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Accordingly, no compensation is recorded for stock options that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on the grant date. However, compensation expense is recorded for the fair value of the restricted stock granted to employees.

     If compensation expense for the stock based awards had been determined using the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation,” the Company’s net income and net income per share 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,
		2005				2004				2005				2004
As Reported:
Non-cash stock based compensation (net of taxes)		$	968			$	494			$	2,082			$	876
Net income			20,854				21,014				66,306				55,907
Basic net income per common share			0.43				0.43				1.36				1.20
Diluted net income per common share			0.42				0.43				1.34				1.18
Pro Forma:
Non-cash stock based compensation (net of taxes)		$	1,715			$	814			$	3,333			$	1,738
Net income			20,107				20,694				65,055				55,045
Basic net income per common share			0.41				0.43				1.34				1.18
Diluted net income per common share			0.41				0.42				1.31				1.17

     There were 641,102 shares of restricted stock outstanding at September 30, 2005, of which 269,555 shares were granted during the nine months ended September 30, 2005. During the first nine months of 2005, 9,070 shares of restricted stock were forfeited. There were 1,496,438 stock options outstanding at September 30, 2005, of which 978,423 options were exercisable at September 30, 2005. There were 115,269 stock options granted during the nine months ended September 30, 2005.

New Accounting Standards

Statement of Financial Accounting Standards No. 123R, “Share-Based Payment”

     In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R is a revision of SFAS No. 123, “Accounting for Stock Based Compensation,” and supersedes APB 25. SFAS No. 123R eliminates the option of using the intrinsic value method of accounting previously available, and requires companies to recognize in the financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The effective date of SFAS No. 123R is January 1, 2006 for calendar year companies.

     SFAS No. 123R permits companies to adopt its requirements using either a “modified prospective” method, or a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial statements beginning with the effective date, based on the requirements of SFAS No. 123R, for all share-based payments granted after that date, and for all unvested awards granted prior to the effective date of SFAS No. 123R. Under the “modified retrospective” method, the requirements are the same as under the “modified prospective” method, but it also permits entities to restate financial statements of previous periods based on pro-forma disclosures made in accordance with SFAS No. 123. The Company plans to adopt the requirements of SFAS No. 123R using the the “modified prospective” method.

     The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options when calculating the pro forma effect of applying the fair value provisions of SFAS No. 123 as disclosed above under “Stock-based Compensation.” While SFAS No. 123R permits entities to continue to use such a model, the standard also permits the use of a “lattice” model. The Company plans to continue using a Black-Scholes option pricing model to measure the fair value of employee stock options upon the adoption of SFAS No. 123R.

     Under SFAS No. 123R, the pro forma disclosures previously permitted under SFAS No. 123 and presented above will no longer be an alternative to financial statement recognition.

     SFAS No. 123R also requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after the effective date. These future amounts cannot be estimated because they depend on, among other things, when employees exercise stock options and the Company’s stock price at that time.

     The Company has not yet determined the financial statement impact of adopting SFAS No. 123R for periods beyond 2005 because they depend on, among other things, the number of options granted in the future and the Company’s future stock price.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”

     In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. FIN No. 47 is effective for fiscal years ending after December 15, 2005. The Company does not expect FIN No. 47 to have a material impact on its results of operations, financial condition, or cash flows.

Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3”

     In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3”. SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS No. 154 to have a material impact on the Company’s results of operations, financial condition, or cash flows.

Emerging Issues Task Force (EITF) Issue 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty”

     The Emerging Issues Task Force considered Issue No. 04-13 in its May 17, 2005 and June 16, 2005 meetings to discuss inventory sales to another entity in the same line of business from which it also purchases inventory. The Task Force reached consensus on the issue that purchases and sales of inventory with the same counterparty should be combined as a single nonmonetary transaction (net) and noted factors that may indicate that transactions were entered into in contemplation of one another. The Task Force also concluded that transfers of finished goods inventory in exchange for work-in-progress or raw materials should be recognized at fair value and prescribes additional disclosures. The Task Force ratified Issue No. 04-13 at its September 28, 2005 meeting, which should be applied to new arrangements entered into in the first interim or annual reporting period beginning after March 15, 2006. The Company has previously reported transactions of this nature on a net basis; therefore, the Company does not expect Issue No. 04-13 to have a material impact on the Company’s results of operations, financial condition, or cash flows.

3. Inventories

     Inventories are comprised principally of materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. The Company’s inventories consisted of the following as of the dates indicated (amounts in thousands):

		September 30, 2005				December 31, 2004
Warehouse inventory		$	7,208			$	6,321
Oil in pipelines (purchased)			3,044				—
Oil in pipelines (produced)			—				229
		$	10,252			$	6,550

4. Cortez Acquisition and Goodwill

     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 of $1.8 million.

     The acquired oil and natural gas properties are located primarily in the Cedar Creek Anticline (“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 the Company’s Consolidated Statement of Operations beginning in April 2004.

     The purchase price allocation resulted in $37.9 million of goodwill primarily as the result of the difference between the fair value of acquired oil and natural gas properties and their lower carryover tax basis, which resulted in deferred taxes of $36.9 million. Management believes the goodwill will be recovered through operating synergies resulting from the close proximity of the properties acquired to existing operations, particularly the additional interest in the CCA and Permian properties. None of the goodwill is deductible for income tax purposes.

5. Derivative Financial Instruments

     The following tables summarize the Company’s open commodity derivative instruments designated as hedges as of September 30, 2005:

Oil Derivative Instruments at September 30, 2005

		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 2005			12,500			$	27.84				2,500			$	31.07				1,000			$	25.12			$	(11,837	)
Jan – June 2006			13,500				44.07				1,000				29.88				2,000				25.03				(18,867	)
July – Dec 2006			13,000				45.00				1,000				29.88				2,000				25.03				(16,058	)
Jan – Dec 2007			4,000				55.00				—				—				2,000				25.11				(19,536	)

Natural Gas Derivative Instruments at September 30, 2005

		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 2005			17,500			$	5.12				5,000			$	5.97				12,500			$	4.99			$	(11,441	)
Jan – Dec 2006			32,500				6.17				5,000				5.68				12,500				5.08				(36,372	)
Jan – Dec 2007			12,500				6.53				—				—				10,000				4.99				(13,193	)

     Encore recognizes the following in its Consolidated Statements of Operations: (1) derivative fair value gains and losses related to changes in the mark-to-market value of basis swaps and certain other commodity derivatives that are not designated for hedge accounting; (2) ineffectiveness of commodity futures contracts designated as hedges; and (3) changes in the mark-to-market value of its 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, commonly called basis swaps, 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 the Company is paid on its actual production and 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 Company’s 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. 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 the Company’s overall hedged volumes, average prices presented in the table above are exclusive of any effect of these non-hedge instruments. As of September 30, 2005, the mark-to-market value of these basis swap contracts is $1.1 million.

     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, 2005 due to fluctuation of prices in the commodities markets.

     The Company recorded $17.8 million of derivative premiums payable at September 30, 2005. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from January 2006 to December 2007. The long-term portion of the derivatives premiums payable is $12.2 million and is recorded in ‘Other’ long-term liabilities on the Company’s Consolidated Balance Sheet.

6. Asset Retirement Obligations

     The Company’s primary asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The following table summarizes the changes in the Company’s future abandonment liability recorded in ‘Future abandonment costs’ on the Company’s Consolidated Balance Sheet for the period from January 1, 2005 through September 30, 2005 (in thousands):

		Nine months ended
		September 30, 2005
Future abandonment liability at January 1, 2005		$	6,601
Wells drilled			858
Accretion expense			366
Plugging and abandonment costs incurred			(600	)
Revision of estimates			4,067
Future abandonment liability at September 30, 2005		$	11,292

     During the first nine months of 2005, the Company increased its discounted estimate of future plugging liability by $4.1 million as actual plugging costs experienced during the first quarter of 2005 increased due to plugging cost escalations (which outpaced inflation), increased cost of outside services, and changes in various state regulations.

7. Capitalization of Exploratory Well Costs

     The Company adopted FASB Staff Position (“FSP”) 19-1 “Accounting for Suspended Well Costs” on July 1, 2005. FSP 19-1 amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies,” to permit the continued capitalization of exploratory well costs beyond one year if the well found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Upon the adoption of FSP 19-1, the Company evaluated all existing capitalized exploratory well costs and determined that there was no impact on the Company’s results of operations, financial condition, or cash flows. At September 30, 2005, the Company had $1.2 million of capitalized exploratory drilling costs. All of the costs are related to wells in progress or wells for which drilling has been completed for less than one year.

8. Debt

     The Company’s long-term debt consisted of the following as of the dates indicated (amounts in thousands):

		September 30, 2005				December 31, 2004
Revolving credit facility		$	49,000			$	79,000
83/8% Senior subordinated notes			—				150,000
61/4% Senior subordinated notes			150,000				150,000
6% Senior subordinated notes, net of unamortized discount of $5,419			294,581				—
		$	493,581			$	379,000

Issuance of 6% Senior Subordinated Notes

     On July 13, 2005, the Company issued $300.0 million of its 6% senior subordinated notes due July 15, 2015 (the “6% Notes”). The offering was made through a private placement and the notes were resold by the initial purchasers pursuant to Rule 144A and Regulation S. The Company received net proceeds of approximately $294.5 million from the private placement and used approximately $165.9 million of the net proceeds to redeem all of the Company’s outstanding 8³/⁸% senior subordinated notes due 2012. The remaining net proceeds were used to reduce the balance outstanding under the Company’s revolving credit facility.

     The Company paid a premium of $15.9 million to redeem the outstanding 8³/⁸% senior subordinated notes. Combined with the unamortized balance of the related debt issuance costs, the Company incurred a loss on early redemption of the debt of $19.5 million, which the Company recognized in earnings for the three and nine months ended September 30, 2005.

     The Company filed an exchange offer registration statement on Form S-4 on August 8, 2005, under which the 6% Notes would be exchanged for registered notes with substantially identical terms. The exchange offer was completed on October 7, 2005 and 100% of the notes were exchanged.

     The notes mature July 15, 2015 and require semi-annual interest payments on April 15 and October 15. The indenture governing the notes contains certain affirmative and negative covenants, including, without limitation, limitations on our ability to incur additional debt, sell assets, incur liens, make investments and consolidate, merge or transfer assets.

Revolving Credit Facility

     On April 29, 2005, the Company amended its existing credit facility to increase the borrowing base from $400.0 million to $500.0 million. Other changes to the facility include a change in the definition of EBITDA to add back exploration expense (EBITDAX), and an increase in the availability of letters of credit from 15% of the borrowing base to 20%.

     Upon the issuance of the 6% Notes on July 13, 2005 (see above), the Company’s borrowing base was reduced from $500.0 million to $450.0 million according to the terms of the credit facility.

Letters of Credit

     The Company had $75.1 million of outstanding letters of credit at September 30, 2005. 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. Any outstanding letters of credit reduce the availability under the Company’s revolving credit facility. As a result, the Company’s availability under its revolving credit facility was reduced to $325.9 million at September 30, 2005.

9. Income Taxes

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

		Nine months ended
		September 30,
		2005				2004
Income before income taxes		$	99,287			$	85,934
Tax at statutory rate			34,750				30,077
State income taxes, net of federal benefit			1,911				2,578
Section 43 credits generated			(2,664	)			(2,507	)
Permanent differences and other			(1,016	)			(121	)
Income tax provision		$	32,981			$	30,027

10. Earnings Per Share (EPS)

     The following table sets forth basic and diluted EPS computations for the three and nine months ended September 30, 2005 and 2004 (in thousands, except per share data):

		Three months ended								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
Numerator:
Net income		$	20,854			$	21,014			$	66,306			$	55,907
Denominator:
Denominator for basic earnings per share – Weighted average shares outstanding			48,703				48,446				48,659				46,611
Effect of dilutive options and dilutive restricted stock (a)			881				657				822				611
Denominator for diluted earnings per share			49,584				49,103				49,481				47,222
Net income per common share:
Basic		$	0.43			$	0.43			$	1.36			$	1.20
Diluted		$	0.42			$	0.43			$	1.34			$	1.18

11. Stockholders’ Equity

     On June 15, 2005, the Company announced that its Board of Directors approved a three-for-two split of the Company’s outstanding common stock in the form of a stock dividend. The dividend was distributed on July 12, 2005, to stockholders of record at the close of business on June 27, 2005 (the “Record Date”). In lieu of issuing fractional shares, the Company paid cash for such fractional shares based on the closing price of the common stock on the Record Date.

     The pro forma effect of the stock split on the December 31, 2004 balance sheet is to reduce additional paid-in-capital by $0.2 million and increase common stock by $0.2 million. The balances of additional paid-in-capital and common stock at December 31, 2004 have been adjusted accordingly and all share and per-share information included in the accompanying consolidated financial statements and related notes thereto for all periods presented have been adjusted to retroactively reflect the stock split.

     On May 3, 2005, the Company’s stockholders approved an amendment to the Company’s Second Amended and Restated Certificate of Incorporation to increase the authorized number of shares of common stock, par value $.01 per share, from 60 million to 144 million.

12. Comprehensive Income (Loss)

Components of comprehensive income (loss), net of related tax, are as follows (in thousands):

		Three months ended								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
Net income		$	20,854			$	21,014			$	66,306			$	55,907
Change in unrealized loss on derivative hedged instruments			(23,708	)			(22,107	)			(53,864	)			(39,644	)
Change in deferred gain on interest rate swap			(53	)			68				(315	)			294
Comprehensive income		$	(2,907	)		$	(1,025	)		$	12,127			$	16,557

The components of accumulated other comprehensive loss, net of related tax, are as follows (in thousands):

		September 30, 2005				December 31, 2004
Unrealized loss on derivative hedged instruments		$	(90,705	)		$	(36,841	)
Deferred gain on interest rate swap			129				444
Accumulated other comprehensive loss		$	(90,576	)		$	(36,397	)

13. Financial Statements of Subsidiary Guarantors

     As of September 30, 2005, all of the Company’s subsidiaries were subsidiary guarantors of the Company’s outstanding 6¹/4% and 6% 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.

14. Related Party Transactions

     The Company paid to Hanover Compressor Company $0.8 million and $0.1 million in the first nine months of 2005 and 2004, respectively, for field compression services. Mr. I. Jon Brumley, the Company’s Chairman and CEO, also serves as a director of Hanover Compressor Company.

15. Subsequent Events

Crusader Acquisition

     On October 14, 2005, the Company completed the acquisition of Crusader Energy Corporation, a privately held, independent oil and natural gas company, for a purchase price of approximately $93.5 million. Encore funded the purchase price by drawing on its revolving credit facility.

Kerr-McGee Acquisition

     On October 19, 2005, the Company entered into an agreement with Kerr-McGee Corporation to acquire oil and natural gas properties for $104.0 million. The transaction is expected to close at the end of November 2005. Encore expects to fund the purchase price through internally generated cash flow and borrowings under its revolving credit facility.

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

     This document contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results may differ materially from those discussed in our forward-looking statements due to many factors, including, but not limited to, those set forth under “FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION” contained in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in Encore’s 2004 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 2004 Form 10-K.

Introduction

This management’s discussion and analysis of financial condition and results of operations is intended to provide investors with an understanding of the Company’s recent performance, its financial condition and its prospects. The following will be discussed and analyzed:

	•		Third Quarter 2005 Highlights
	•		Results of Operations

	-		Comparison of Quarter Ended September 30, 2005 to Quarter Ended September 30, 2004
	-		Comparison of Nine Months Ended September 30, 2005 to Nine Months Ended September 30, 2004

	•		Capital Resources
	•		Capital Commitments
	•		Liquidity

Third Quarter 2005 Highlights

Our financial and operating results for the quarter ended September 30, 2005 included the following highlights:

	•		During the third quarter of 2005, we had oil and natural gas revenues of $127.6 million. This represents a 61% increase over the $79.2 million of oil and natural gas revenues reported for the third quarter of 2004.
	•		We reported net income of $20.9 million, or $0.42 per diluted share, in the three months ended September 30, 2005. This represents a marginal decrease from the $21.0 million of net income, or $0.43 per diluted share, reported for the third quarter of 2004. The reduction in net income was due to a one-time $19.5 million loss on early redemption of debt related to redemption premiums and the expensing of unamortized debt issuance costs related to the 83/8% senior subordinated notes.
	•		Our realized average oil price, including the effects of hedging, increased $16.57 per Bbl in the third quarter of 2005 over the same period in 2004. Our realized average natural gas price, including the effects of hedging, increased $2.48 per Mcf in the third quarter of 2005 over the same period in 2004.
	•		Production volumes for the quarter increased 9% to 28,202 BOE per day (2.6 MMBOE for the quarter), compared with third quarter 2004 production of 25,779 BOE per day (2.4 MMBOE for the quarter). The rise in production volumes was attributable to the continued success of our drilling program, uplift from our HPAI tertiary recovery project on the CCA, and acquisitions completed in 2004. Oil represented 65% and 71% of our total production volumes in the third quarter of 2005 and 2004, respectively.
	•		On July 13, 2005, the Company issued $300.0 million of 6% senior subordinated notes due 2015. The Company received net proceeds of approximately $294.5 million from the issuance and used approximately $165.9 million of the net proceeds to redeem all of the outstanding principal and related accrued interest of the Company’s 83/8% senior subordinated notes. The remaining proceeds were used to reduce our indebtedness under our revolving credit facility.
	•		We invested $125.0 million in oil and natural gas activities during the third quarter of 2005 (excluding development-related asset retirement obligations). We invested $92.6 million in development, exploitation, expanding our HPAI program in the CCA, and exploration activities, which yielded 84 gross (56.1 net) wells. We also invested $32.4

			million in acquiring proved properties and undeveloped leases. We are currently investing capital in an eleven-rig operated drilling program on the onshore continental United States, with four rigs in Montana, two rigs in East Texas, two rigs in West Texas, and three rigs in the Mid-Continent area.
	•		We were able to fund $86.7 million of our investments in oil and natural gas activities using operating cash flows generated during the quarter. The remaining $38.3 million was funded through borrowings under our existing revolving credit facility. Long-term debt at September 30, 2005 increased to $493.6 million from $379.0 million at December 31, 2004.

Results of Operations

Comparison of Quarter Ended September 30, 2005 to Quarter Ended September 30, 2004

Below is a comparison of our operations during the third quarter of 2005 with the third quarter of 2004.

     Revenues and Production. The following table illustrates the primary components of oil and natural gas revenues for the three months ended September 30, 2005 and 2004, as well as each quarter’s respective oil and natural gas volumes (in thousands, except per unit and per day amounts):

		Three months ended								Increase /
		September 30,								(Decrease)
		2005				2004				$				%
Revenues:
Oil wellhead		$	97,563			$	68,484			$	29,079
Oil hedges			(12,004	)			(10,241	)			(1,763	)
Total Oil Revenues		$	85,559			$	58,243			$	27,316				47	%
Natural gas wellhead		$	46,515			$	21,551			$	24,964
Natural gas hedges			(4,502	)			(542	)			(3,960	)
Total Natural Gas Revenues		$	42,013			$	21,009			$	21,004				100	%
Combined wellhead		$	144,078			$	90,035			$	54,043
Combined hedges			(16,506	)			(10,783	)			(5,723	)
Total Combined Revenues		$	127,572			$	79,252			$	48,320				61	%
Revenues ($/Unit):
Oil wellhead		$	58.09			$	40.41			$	17.68
Oil hedges			(7.15	)			(6.04	)			(1.11	)
Total Oil Revenues		$	50.94			$	34.37			$	16.57				48	%
Natural gas wellhead		$	8.47			$	5.30			$	3.17
Natural gas hedges			(0.82	)			(0.13	)			(0.69	)
Total Natural Gas Revenues		$	7.65			$	5.17			$	2.48				48	%
Combined wellhead		$	55.52			$	37.97			$	17.55
Combined hedges			(6.35	)			(4.55	)			(1.80	)
Total Combined Revenues		$	49.17			$	33.42			$	15.75				47	%
Total production volumes:
Oil (Bbls)			1,680				1,695				(15	)
Natural gas (Mcf)			5,489				4,063				1,426
Combined (BOE)			2,595				2,372				223				9	%
Daily production volumes:
Oil (Bbls/day)			18,257				18,419				(162	)
Natural gas (Mcf/day)			59,666				44,160				15,506
Combined (BOE/day)			28,202				25,779				2,423				9	%
NYMEX Prices:
Oil (per Bbl)		$	63.19			$	43.92			$	19.27				44	%
Natural gas (per Mcf)			9.64				5.56				4.08				73	%

     Oil revenues increased from third quarter 2004 to third quarter 2005 by $27.3 million, due primarily to a higher realized average oil price. Our realized average oil price increased $16.57 per Bbl in the third quarter of 2005 over the same period in 2004 as a result of an increase in our average wellhead price of $17.68 per Bbl, offset by an increase in hedging payments of $1.11 per Bbl. The increase in our average wellhead price and hedging payments resulted from the increase in the overall market price for oil as reflected in the increase in the average NYMEX price from $43.92 for the third quarter of 2004 to $63.19 for the third quarter of 2005.

     Natural gas revenues increased by $21.0 million, or $2.48 per Mcf, in the third quarter of 2005 from the third quarter of 2004 due to an increase in volumes and an increase in our realized average natural gas price. Production volumes increased 1,426 MMcf in the third quarter of 2005 as compared to the third quarter of 2004 due to drilling activities. The $2.48 per Mcf increase in our realized average natural gas price was due to the $3.17 per Mcf increase in the wellhead price for our natural gas from the third quarter of 2004 to the third quarter of 2005, offset by an increase in hedging payments of $0.69 per Mcf. The average NYMEX price for natural gas increased from $5.56 for the third quarter of 2004 to $9.64 for the third quarter of 2005.

     The table below illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices for the quarters ended September 30, 2005 and 2004. Management uses the wellhead to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

		Three months ended
		September 30,
		2005				2004
Oil wellhead ($/Bbl)		$	58.09			$	40.41
Average NYMEX ($/Bbl)		$	63.19			$	43.92
Differential to NYMEX		$	(5.10	)		$	(3.51	)
Oil wellhead to NYMEX percentage			92	%			92	%
Natural gas wellhead ($/Mcf)		$	8.47			$	5.30
Average NYMEX ($/Mcf)		$	9.64			$	5.56
Differential to NYMEX		$	(1.17	)		$	(0.26	)
Natural gas wellhead to NYMEX percentage			88	%			95	%

     As indicated above, our differential to the average NYMEX price of oil increased on a per unit basis while our oil wellhead price as a percentage of the average NYMEX price remained consistent from the third quarter of 2004 to the third quarter of 2005

     Our natural gas wellhead price as a percentage of the average NYMEX price decreased from the third quarter of 2004 to the third quarter of 2005. The decrease is primarily due to regional natural gas spot prices lagging the significant increases in the NYMEX price during the third quarter of 2005.

     Expenses. The following table summarizes our expenses for the quarters ended September 30, 2005 and 2004:

		Three months ended								Increase /
		September 30,								(Decrease)
		2005				2004				$				%
Expenses (in thousands):
Production —
Lease operations		$	17,912			$	12,589			$	5,323
Production, ad valorem, and severance taxes			12,526				8,117				4,409
Total production expenses			30,438				20,706				9,732				47	%
Other —
Depletion, depreciation, and amortization			24,222				12,750				11,472
Exploration			4,818				462				4,356
General and administrative (excluding non-cash stock based compensation)			4,030				2,858				1,172
Non-cash stock based compensation			1,544				796				748
Derivative fair value loss			1,612				2,301				(689	)
Loss on early redemption of debt			19,477				—				19,477
Other operating			2,520				1,369				1,151
Total operating			88,661				41,242				47,419				115	%
Interest			9,264				6,547				2,717
Current and deferred income tax provision			9,373				10,527				(1,154	)
Total expenses		$	107,298			$	58,316			$	48,982				84	%
Expenses (per BOE):
Production —
Lease operations		$	6.90			$	5.31			$	1.59
Production, ad valorem, and severance taxes			4.83				3.42				1.41
Total production expenses			11.73				8.73				3.00				34	%
Other —
Depletion, depreciation, and amortization			9.34				5.38				3.96
Exploration			1.86				0.19				1.67
General and administrative (excluding non-cash stock based compensation)			1.55				1.21				0.34
Non-cash stock based compensation			0.59				0.34				0.25
Derivative fair value loss			0.62				0.97				(0.35	)
Loss on early redemption of debt			7.51				—				7.51
Other operating			0.97				0.58				0.39
Total operating			34.17				17.40				16.77				96	%
Interest			3.57				2.76				0.81
Current and deferred income tax provision			3.61				4.44				(0.83	)
Total expenses		$	41.35			$	24.60			$	16.75				68	%

     Production expenses (Lease operations and production, ad valorem, and severance taxes). Total production expenses for the third quarter of 2005 increased $9.7 million as compared to the third quarter of 2004. This increase resulted from an increase in total production volumes, as well as a $3.00 increase in production expenses per BOE in the third quarter of 2005 as compared to the third quarter of 2004. The $3.00 increase in production expenses per BOE in the third quarter of 2005 represents a 34% increase over the third quarter of 2004. The 34% increase in total production expenses per BOE is less than the 47% increase in revenues per BOE over the same period, resulting in a higher production margin.

     The production expense attributable to lease operations for the third quarter of 2005 increased as compared to the third quarter of 2004 by $5.3 million. The increase in total lease operations expense resulted from: (1) an increase in production volumes as a result of our 2005 drilling program and our high-pressure air injection (“HPAI”) program; (2) an increase in prices paid for outside services in the current higher price environment, increased operational activity to maximize production, and the operation of higher operating cost wells as lower margin wells become more attractive in the current higher price environment; and (3) the expensing of HPAI production costs attributable to Little Beaver Phase I that previously were being capitalized during the pressurization phase.

     The production expense attributable to production, ad valorem, and severance taxes for the third quarter of 2005 increased as compared to the same period in 2004 by approximately $4.4 million due to an increase in total 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 2005 decreased to 8.7% from 9.0% in the third quarter of 2004 as a result of higher production levels in states with lower production, ad valorem, and severance taxes. 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 2005 increased by $11.5 million as compared to the third quarter of 2004, due to a $3.96 per BOE increase and an increase in production. This per BOE rate increase was due to the development of proved undeveloped reserves from the 2004 acquisitions and higher drilling costs per BOE of reserves than our historical DD&A rate in certain areas.

     Exploration expense. Exploration expense was $4.8 million in the third quarter of 2005, while it was $0.5 million in the third quarter of 2004. During the third quarter of 2005, we expensed 21 exploratory dry holes totaling $3.6 million. Out of the 21 exploratory dry holes expensed, one was drilled in the CCA and twenty were drilled in the shallow gas area of Montana. In the third quarter of 2004, we did not expense any dry holes. The following table details our exploration-related expenses for the third quarter of 2005 and 2004 (in thousands):

		Three months ended
		September 30,								Increase /
		2005				2004				(Decrease)
Exploration expenses:
Dry hole		$	3,604			$	—			$	3,604
Geological and geophysical			305				64				241
Seismic			352				18				334
Delay rental			169				40				129
Impairment of undeveloped leasehold			388				340				48
Total		$	4,818			$	462			$	4,356

     General and administrative (“G&A”) expense. G&A expense (excluding non-cash stock based compensation) increased $1.2 million for the third quarter of 2005 as compared to the third quarter of 2004. The overall increase, as well as the $0.34 increase in the per BOE rate, is a result of increased staffing to manage our larger asset base and higher activity levels. Additionally, we have experienced increased competition for human resources from other companies within the industry that has increased the cost to hire and retain experienced industry personnel.

     Non-cash stock based compensation expense. Non-cash stock based compensation expense for the third quarter of 2005 increased $0.7 million as compared to the same period in 2004. This expense represents the amortization of deferred compensation recorded in equity related to restricted stock granted under the 2000 Incentive Stock Plan. Amortization of deferred compensation increased from the same period in 2004 primarily due to third quarter 2005 amortization related to 269,555 shares of restricted stock granted in the nine months ended September 30, 2005. In addition, certain restricted stock grants contain performance vesting provisions, which require us to recognize periodic expense based on the Company’s current stock price, rather than the stock price at the day of grant. As a result, the Company’s higher stock price has also resulted in increased amortization expense.

     Derivative fair value loss. During the third quarter of 2005 we recorded a $1.6 million derivative fair value loss as compared to the $2.3 million loss recorded in the third quarter of 2004. This derivative fair value loss represents the ineffective portion of the mark-to-market loss on our derivative hedging instruments, settlements received on our fixed-to-floating interest rate swap, (gains) losses related to commodity derivatives not designated as hedges, and changes in the mark-to-market value of our fixed–to-floating interest rate swap.

     The components of the derivative fair value (gain) loss reported in the third quarter of 2005 and 2004 are as follows (in thousands):

		Three months ended
		September 30,								Increase /
		2005				2004				(Decrease)
Designated cash flow hedges:
Ineffectiveness – Commodity contracts		$	2,211			$	2,740			$	(529	)
Undesignated derivative contracts:
Mark-to-market (gain) loss – Interest rate swap			—				(383	)			383
Mark-to-market (gain) loss – Commodity contracts			(599	)			(56	)			(543	)
Derivative fair value loss		$	1,612			$	2,301			$	(689	)

     Ineffectiveness loss related to our derivative commodity contracts decreased $0.5 million due primarily to fewer loss positions on our natural gas contracts offset by an increased oil wellhead differential on our production in the CCA. We currently do not have any interest rate swap contracts outstanding as our fixed-to-floating interest rate swap expired in June 2005. The gain related to undesignated commodity contracts increased $0.5 million from the prior year three month period due to changes in the fair value of certain natural gas basis swaps.

     Loss on early redemption of debt. In the third quarter of 2005, we recorded a one-time $19.5 million loss on early redemption of debt related to the redemption premium and the expensing of unamortized debt issuance costs of the 8³/⁸% senior subordinated notes. We redeemed the 8³/⁸% notes with proceeds received from the issuance of our $300.0 million 6% senior subordinated notes in July 2005.

     Other operating expense. Other operating expense for the third quarter of 2005 increased by $1.2 million when compared to the same period in 2004. This increase is mainly due to an increase in third party natural gas transportation costs attributable to higher production volumes for the third quarter of 2005 over the same period in 2004.

     Interest expense. Interest expense increased $2.7 million in the third quarter of 2005 compared to the third quarter of 2004. The increase is primarily due to the issuance of $300.0 million of 6% senior subordinated notes in July 2005. The increase is offset by the redemption of $150.0 million of 8³/⁸% senior subordinated notes in August 2005. The weighted average interest rate, net of hedges, for the quarter ended September 30, 2005 was 6.9% compared to 7.1% for the quarter ended September 30, 2004. This lower weighted average interest rate is the result of the issuance of 6% notes which has a rate lower than our historical average rate.

     The following table illustrates the components of interest expense for the three months ended September 30, 2005 and 2004 (in thousands):

		Three months ended
		September 30,								Increase /
		2005				2004				(Decrease)
83/8% notes due 2012		$	1,570			$	3,141			$	(1,571	)
61/4% notes due 2014			2,344				2,344				—
6% notes due 2015			3,937				—				3,937
Revolving credit facility			675				467				208
Letters of credit			219				77				142
Interest rate hedges (1)			(94	)			109				(203	)
Debt issuance cost			255				248				7
Banking fees and other			358				161				197
Total		$	9,264			$	6,547			$	2,717