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

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

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

     Number of shares of Common Stock, $0.01 par value, outstanding as of July 29, 2005 ....................... 49,327,156

 

 

ENCORE ACQUISITION COMPANY

INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004			1
Consolidated Statements of Operations for the three and six months ended June 30, 2005 and 2004			2
Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2005			3
Consolidated Statements of Cash Flows for the six months ended June 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 4. Submission of Matters to a Vote for Security Holders			29
Item 6. Exhibits			30
Signatures			31
Purchase Agreement
Rule 13a-14(a)/15d-14(a) Certification - Pricipal Executive Officer
Rule 13a-14(a)/15d-14(a) Certification - Pricipal Financial Officer
Section 1350 Certifiation - Principal Executive Officer
Section 1350 Certifiation - Principal Financial Officer

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

     This Quarterly Report on Form 10-Q contains forward-looking statements, which 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” 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)

		June 30,				December 31,
		2005				2004
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	1,023			$	1,103
Accounts receivable			50,944				43,839
Inventory			10,191				6,550
Derivatives			776				2,665
Deferred taxes			20,869				11,118
Other			3,124				5,842
Total current assets			86,927				71,117
Properties and equipment, at cost — successful efforts method:
Proved properties			1,295,489				1,134,220
Unproved properties			30,825				29,740
Accumulated depletion, depreciation, and amortization			(206,655	)			(171,691	)
			1,119,659				992,269
Other property and equipment			14,495				10,425
Accumulated depreciation			(4,288	)			(3,551	)
			10,207				6,874
Goodwill			37,908				37,995
Other			15,110				15,145
Total assets		$	1,269,811			$	1,123,400
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	18,221			$	24,375
Derivatives			49,977				24,270
Accrued and other current			42,327				38,038
Total current liabilities			110,525				86,683
Derivatives			54,865				31,477
Future abandonment costs			11,161				6,601
Other			1,336				—
Deferred taxes			159,907				146,064
Long-term debt			440,000				379,000
Total liabilities			777,794				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, 49,338,036 and 48,982,197 issued and outstanding			493				490
Additional paid-in capital			323,631				314,573
Deferred compensation			(10,256	)			(4,603	)
Retained earnings			244,964				199,512
Accumulated other comprehensive loss			(66,815	)			(36,397	)
Total stockholders’ equity			492,017				473,575
Total liabilities and stockholders’ equity		$	1,269,811			$	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								Six months ended
		June 30,								June 30,
		2005				2004				2005				2004
Revenues:
Oil		$	69,559			$	52,885			$	136,695			$	99,649
Natural gas			30,158				17,237				54,603				29,764
Total revenues			99,717				70,122				191,298				129,413
Expenses:
Production —
Lease operations			15,721				10,921				30,589				21,163
Production, ad valorem, and severance taxes			9,813				7,161				18,899				13,000
Depletion, depreciation, and amortization			19,038				11,249				35,721				20,512
Exploration			3,772				1,697				6,383				1,697
General and administrative (excluding non-cash stock based compensation)			3,571				2,530				7,206				4,758
Non-cash stock based compensation			1,006				307				1,779				617
Derivative fair value loss			1,692				965				4,101				1,123
Other operating			1,703				1,091				3,302				2,093
Total expenses			56,316				35,921				107,980				64,963
Operating income			43,401				34,201				83,318				64,450
Other income (expenses):
Interest			(7,448	)			(6,308	)			(14,407	)			(10,214	)
Other			85				106				149				157
Total other income (expenses)			(7,363	)			(6,202	)			(14,258	)			(10,057	)
Income before income taxes			36,038				27,999				69,060				54,393
Current income tax provision			(589	)			(919	)			(1,390	)			(2,004	)
Deferred income tax provision			(11,781	)			(9,089	)			(22,218	)			(17,496	)
Net income		$	23,668			$	17,991			$	45,452			$	34,893
Net income per common share:
Basic		$	0.49			$	0.39			$	0.93			$	0.76
Diluted			0.48				0.39				0.92				0.75
Weighted average common shares outstanding:
Basic			48,660				46,089				48,636				45,684
Diluted			49,458				46,680				49,429				46,271

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

ENCORE ACQUISITION COMPANY

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

																						Accumulated
		Shares of								Additional												Other				Total
		Common				Common				Paid-In				Deferred				Retained				Comprehensive				Stockholders’
		Stock				Stock				Capital				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			92				—				1,629				—				—				—				1,629
Deferred compensation:
Issuance of restricted Common Stock			270				3				7,106				(7,109	)			—				—				—
Amortization to expense			—				—				—				1,779				—				—				1,779
Other changes			(6	)			—				323				(323	)			—				—				—
Components of comprehensive income:
Net income			—				—				—				—				45,452				—				45,452
Change in deferred hedge loss, net of income taxes of $18,120			—				—				—				—				—				(30,418	)			(30,418	)
Total comprehensive income																											15,034
Balance at June 30, 2005			49,338			$	493			$	323,631			$	(10,256	)		$	244,964			$	(66,815	)		$	492,017

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

ENCORE ACQUISITION COMPANY

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

		Six months ended
		June 30,
		2005				2004
Operating activities
Net income		$	45,452			$	34,893
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization			35,721				20,512
Dry hole expense			3,329				1,697
Deferred taxes			22,218				17,496
Non-cash stock based compensation			1,779				617
Non-cash derivative fair value loss			8,278				6,106
Other non-cash			1,844				779
Loss on disposition of assets			160				109
Changes in operating assets and liabilities:
Accounts receivable			(7,059	)			(3,882	)
Other current assets			(2,952	)			(8,357	)
Other assets			(4,113	)			(309	)
Accounts payable and accrued liabilities			12,808				4,829
Cash provided by operating activities			117,465				74,490
Investing activities
Proceeds from disposition of assets			424				425
Purchases of other property and equipment			(4,714	)			(6,597	)
Acquisition of oil and natural gas properties			(17,379	)			(98,608	)
Acquisition of Cortez Oil & Gas, Inc. (net of cash acquired)			—				(123,023	)
Development and exploration of oil and natural gas properties			(144,434	)			(70,573	)
Cash used by investing activities			(166,103	)			(298,376	)
Financing activities
Proceeds from issuance of common stock			—				53,900
Payment of offering cost of common stock			—				(900	)
Proceeds from long-term debt			195,000				169,000
Payments on long-term debt			(134,000	)			(145,000	)
Proceeds from issuance of 61/4% notes			—				150,000
Payments of debt issuance costs			(204	)			(3,128	)
Cash overdrafts and other			(12,238	)			2,374
Cash provided by financing activities			48,558				226,246
Increase (decrease) in cash and cash equivalents			(80	)			2,360
Cash and cash equivalents, beginning of period			1,103				431
Cash and cash equivalents, end of period		$	1,023			$	2,791

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

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2005
(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 June 30, 2005, results of operations for the three and six months ended June 30, 2005 and 2004, and cash flows for the six months ended June 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.

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

     As discussed at Note 10, “Stockholders’ Equity,” during the three months ended June 30, 2005, the Company’s Board of Directors approved a three-for-two stock split in the form of a stock dividend to shareholders of record on June 27, 2005. All share and per-share information for all periods presented in the accompanying financial statements and related notes thereto have been restated to reflect the stock split that occurred on July 12, 2005.

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								Six months ended
		June 30,								June 30,
		2005				2004				2005				2004
As Reported:
Non-cash stock based compensation (net of taxes)		$	630			$	190			$	1,114			$	383
Net income			23,668				17,991				45,452				34,893
Basic net income per common share			0.49				0.39				0.93				0.76
Diluted net income per common share			0.48				0.39				0.92				0.75
Pro Forma:
Non-cash stock based compensation (net of taxes)		$	971			$	518			$	1,618			$	924
Net income			23,327				17,663				44,948				34,352
Basic net income per common share			0.48				0.38				0.92				0.75
Diluted net income per common share			0.47				0.38				0.91				0.74

     There were 269,555 shares of restricted stock granted during the six months ended June 30, 2005, of which 266,636 shares are outstanding at June 30, 2005. During the first half of 2005, 2,536 shares of restricted stock, which were issued and outstanding at December 31, 2004, were forfeited. There were 115,284 shares of stock options granted in the six months ended June 30, 2005, of which 114,375 shares of stock options are outstanding at June 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 was initially scheduled to be the first reporting period beginning after June 15, 2005, which is third quarter 2005 for calendar year companies. However, on April 14, 2005, the Securities and Exchange Commission (“SEC”) announced that the effective date of SFAS No. 123R will be delayed until 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 has not yet determined which of the aforementioned adoption methods it will use.

     The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees to calculate 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 has not yet determined which model it will use to measure the fair value of employee stock options upon the adoption of SFAS No. 123R.

     Under the revised standard, the pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. See the discussion of stock-based compensation above for the pro forma net income and net income per share amounts for the three and six months ended June 30, 2004 and 2005, as if the Company had used a fair-value-based method similar to the methods required under SFAS No. 123R to measure compensation expense for employee stock incentive awards.

     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 plans to adopt SFAS No. 123R effective January 1, 2006, based on the new effective date announced by the SEC. The Company has not yet determined the financial statement impact of adopting SFAS No. 123R for periods beyond 2005.

FASB Staff Position 19-1, “Accounting for Suspended Well Costs”

     On April 4, 2005 the FASB adopted FASB Staff Position (“FSP”) 19-1 “Accounting for Suspended Well Costs” that 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 entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP 19-1 is effective for the first reporting period beginning after April 4, 2005, which for the Company will be the third quarter of 2005. Its adoption is not expected 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 for 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 is expected to ratify Issue No. 04-15 at its September 2005 meeting, which would be applicable for transactions completed in reporting periods 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. 04-15 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):

		June 30, 2005				December 31, 2004
Warehouse inventory		$	6,952			$	6,321
Oil in pipelines (purchased)			3,239				—
Oil in pipelines (produced)			—				229
		$	10,191			$	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 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 the Company’s Consolidated Statement of Operations beginning in April 2004.

     The calculation of the total purchase price and the allocation as of June 30, 2005 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		$	85,805
Cortez debt repaid			39,449
Transaction costs			1,760
Total purchase price		$	127,014
Allocation of purchase price to the fair value of net assets acquired:
Cash		$	3,206
Current assets, excluding cash			5,946
Proved oil and natural gas properties			120,503
Unproved oil and natural gas properties			3,011
Goodwill			37,908
Total assets acquired			170,574
Current liabilities			(5,673	)
Non-current liabilities			(996	)
Deferred income taxes			(36,891	)
Total liabilities assumed			(43,560	)
Fair value of net assets acquired		$	127,014

     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 June 30, 2005:

Oil Derivative Instruments at June 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)
July – Dec 2005			12,500			$	27.84				2,500			$	31.07				1,000			$	25.12			$	(18,513	)
Jan – June 2006			7,000				33.93				1,000				29.88				2,000				25.03				(16,927	)
July – Dec 2006			6,500				35.00				1,000				29.88				2,000				25.03				(16,233	)
Jan – Dec 2007			—				—				—				—				2,000				25.11				(22,001	)

Natural Gas Derivative Instruments at June 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)
July – Dec 2005			17,500			$	5.12				5,000			$	5.97				12,500			$	4.99			$	(6,004	)
Jan – Dec 2006			12,500				5.34				5,000				5.68				12,500				5.08				(15,576	)
Jan – Dec 2007			—				—				—				—				10,000				4.99				(8,458	)

     Encore recognizes in the Consolidated Statements of Operations 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; ineffectiveness of commodity futures contracts designated as hedges; and 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 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 June 30, 2005, the mark-to-market value of these contracts is $0.5 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 June 30, 2005 due to fluctuation of prices in the commodities markets.

Interest Rate Derivatives

     The Company does not currently have any interest rate swap contracts outstanding. During the quarter ended June 30, 2005, a gain of $0.03 million related to an interest rate swap that expired in June 2005 was recorded in the Consolidated Statement of Operations.

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 June 30, 2005 (in thousands):

		Six months ended
		June 30, 2005
Future abandonment liability at January 1, 2005		$	6,601
Wells drilled			564
Accretion expense			224
Plugging and abandonment costs incurred			(530	)
Revision of estimates			4,302
Future abandonment liability at June 30, 2005		$	11,161

     During the first half of 2005, the Company increased its discounted estimate of future plugging liability by $4.3 million as actual plugging costs experienced during the first quarter of 2005 increased due to plugging cost escalations (which outpaced inflation), the cost of outside services, and changes in various state regulations.

7. Debt

Issuance of 6% Senior Subordinated Notes

     On June 30, 2005, the Company priced $300.0 million of 6% senior subordinated notes due July 15, 2015 (the “6% notes”). The Company issued and sold the notes on July 13, 2005. The offering was made through a private placement pursuant to Rule 144A and Regulation S. The Company estimates net proceeds of approximately $293.5 million after paying all costs associated with the offering. The net proceeds are expected to be used to redeem all $150.0 million of the Company’s outstanding 8³/₈% senior subordinated notes due 2012, and to reduce outstanding indebtedness under the Company’s existing revolving credit facility. Concurrently with the issuance of the 6% notes, the Company entered into a registration rights agreement whereby the Company agreed to file a registration statement offering to exchange the 6% notes for publicly registered notes with substantially identical terms.

     The 6% notes mature on July 15, 2015 and all amounts then outstanding will be due and payable at that time. Interest is paid semi-annually on July 15 and January 15. The indenture governing the 6% notes contains substantially the same covenants and restrictions as the Company’s outstanding 6¹/4% senior subordinated notes due 2014.

Line of Credit

     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.

Letters of Credit

     The Company had $56.1 million of outstanding letters of credit at June 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.

8. Income Taxes

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

		Six months ended
		June 30,
		2005				2004
Income before income taxes		$	69,060			$	54,393
Tax at statutory rate			24,171				19,038
State income taxes, net of federal benefit			1,371				1,632
Section 43 credits generated			(1,446	)			(1,663	)
Permanent differences and other			(488	)			493
Income tax provision		$	23,608			$	19,500

9. Earnings Per Share (EPS)

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

		Three months ended								Six months ended
		June 30,								June 30,
		2005				2004				2005				2004
Numerator:
Net income		$	23,668			$	17,991			$	45,452			$	34,893
Denominator:
Denominator for basic earnings per share –
Weighted average shares outstanding			48,660				46,089				48,636				45,684
Effect of dilutive options and dilutive restricted stock (a)			798				591				793				587
Denominator for diluted earnings per share			49,458				46,680				49,429				46,271
Net income per common share:
Basic		$	0.49			$	0.39			$	0.93			$	0.76
Diluted		$	0.48			$	0.39			$	0.92			$	0.75

     As discussed in Note 10, “Stockholders’ Equity,” during the three months ended June 30, 2005, the Company’s Board of Directors approved a three-for-two stock split in the form of a stock dividend to shareholders of record on June 27, 2005. All share and per-share information in the table above have been restated to reflect the stock split.

10. Stockholders’ Equity

     During the three months ended June 30, 2005, the Company’s Board of Directors approved a three-for-two stock split in the form of a stock dividend on each share of common stock outstanding as of the close of business on June 27, 2005 (the “Record Date”). The stock dividend was distributed on July 12, 2005 to stockholders of record as of 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 beginning balances of additional paid-in-capital and common stock at December 31, 2004 have been adjusted in the June 30, 2005 Consolidated Balance Sheet and Consolidated Statement of Stockholders’ Equity to reflect this pro-forma effect of the stock split. All share and per-share information have been restated to reflect the stock split that became effective July 12, 2005.

     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.

11. Comprehensive Income (Loss)

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

		Three months ended								Six months ended
		June 30,								June 30,
		2005				2004				2005				2004
Net income		$	23,668			$	17,991			$	45,452			$	34,893
Change in unrealized loss on derivative hedged instruments			3,383				(9,854	)			(30,156	)			(17,794	)
Change in deferred gain on interest rate swap			(317	)			358				(262	)			483
Comprehensive income			26,734				8,495				15,034				17,582

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

		June 30, 2005				December 31, 2004
Unrealized loss on derivative hedged instruments		$	(66,997	)		$	(36,841	)
Deferred gain on interest rate swap			182				444
Accumulated other comprehensive loss		$	(66,815	)		$	(36,397	)

12. Financial Statements of Subsidiary Guarantors

     As of June 30, 2005, all of the Company’s subsidiaries were subsidiary guarantors of the Company’s outstanding 8³/₈% and 6¹/4% 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.

13. Related Party Transactions

     The Company paid to Hanover Compressor Company $0.4 million and $0.01 million in the first six 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.

14. Subsequent Events

     8³/₈% Notes

     On July 13, 2005, the Company issued a notice of redemption (the “Redemption Notice”) pursuant to the provisions of the Indenture, dated as of June 25, 2002, among the Company, certain subsidiaries of the Company and Wells Fargo Bank, National

Association, as Trustee (the “Trustee”), pursuant to which the 8³/₈% senior subordinated notes of the Company (the “8³/₈% notes”) were issued. In the Redemption Notice, the Company indicated that it was exercising its right to redeem on August 15, 2005 (the “Redemption Date”) all $150 million aggregate principal amount of 8³/₈% notes currently outstanding. The Company expects the redemption price to approximate $168.6 million, including a make-whole premium and accrued interest through the redemption date. The exact redemption price will be determined in part using the latest Treasury yields at the redemption date and, thus, it will not be known until that time. However, the Company does not expect the estimate to change materially.

     Combined with the unamortized balance of debt issuance costs of the 8³/₈% notes, the Company estimates a pre-tax charge to earnings from the redemption to be recorded in the third quarter of 2005 of $21.8 million at June 30, 2005.

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.

Second Quarter 2005 Highlights

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

	•		During the second quarter of 2005, we had oil and natural gas revenues of $99.7 million. This represents a 42% increase over the $70.1 million of oil and natural gas revenues reported for the second quarter of 2004. Our realized commodity prices, including the effects of hedging, averaged $40.96 per barrel and $6.11 per Mcf during the second quarter of 2005, increases of 31% and 14%, respectively, from the second quarter of 2004. On a combined basis, including the effects of hedging, prices increased 25% during the second quarter of 2005 to $39.56 per BOE from $31.54 per BOE in the second quarter of 2004.
	•		We reported net income of $23.7 million, or $0.48 per diluted share, in the three months ended June 30, 2005. This represents a 32% increase from the $17.9 million of net income, or $0.39 per diluted share, reported for the second quarter of 2004.
	•		Higher net income in the second quarter of 2005 resulted as production volumes for the quarter increased 13% to 27,697 BOE per day (2.5 MMBOE), compared with second quarter 2004 production of 24,434 BOE per day (2.2 MMBOE). 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 67% and 76% of our total production volumes in the second quarter of 2005 and 2004, respectively.
	•		We invested $89.0 million in oil and natural gas activities during the second quarter of 2005 (excluding development-related asset retirement obligations). We invested $81.0 million in development, exploitation, expanding our HPAI program in the CCA, and exploration activities yielding 110 gross (65.7 net) wells. We also invested $8.0 million in acquiring proved properties and undeveloped leases. We are currently investing capital in an eleven-rig conventional operated drilling program on the onshore continental United States, with five rigs in Montana, three rigs in East Texas, two rigs in West Texas, and one rig in Oklahoma.
	•		We were able to fund the majority of the $89.0 million of investments in oil and natural gas activities made in the second quarter of 2005 using the $62.6 million of operating cash flows generated during the quarter. The remaining $26.4 million was funded through borrowings under our existing revolving credit facility. Long-term debt at June 30, 2005 increased to $440.0 million from $379.0 million at December 31, 2004.
	•		On June 30, 2005, we priced the sale of $300.0 million 6% senior subordinated debt. We issued and sold the notes on July 13, 2005. We expect to redeem our 83/8% notes during the third quarter of 2005, and use the remaining net cash received to reduce amounts outstanding under our existing revolving credit facility.

Results of Operations

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

     Set forth below is our comparison of operations during the second quarter of 2005 with the second quarter of 2004.

     Revenues and Production. The following table illustrates the primary components of oil and natural gas revenues for the three months ended June 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 June 30,								Increase /
		2005				2004				(Decrease)
										$				%
Revenues:
Oil wellhead		$	80,178			$	60,638			$	19,540
Oil hedges			(10,619	)			(7,753	)			(2,866	)
Total Oil Revenues		$	69,559			$	52,885			$	16,674				32%
Natural gas wellhead		$	32,448			$	17,948			$	14,500
Natural gas hedges			(2,290	)			(711	)			(1,579	)
Total Natural Gas Revenues		$	30,158			$	17,237			$	12,921				75%
Combined wellhead		$	112,626			$	78,586			$	34,040
Combined hedges			(12,909	)			(8,464	)			(4,445	)
Total Combined Revenues		$	99,717			$	70,122			$	29,595				42%
Revenues ($/Unit):
Oil wellhead		$	47.21			$	35.90			$	11.31
Oil hedges			(6.25	)			(4.58	)			(1.67	)
Total Oil Revenues		$	40.96			$	31.32			$	9.64				31%
Natural gas wellhead		$	6.57			$	5.59			$	0.98
Natural gas hedges			(0.46	)			(0.22	)			(0.24	)
Total Natural Gas Revenues		$	6.11			$	5.37			$	0.74				14%
Combined wellhead		$	44.69			$	35.35			$	9.34
Combined hedges			(5.13	)			(3.81	)			(1.32	)
Total Combined Revenues		$	39.56			$	31.54			$	8.02				25%

		Three months ended June 30,								Increase /
		2005				2004				(Decrease)
Total production volumes:
Oil (Bbls)			1,698				1,689				9
Natural gas (Mcf)			4,933				3,209				1,724
Combined (BOE)			2,520				2,223				297
Daily production volumes:
Oil (Bbls/day)			18,662				18,557				105
Natural gas (Mcf/day)			54,213				35,260				18,953
Combined (BOE/day)			27,697				24,434				3,263
NYMEX Prices:
Oil (per Bbl)		$	53.17			$	38.32			$	14.85
Natural gas (per Mcf)			6.95				6.07				0.88

     Oil revenues increased from second quarter 2004 to second quarter 2005 by $16.7 million, due primarily to a higher realized average oil price. Our realized average oil price increased $9.64 per Bbl in the second quarter of 2005 over the same period in 2004 as a result of an increase in our average wellhead price of $11.31 per Bbl, offset by an increase in hedging payments of $1.67 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 $14.85 per Bbl increase in the average NYMEX price over the same period.

     Natural gas revenues increased by $12.9 million, or $0.74 per Mcf, in the second quarter of 2005 from the second quarter of 2004 due to an increase in volumes and an increase in our realized average natural gas price. Production volumes increased 1,724 MMcf in the second quarter of 2005 as compared to the second quarter of 2004 due to our drilling activities and the Overton acquisition, which closed on June 17, 2004, and is included in our financial statements beginning July 1, 2004. The $0.74 per Mcf increase in our realized average natural gas price was due to the $0.98 per Mcf increase in the wellhead price for our natural gas from the second quarter of 2004 to the second quarter of 2005. The NYMEX price for natural gas increased by $0.88 per Mcf over the same period.

     The table below illustrates the relationship between oil and natural gas wellhead prices and average NYMEX prices for the quarters ended June 30, 2005 and 2004:

		Three months ended June 30,
		2005				2004
Oil wellhead ($/Bbl)		$	47.21			$	35.90
Average NYMEX ($/Bbl)		$	53.17			$	38.32
Differential to NYMEX		$	(5.96	)		$	(2.42	)
Oil wellhead to NYMEX percentage			89	%			94	%
Natural gas wellhead ($/Mcf)		$	6.57			$	5.59
Average NYMEX ($/Mcf)		$	6.95			$	6.07
Differential to NYMEX		$	(0.38	)		$	(0.48	)
Natural gas wellhead to NYMEX percentage			95	%			92	%

     Management uses this wellhead to NYMEX margin analysis to assess trends in our anticipated oil and natural gas revenues. As indicated, our oil differential to the NYMEX price widened from the second quarter of 2004 to the second quarter of 2005 as NYMEX increased at a higher rate than our average wellhead price increased. This oil differential between our wellhead price received and NYMEX has been wider primarily as differentials tend to widen in a period of higher general oil prices. We also have been adversely affected by wider differentials in the market price for our production in two particular areas: the Permian Basin, where much of our production has been tied to a West Texas Sour price, and the Rockies, where much of our production has been tied to a Wyoming Sweet price. Both the West Texas Sour differential and the Wyoming Sweet differential have widened in the second quarter of 2005 versus the second quarter of 2004, and each has therefore contributed to a widening of our overall oil wellhead differential to NYMEX.

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

		Three months ended June 30,								Increase/
		2005				2004				(Decrease)
										$				%
Expenses (in thousands):
Production —
Lease operations		$	15,721			$	10,921			$	4,800
Production, ad valorem, and severance taxes			9,813				7,161				2,652
Total production expenses			25,534				18,082				7,452				41%
Other —
Depletion, depreciation, and amortization			19,038				11,249				7,789
Exploration			3,772				1,697				2,075
General and administrative (excluding non-cash stock based compensation)			3,571				2,530				1,041
Non-cash stock based compensation			1,006				307				699
Derivative fair value loss			1,692				965				727
Other operating			1,703				1,091				612
Total operating			56,316				35,921				20,395				57%
Interest			7,448				6,308				1,140
Current and deferred income tax provision			12,370				10,008				2,362
Total expenses		$	76,134			$	52,237			$	23,897				46%
Expenses (per BOE):
Production —
Lease operations		$	6.24			$	4.91			$	1.33
Production, ad valorem, and severance taxes			3.89				3.22				0.67
Total production expenses			10.13				8.13				2.00				25%
Other —
Depletion, depreciation, and amortization			7.55				5.06				2.49
Exploration			1.50				0.76				0.74
General and administrative (excluding non-cash stock based compensation)			1.42				1.14				0.28
Non-cash stock based compensation			0.40				0.14				0.26
Derivative fair value loss			0.67				0.43				0.24
Other operating			0.68				0.50				0.18
Total operating			22.35				16.16				6.19				38%
Interest			2.96				2.84				0.12
Current and deferred income tax provision			4.91				4.50				0.41
Total expenses		$	30.22			$	23.50			$	6.72				29%

     Production expenses (Lease operations and production, ad valorem, and severance taxes). Total production expenses for the second quarter of 2005 increased $7.5 million as compared to the second quarter of 2004. This increase resulted from an increase in total production volumes, as well as a $2.00 increase in production expenses per BOE in the second quarter of 2005 as compared to the second quarter of 2004. The $2.00 increase in production expenses per BOE in the second quarter of 2005 represents a 25% increase over the second quarter of 2004. This increase is in line with the 25% increase in revenues per BOE over the same period, giving rise to a 26% increase in our production margin (revenues less production expenses) per BOE, which increased from $23.41 in the second quarter of 2004 to $29.43 in the second quarter of 2005.

     The production expense attributable to lease operations for the second quarter of 2005 increased as compared to the second quarter of 2004 by $4.8 million. The increase in total lease operations expense resulted from an increase in production volumes as a result of our 2005 drilling program, the Overton acquisition, and our high-pressure air injection (“HPAI”) program; and an increase in the per BOE rate. The increase in our average per BOE rate was attributable to increase in prices paid for outside services due to a current higher price environment, increased operational activity to maximize production, and the addition of higher operating cost barrels as lower margin wells are operated in the current higher price environment. LOE expenses are expected to increase because of a continued high-price environment and in the third quarter we expect to begin expensing HPAI costs attributable to Little Beaver Phase 1 that previously have been capitalized during the pressurization phase. We expect additional LOE costs for HPAI to be approximately $0.7 million in the third quarter of 2005.

     The production expense attributable to production, ad valorem, and severance taxes for the second quarter of 2005 increased as compared to the same period in 2004 by approximately $2.7 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 second quarter of 2005 decreased to 8.7% from 9.1% in the second 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 second quarter of 2005 increased by $7.8 million as compared to the second quarter of 2004, due to a $2.49 increase in the per BOE rate and an increase in production. This per BOE rate increase was due to the 2004 acquisitions, which had higher acquisition costs than our historical average, as well as higher drilling costs per BOE of reserves than our historical DD&A rate in certain areas.

     Exploration expense. Exploration expense was $3.8 million in the second quarter of 2005, while it was $1.7 million in the second quarter of 2004. During the second quarter of 2005, we expensed twelve exploratory dry holes totaling $2.0 million. Out of the twelve exploratory dry holes expensed, one was drilled in the CCA and eleven were drilled in the shallow gas area of Montana. In the second quarter of 2004, we had one dry hole drilled in the Barnett Shale area that was spud by Cortez and acquired in the Cortez acquisition. The following table details our exploration-related expenses for the second quarter of 2005 and 2004 (in thousands):

		Three months ended June 30,								Increase /
		2005				2004				(Decrease)
Exploration expenses:
Dry hole		$	2,010			$	1,697			$	313
Geological and geophysical			278				—				278
Seismic			965				—				965
Delay rental			108				—				108
Impairment of undeveloped leasehold			411				—				411
Total		$	3,772			$	1,697			$	2,075

     General and administrative (“G&A”) expense. G&A expense (excluding non-cash stock based compensation) increased $1.0 million for the second quarter of 2005 as compared to the second quarter of 2004. The overall increase, as well as the $0.28 increase in the per BOE rate, is a result of increased staffing to manage our larger asset base, higher rent expense for our corporate office, and higher directors’ and officers’ insurance costs. 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 second 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. Both deferred compensation and related amortization increased from second quarter 2004 to second quarter 2005 as the Company’s stock price per share increased and the number of shares granted in the second quarter of 2005 increased as compared to the second quarter of 2004.

     Derivative fair value loss. During the second quarter of 2005 we recorded a $1.7 million derivative fair value loss as compared to the $1.0 million loss recorded in the second 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 second quarter of 2005 and 2004 are as follows (in thousands):

		Three months ended June 30,								Increase /
		2005				2004				(Decrease)
Designated cash flow hedges:
Ineffectiveness – Commodity contracts		$	1,942			$	181			$	1,761
Undesignated derivative contracts:
Mark-to-market (gain) loss – Interest rate swap			(31	)			1,130				(1,161	)
Mark-to-market (gain) loss – Commodity contracts			(219	)			(346	)			127
Derivative fair value loss		$	1,692			$	965			$	727

     Ineffectiveness loss related to our derivative commodity contracts increased $1.8 million due primarily to an increase in oil wellhead differentials on our production in the CCA.

     Other operating expense. Other operating expense for the second quarter of 2005 increased by $0.6 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 second quarter of 2005 over the same period in 2004.

     Interest expense. Interest expense increased $1.1 million in the quarter ended June 30, 2005 from the quarter ended June 30, 2004. This increase is due primarily to an increase in debt outstanding under our credit facility, offset slightly by a decrease in our weighted average interest rate from period to period. We incurred additional debt in the second quarter of 2004 to fund the Cortez and Overton acquisitions and to fund the Company’s development, exploitation, and exploration capital programs. The weighted average interest rate, net of hedges, for the quarter ended June 30, 2005 was 7.0% compared to 7.9% for the quarter ended June 30, 2004. This lower weighted average interest rate is the result of the issuance of $150 million aggregate principal amount of 6¹/4% senior subordinated notes in April 2004. The following table illustrates the components of interest expense for the three months ended June 30, 2005 and 2004 (in thousands):

		Three months ended June 30,								Increase /
		2005				2004				(Decrease)
83/8% notes due 2012 (2)		$	3,141			$	3,141			$	—
61/4% notes due 2014			2,344				2,318				26
Revolving credit facility			1,367				230				1,137
Interest rate hedges (1)			(72	)			153				(225	)
Debt issuance cost			277				262				15
Banking fees and other			391				204				187
Total		$	7,448			$	6,308			$	1,140

     Income taxes. Income tax expense for the second quarter of 2005 increased $2.4 million over the same period in 2004. This increase is due primarily to the $8.0 million increase in income before income taxes from the second quarter of 2004 to the second quarter of 2005, offset by a decrease in our effective tax rate from 35.7% for the second quarter in 2004 to 34.3% in the second quarter of 2005.

Comparison of Six Months Ended June 30, 2005 to Six Months Ended June 30, 2004

     Set forth below is our comparison of operations during the first six months of 2005 with the first six months of 2004.

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

		Six months ended June 30,								Increase /
		2005				2004				(Decrease)
										$				%
Revenues:
Oil wellhead		$	156,898			$	113,017			$	43,881
Oil hedges			(20,203	)			(13,368	)			(6,835	)
Total Oil Revenues		$	136,695			$	99,649			$	37,046				37%
Natural gas wellhead		$	58,124			$	30,870			$	27,254
Natural gas hedges			(3,521	)			(1,106	)			(2,415	)
Total Natural Gas Revenues		$	54,603			$	29,764			$	24,839				83%
Combined wellhead		$	215,022			$	143,887			$	71,135
Combined hedges			(23,724	)			(14,474	)			(9,250	)
Total Combined Revenues		$	191,298			$	129,413			$	61,885				48%
Revenues ($/Unit):
Oil wellhead		$	46.11			$	34.25			$	11.86
Oil hedges			(5.94	)			(4.05	)			(1.89	)
Total Oil Revenues		$	40.17			$	30.20			$	9.97				33%
Natural gas wellhead		$	6.20			$	5.38			$	0.82
Natural gas hedges			(0.38	)			(0.19	)			(0.19	)
Total Natural Gas Revenues		$	5.82			$	5.19			$	0.63				12%
Combined wellhead		$	43.30			$	33.82			$	9.48
Combined hedges			(4.78	)			(3.40	)			(1.38	)
Total Combined Revenues		$	38.52			$	30.42			$	8.10				27%