UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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                    .

Commission File No. 001-11899

THE HOUSTON EXPLORATION COMPANY

Delaware		22-2674487
(State or Other Jurisdiction of		(IRS Employer Identification No.)
Incorporation or Organization)
1100 Louisiana, Suite 2000
Houston, Texas		77002-5215
(Address of Principal Executive Offices)		(Zip Code)

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 Act).
Yes þ No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes o No þ

As of November 8, 2005, 28,96,103 shares of Common Stock, par value $0.01 per share, were outstanding.

 

 

TABLE OF CONTENTS

Forward-Looking Statements and Other Information			2
Part I. Financial Information			4
Item 1. Condensed Consolidated Financial Statements			4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 3. Quantitative and Qualitative Disclosures About Market Risk			30
Item 4. Controls and Procedures			33
Part II. Other Information			33
Item 5. Other Information			33
Item 6. Exhibits			34
SIGNATURES			35
Compensation Table for Executive Officers
Computation of ratio of earnings to fixed charges
Certification of CEO pursuant to Section 302
Certification of CFO pursuant to Section 302
Certification of CEO pursuant to Section 906
Certification of CFO pursuant to Section 906

Forward-Looking Statements and Other Information

All of the estimates and assumptions contained in this Quarterly Report on Form 10-Q (“Quarterly Report”) constitute forward-looking statements as that term is defined in Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements include information concerning our reserves and production, future production, plans and capital expenditures, as well as those statements using forward-looking words such as “anticipate,” “believe,” “continue,” “expect,” “estimate,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “should,” “target,” “goal,” “objective” or other similar expressions and discuss forward-looking information. Forward-looking statements include all statements under the caption “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” involving the discussion of the following:

	n		business strategy;
	n		natural gas and oil reserves;
	n		future production;
	n		hedge positions;
	n		expected realized natural gas and oil prices;
	n		expected costs and expenses;
	n		anticipated capital expenditures and financings;
	n		future operating results;
	n		future cash flows and borrowings;
	n		pursuit of potential future acquisition or disposition opportunities;
	n		potential stock repurchases;
	n		future tax payments;
	n		identified drilling locations; and
	n		sources of funding and the timing of exploration and development activities.

Although we believe that these forward-looking statements are based on reasonable assumptions, our expectations may not occur, and we cannot guarantee that the anticipated future results will be achieved. A number of factors could cause our actual future results to differ materially from those anticipated or implied in the forward-looking statements. These factors include, among other things:

	n		the volatility of natural gas and oil prices;
	n		the requirement to take writedowns if natural gas and oil prices decline or if our finding and development costs continue to increase;
	n		the relatively short production lives of our reserves; · our ability to find, replace, develop and acquire natural gas and oil reserves;
	n		consummation and integration of the pending South Texas acquisition;
	n		our ability to dispose of our Gulf of Mexico assets;
	n		our ability to maximize tax efficiencies involving tax free asset exchanges transactions;
	n		the maturity of North American gas basins;
	n		acquisition and investment risks;
	n		our ability to manage rising costs;
	n		our ability to meet our substantial capital requirements;
	n		our outstanding indebtedness and pending credit agreement amendment;
	n		the uncertainty of estimates of natural gas and oil reserves and production rates;
	n		the inherent hazards and risks involved in our operations;
	n		dependence upon geographically concentrated operations;
	n		drilling risks;
	n		our hedging activities;
	n		compliance with environmental and other governmental regulations;
	n		stock market conditions;
	n		the competitive nature of our industry;
	n		weather risks and other natural disasters;
	n		the ability to resume curtailed production caused by damage to third party pipelines and facilities; and
	n		our customers’ ability to meet their obligations.

For additional discussion of these and other risks, uncertainties and assumptions, see “Items 1 and 2. Business and Properties” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2004. We undertake no obligation to publicly update or revise any forward-looking statements.

In this Quarterly Report, unless the context requires otherwise, when we refer to “we,” “us,” “our” and “Houston Exploration,” we are describing The Houston Exploration Company including, through May 31, 2004, our former

subsidiary Seneca-Upshur Petroleum, Inc., and subsequent to October 8, 2004, THEC, LLC and THEC, LP on a consolidated basis.

If you are not familiar with the natural gas and oil terms used in this Quarterly Report, please refer to the explanations of the terms under the caption “Glossary of Natural Gas and Oil Terms” included on pages G-1 through G-2 of our Annual Report on Form 10-K for the year ended December 31, 2004. When we refer to “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one barrel of oil is equal to six thousand cubic feet of natural gas. Unless otherwise stated, all reserve and production quantities are expressed net to our interests.

Part I. Financial Information

Item 1. Condensed Consolidated Financial Statements

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
(Unaudited)

		September 30,				December 31,
		2005				2004
Assets:
Cash and cash equivalents		$	8,777			$	18,577
Accounts receivable			129,261				103,069
Inventories			2,329				976
Deferred tax asset			173,898				24,101
Prepayments and other			17,660				9,107
Total current assets			331,925				155,830
Natural gas and oil properties, full cost method
Unevaluated properties			122,085				122,691
Properties subject to amortization			3,202,764				2,777,097
Other property and equipment			12,475				11,740
			3,337,324				2,911,528
Less: Accumulated depreciation, depletion and amortization			1,578,430				1,363,272
			1,758,894				1,548,256
Other non-current assets			16,674				18,491
Total Assets		$	2,107,493			$	1,722,577
Liabilities:
Accounts payable and accrued expenses		$	155,296			$	118,971
Derivative financial instruments			537,139				68,081
Asset retirement obligation			1,503				662
Total current liabilities			693,938				187,714
Long-term debt and notes			349,000				355,000
Derivative financial instruments			159,540				7,068
Deferred income taxes			272,688				288,069
Asset retirement obligation			99,701				91,084
Other non-current liabilities			15,450				10,722
Total Liabilities			1,590,317				939,657
Commitments and Contingencies (see Note 4)
Stockholders’ Equity:
Preferred Stock, $0.01 par value, 5,000,000 shares authorized and no shares issued			—				—
Common Stock, $.01 par value, 100,000,000 shares authorized and 28,847,363 shares issued and outstanding at September 30, 2005 and 50,000,000 shares authorized and 28,380,207 shares outstanding at December 31, 2004			288				284
Additional paid-in capital			297,958				273,002
Unearned compensation			(7,652	)			(2,537	)
Retained earnings			643,547				558,198
Accumulated other comprehensive (loss)			(416,965	)			(46,027	)
Total Stockholders’ Equity			517,176				782,920
Total Liabilities and Stockholders’ Equity		$	2,107,493			$	1,722,577

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

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Revenues:
Natural gas and oil revenues		$	124,997			$	162,472			$	466,011			$	486,684
Other			416				288				939				734
Total revenues			125,413				162,760				466,950				487,418
Operating expenses:
Lease operating			17,771				14,301				52,263				39,506
Severance tax			4,165				3,356				11,629				10,304
Transportation expense			3,000				3,006				8,759				8,911
Asset retirement accretion expense			1,313				1,098				3,964				3,576
Depreciation, depletion and amortization			72,702				66,926				215,249				195,082
General and administrative, net of amounts capitalized			10,229				5,679				27,552				21,528
Total operating expenses			109,180				94,366				319,416				278,907
Income from operations			16,233				68,394				147,534				208,511
Other (income) expense			(101	)			(1,588	)			286				(1,856	)
Interest expense, net of amounts capitalized			3,541				2,000				10,171				6,593
Income before income taxes			12,793				67,982				137,077				203,774
Provision for taxes			4,712				24,984				51,728				75,736
Net income		$	8,081			$	42,998			$	85,349			$	128,038
Earnings per share:
Net income per share — basic		$	0.28			$	1.53			$	2.98			$	4.26
Net income per share — diluted		$	0.28			$	1.51			$	2.95			$	4.22
Weighted average shares outstanding — basic			28,744				28,082				28,641				30,068
Weighted average shares outstanding — diluted			29,120				28,486				28,966				30,330

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

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)

		Nine Months Ended				September 30,
		2005				2004
Operating Activities:
Net income		$	85,349			$	128,038
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			215,249				195,082
Deferred income tax expense			39,202				39,585
Asset retirement accretion expense			3,964				3,576
Stock compensation expense			3,719				2,044
Tax benefit non-qualified stock options			2,909				3,529
Loss due to ineffectiveness of derivative instruments			47,324				2,600
Amortization of premiums paid on derivative contracts			—				4,432
Debt extinguishment			—				211
Changes in operating assets and liabilities:
Accounts receivable			(26,192	)			(9,749	)
Inventories			(1,353	)			(183	)
Prepayments and other			(9,665	)			519
Other non-current assets			1,817				(2,784	)
Accounts payable and accrued expenses			16,930				29,381
Other non-current liabilities			4,728				8,590
ARO liability for assets abandoned			—				(2,569	)
Net cash provided by operating activities			383,981				402,302
Investing Activities:
Investment in property and equipment			(401,881	)			(296,752	)
Deposit paid for property acquisition			—				(11,350	)
Dispositions and other			883				13,425
Net cash used in investing activities			(400,998	)			(294,677	)
Financing Activities:
Proceeds from long-term borrowings			364,000				247,000
Repayments of long-term borrowings			(370,000	)			(294,000	)
Debt issue costs			—				(1,555	)
Proceeds from issuance of common stock from exercise of stock options			13,218				20,934
Proceeds from issuance of common stock			—				310,727
Repurchase of common stock			—				(388,979	)
Net cash provided by (used in) financing activities			7,218				(105,873	)
(Decrease) Increase in cash and cash equivalents			(9,800	)			1,752
Cash and cash equivalents, beginning of period			18,577				2,569
Cash and cash equivalents, end of period		$	8,777			$	4,321
Supplemental Information:
Non-cash transactions:
Divesture and exchange of Appalachian Basin assets		$	—			$	60,000
Investments in property and equipment accrued, not paid			(19,395	)			(5,628	)
Cash paid during period for:
Interest		$	12,664			$	8,649
Federal and state income taxes			19,297				35,900

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

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1 — Summary of Organization and Significant Accounting Policies

Our Business

We are an independent natural gas and oil producer concentrating on growing reserves and production through the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. Currently, our core areas of operations are South Texas, offshore in the shallow waters of the Gulf of Mexico, the Arkoma Basin of Oklahoma and Arkansas and the Rocky Mountain region where, during 2003, we began operations with an initial focus in the Uinta Basin of northeastern Utah and during 2004, we expanded our focus to the DJ Basin in Eastern Colorado. On November 8, 2005, we announced plans to divest all our Gulf of Mexico assets and shift our operational focus to onshore North America. See Note 7 – Subsequent Events.

We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and oil on behalf of KeySpan Corporation, our then parent company. In September 1996, we completed our initial public offering and sold approximately 31% of our shares to the public. Through a series of three separate transactions, the first in February 2003 and the last in November 2004, KeySpan completely divested of its interest in our stock.

Principles of Consolidation

Our consolidated financial statements for the period ended September 30, 2005, include our accounts and the accounts of our wholly-owned subsidiaries.

Our consolidated financial statements for the period ended September 30, 2004, include our accounts and the accounts of our 100% owned subsidiary, Seneca-Upshur Petroleum, Inc. until June 2, 2004, when we conveyed all of the shares of Seneca-Upshur to KeySpan in connection with an asset exchange transaction. At that time, Seneca-Upshur was our only subsidiary. Seneca-Upshur is a natural gas exploration and production company located in West Virginia.

All significant inter-company balances and transactions have been eliminated.

Interim Financial Statements

Our balance sheet at September 30, 2005, and the statements of operations and cash flows for the periods indicated herein have been prepared without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been condensed or omitted, although we believe that the disclosures contained herein are adequate to make the information presented not misleading. Our balance sheet at December 31, 2004, is derived from our December 31, 2004 audited financial statements, but does not include all disclosures required by GAAP. The financial statements included herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2004.

In the opinion of our management, these financial statements reflect all adjustments necessary for a fair statement of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. The results of operations for such interim periods are not necessarily indicative of the results for the full year.

Use of Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Our most significant financial estimates are based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key components of our depletion rate for natural gas and oil properties, our unevaluated properties and our full cost ceiling test. In addition, estimates are used in computing taxes, preparing accruals of operating costs and production revenues, asset retirement obligations, fair value and effectiveness of derivative instruments and fair value of stock options and the related compensation expense. Because there are numerous uncertainties inherent in the estimation process, actual results could differ materially from these estimates.

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Reclassifications

Certain reclassifications have been made to prior year amounts to conform to the current year presentation.

Business Segment Information

The Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 131, “Disclosures about Segments of an Enterprise and Related Information,” establishes standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engages in activities from which it may earn revenues and incur expenses, separate financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.

Segment reporting is not applicable for us as each of our operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in SFAS 131. All of our operations involve the exploration, development and production of natural gas and oil, and all of our operations are located in the United States. We have a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments. We track only basic operational data by area, and do not maintain separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, we freely allocate capital resources on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas or segments.

Revenue Recognition and Gas Imbalances

We use the entitlements method of accounting for the recognition of natural gas and oil revenues. Under this method of accounting, income is recorded based on our net revenue interest in production or nominated deliveries. We incur production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over-and under-deliveries or by cash settlement, as required by applicable contracts. Production imbalances are marked-to-market at the end of each month at the lowest of (i) the price in effect at the time of production; (ii) the current market price; or (iii) the contract price, if a contract is in hand.

At September 30, 2005, we had production imbalances representing assets of $3.2 million and liabilities of $7.6 million. At December 31, 2004, we had production imbalances representing assets of $3.3 million and liabilities of $4.0 million. The primary sources of our production imbalances relate to Eugene Island 331, acquired in October 2003 from Transworld Exploration and Production Inc., and to various Arkoma wells. Production imbalances are included in the line items “other non-current assets” and “other non-current liabilities” on the balance sheet.

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Net Income Per Share

Basic earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. No dilution for any potentially dilutive securities is included. Fully diluted earnings per share assumes the conversion of all potentially dilutive securities and is calculated by dividing net income by the sum of the weighted average number of shares of common stock outstanding plus all potentially dilutive securities.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
		(in thousands, except per share data)
Numerator:
Net income		$	8,081			$	42,998			$	85,349			$	128,038
Denominator:
Weighted average shares outstanding			28,744				28,082				28,641				30,068
Add dilutive securities: Stock options			376				404				325				262
Total weighted average shares outstanding and dilutive securities			29,120				28,486				28,966				30,330
Earnings per share – basic:		$	0.28			$	1.53			$	2.98			$	4.26
Earnings per share – diluted:		$	0.28			$	1.51			$	2.95			$	4.22

For the three months ended September 30, 2005 and 2004, the calculation of shares outstanding for diluted earnings per share does not include the effect of outstanding stock options to purchase 407,960 and 404,001 shares, respectively, because the exercise price of these shares was greater than the average market price for the year, which would have an antidulitive effect on earnings per share. For the nine months ended September 30, 2005 and 2004, the calculation of shares outstanding for diluted earnings per share does not include the effect of outstanding stock options to purchase 394,513 and 907,956 shares, respectively, because the exercise price of these shares was greater than the average market price for the year, which would have an antidulitive effect on earnings per share.

Comprehensive Income (Loss)

Comprehensive income includes net income and certain items recorded directly to stockholders’ equity and classified as other comprehensive income. The table below summarizes comprehensive income and provides the components of the change in accumulated other comprehensive income for the three-month and nine-month periods ended September 30, 2005 and 2004.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
		(in thousands)
Net income		$	8,081			$	42,998			$	85,349			$	128,038
Other comprehensive income (loss) Derivative contracts settled and reclassified, net of tax			40,192				6,990				65,069				23,011
Change in unrealized (loss) fair value of open derivative contracts, net of tax			(311,008	)			(34,680	)			(436,007	)			(92,463	)
Total other comprehensive income (loss)			(270,816	)			(27,690	)			(370,938	)			(69,452	)
Comprehensive income (loss)		$	(262,735	)		$	15,308			$	(285,589	)		$	58,586

Natural Gas and Oil Properties

Full Cost Accounting. We use the full cost method to account for our natural gas and oil properties. Under full cost accounting, all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are capitalized into a “full cost pool.” Capitalized costs include costs of all unproved properties, internal costs directly related to our natural gas and oil activities and capitalized interest. We amortize these costs using a unit-of-production method. We compute the provision for depreciation, depletion and amortization quarterly by multiplying production for the quarter by a

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

depletion rate. The depletion rate is determined by dividing our total unamortized cost base by net equivalent proved reserves at the beginning of the quarter. Our total unamortized cost base is the sum of our:

	n		full cost pool (including assets associated with retirement obligations); plus,
	n		estimates for future development costs (excluding asset retirement obligations); less,
	n		unevaluated properties and their related costs; less,
	n		estimates for salvage.

Costs associated with unevaluated properties are excluded from the amortization base until we have made a determination as to the existence of proved reserves. We review our unevaluated properties at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and thereby subject to amortization. Sales of natural gas and oil properties are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a writedown or impairment of the full cost pool is required. A writedown of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a writedown is not reversible at a later date.

The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. We use derivative financial instruments that qualify for cash flow hedge accounting under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” to hedge against the volatility of natural gas prices, and in accordance with SEC guidelines, we include estimated future cash flows from our hedging program in our ceiling test calculation. In addition, subsequent to the adoption of SFAS 143, “Accounting for Asset Retirement Obligations,” the future cash outflows associated with settling asset retirement obligations are excluded from the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.

Unevaluated Properties. The costs associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination has been made or upon expiration of a lease. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. We estimate that these costs will be evaluated within a four-year period.

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Asset Retirement Obligations

For us, asset retirement obligations (“ARO”) represent the future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. SFAS 143, “Accounting for Asset Retirement Obligations,” requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. We carry ARO assets on the balance sheet as part of our full cost pool, and include these ARO assets in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability are excluded from the computation of the discounted present value of estimated future net revenues.

The following table describes changes in our ARO liability during the nine-month periods ended September 30, 2005 and 2004. The ARO liability in the table below includes amounts classified as both current and long-term at period end.

		Nine Months Ended
		September 30,
		2005				2004
		(in thousands)
ARO liability at January 1		$	91,746			$	92,357
Accretion expense			3,963				3,576
Liabilities incurred from drilling			5,496				4,982
Liabilities incurred from assets acquired			169				7,626
Liabilities settled — assets sold			(32	)			(12,714	)
Liabilities settled — assets abandoned			(937	)			(4,287	)
Changes in estimates			799				—
ARO liability at September 30		$	101,204			$	91,540

Derivative Instruments and Hedging Activities

Our hedging policy does not permit us to hold derivative instruments for trading purposes and mandates that all hedge structures meet the definition of cash flow hedges to qualify for hedge accounting under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and that all hedge transactions are specifically identified as hedges for Federal income tax purposes as defined in Section 1221(b)(2) of the Internal Revenue Code. Our hedging policy allows us the flexibility to implement a wide variety of hedging strategies, including swaps, collars and options. We generally execute contracts with significant, creditworthy financial institutions and, to a lesser extent, other counterparties. Although our hedging program protects a portion of our cash flows from downward price movements, certain hedging strategies, specifically the use of swaps and collars, may also limit our ability to realize the full benefit of future price increases, as in recent years. In addition, because our derivative instruments are typically indexed to New York Mercantile Exchange (“NYMEX”) prices, as opposed to the index price where the gas is actually sold, our hedging strategy will not fully protect our cash flows when, as in recent quarters, the price differential increases between the NYMEX price and index price for the point of sale.

Our derivative instruments qualify for hedge accounting. Consequently, we carry the fair market value of our derivative instruments on the balance sheet as either an asset or liability and defer unrealized gains or losses in accumulated other comprehensive income. Gains and losses are reclassified from accumulated other comprehensive income to the income statement as a component of natural gas and oil revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the income statement and would be included as a component of the line item “natural gas and oil revenues.” For us, ineffectiveness is primarily a result of changes at the end of the current period in the price differentials between the index price of the derivative contract, which uses a NYMEX index, and index price for the point of sale for the cash flow that is being hedged, the majority of which is the Houston Ship Channel index. For the three-month and nine-month periods ended September 30, 2005, we recorded losses due to ineffectiveness of open contracts of $45.9 million ($29.6 million net of tax) and $47.3 million ($30.6 million net of tax), respectively. At September 30, 2005, our open derivative contracts extend through the remaining three months of 2005 and continue through 2006, 2007 and 2008.

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Based on market prices at September 30, 2005, we recorded an unrealized loss in accumulated other comprehensive income of $417.0 million, net of tax, representing the fair value of our open derivative contracts. Any loss will be realized in future earnings at the time of the related sales of natural gas production applicable to specific hedges. If prices in effect at September 30, 2005 were to remain unchanged, over the next 12-month period, we would expect to reclassify from accumulated other comprehensive income to earnings a loss of $318.2 million, net of tax, relating to our open derivative contracts. However, these amounts could vary materially as a result of changes in market conditions. See Note 7 – Subsequent Events for a description of a plan to liquidate a portion of our hedge positions concurrent with the divesture of our Gulf of Mexico assets.

We enter into a substantial portion of our hedge contracts with counterparties who are participant banks in our revolving bank credit facility. Under our arrangements with these banks, we generally have no margin obligation so long as the counterparty remains in our bank group or is otherwise secured pari passu with our bank group. As to other counterparties, with one exception, we have no margin obligation so long as we satisfy credit rating thresholds with prescribed rating agencies. In one instance we have a margin exposure threshold, above which we must provide the counterparty margin to secure our hedge obligations. At September 30, 2005, we had $17 million in outstanding letters of credit relating to this derivative contract, which contract expires December 31, 2005.

Accounting for Stock Options and Restricted Stock

On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS 148, “Accounting for Stock–Based Compensation – Transition and Disclosure” using the “prospective method” as defined by the SFAS 148. As a result, we recorded as compensation expense the fair value of all stock options issued subsequent to January 1, 2003. No expense for stock options has been recorded for grants made in years prior to January 1, 2003. Prior to 2003, we accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options was measured as the excess, if any, of the fair value of common stock at the date of the grant over the amount the employee must pay to acquire the common stock. If the exercise price of a stock option was equal to the fair market value at the time of grant, no compensation expense was incurred. If we had accounted for all stock options using the fair value method as recommended in SFAS 123, compensation expense would have had the following pro forma effect on our net income and earnings per share for the three months and nine months ended September 30, 2005 and 2004.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
		(in thousands, except share data)
Net income – as reported		$	8,081			$	42,998			$	85,349			$	128,038
Add: Stock-based compensation expense included in net income, net of tax			831				361				1,705				1,016
Less: Stock-based compensation expense determined using fair value method, net of tax			(1,183	)			(1,266	)			(2,769	)			(3,999	)
Net income – pro forma		$	7,729			$	42,093			$	84,285			$	125,055
Net income per share – basic – as reported		$	0.28			$	1.53			$	2.98			$	4.26
Net income per share – diluted – as reported			0.28				1.51				2.95				4.22
Net income per share – basic – pro forma		$	0.27			$	1.50			$	2.94			$	4.16
Net income per share – diluted – pro forma			0.27				1.48				2.91				4.12

The effects of applying SFAS 123 in this pro forma disclosure may not be representative of future amounts. The weighted average fair value of options at their grant date for the first nine months of 2005 and 2004 were $21.05 and $17.23, respectively. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions, which are averages, used for grants during the nine months ended September 30, 2005 and 2004:

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

		Nine Months Ended
		September 30,
		2005				2004
Risk-free interest rate			4.0	%			3.7	%
Expected years until exercise			5				5
Expected stock volatility			34.0	%			37.2	%
Expected dividends			—				—

For the risk-free interest rate, we utilize daily rates for five-year United States treasury bills with constant maturity. The expected life is based on historical exercise activity over the previous nine-year period. The expected volatility is based on historical volatility and measured using the average closing price of our stock over a 60-month period. We believe historical volatility is the most accurate measure of future volatility of our common stock.

The following table provides the detail of stock compensation expenses incurred during each of the three-month and nine-month periods ended September 30, 2005 and 2004:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
		(in thousands)
Options		$	1,185			$	684			$	2,768			$	1,588
Restricted stock			512				31				951				456
Stock compensation expense, gross			1,697				715				3,719				2,044
Amounts capitalized			(581	)			(159	)			(1,250	)			(481	)
Stock compensation expense, net of amounts capitalized		$	1,116			$	556			$	2,469			$	1,563

Recent Accounting Pronouncements

On December 16, 2004, the FASB revised Statement 123 (revised 2004), “Share-Based Payment” that will require compensation costs related to share-based payment transactions (e.g., issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. Statement 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” For us, SFAS 123(R), as amended by SEC Release 34-51558, is effective for our first fiscal year beginning after June 15, 2005, or January 1, 2006. Entities that use the fair-value-based method for either recognition or disclosure under SFAS 123 are required to apply SFAS 123(R) using a modified version of prospective application. Under this method, an entity records compensation expense for all awards it grants after the date of adoption. In addition, the entity is required to record compensation expense for the unvested portion of previously granted awards that remain outstanding at the date of adoption. In addition, entities may elect to adopt SFAS 123(R) using a modified retrospective method whereby previously issued financial statements are restated based on the expense previously calculated and reported in their pro forma footnote disclosures.

On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” using the “prospective method” as defined by the SFAS 148. As a result, we have recognized compensation expense for all stock options granted subsequent to January 1, 2003, with no expense recognized for grants made prior to 2003. Adoption of SFAS 123(R) will require us to recognize compensation expense over the remaining service period for the unvested portion of all options granted during 2000, 2001 and 2002. All options granted prior to 2000 are fully vested. We continue to evaluate the effect of adopting SFAS 123(R) and we do not believe the adoption will have a material impact to our financial statements.

On March 29, 2005, the SEC released Staff Accounting Bulletin (“SAB”) 107 providing additional guidance in applying the provisions of SFAS 123(R), “Share-Based Payment.” SAB 107 should be applied when adopting SFAS 123(R) and addresses a wide range of issues, focusing on valuation methodologies and the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC guidance.

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 2 — Long-Term Debt and Notes

		September 30, 2005				December 31, 2004
		(in thousands)
Senior Debt:
Revolving bank credit facility, due April 1, 2008		$	174,000			$	180,000
Subordinated Debt:
7% senior subordinated notes, due June 15, 2013			175,000				175,000
Total long-term debt and notes		$	349,000			$	355,000

The carrying amount of borrowings outstanding under our revolving bank credit facility approximates fair value as the interest rates are tied to current market rates. At September 30, 2005, the quoted market value of our $175 million of 7% senior subordinated notes was 97% of the $175 million carrying value, or $169.8 million. At December 31, 2004, the quoted market value of our $175 million of 7% senior subordinated notes was 101% of the $175 million carrying value, or $177 million.

Revolving Bank Credit Facility

We maintain a revolving bank credit facility with a syndicate of lenders led by Wachovia Bank, National Association, as issuing bank and administrative agent, The Bank of Nova Scotia and Bank of America as co-syndication agents and BNP Paribas and Comerica Bank as co-documentation agents. The facility originally provided us with a commitment of $400 million, and, effective October 25, 2005, was increased to $450 million. Amounts available for borrowing under the credit facility are limited to a borrowing base, which as of October 25, 2005 was $450 million. Up to $40 million of the borrowing base is available for the issuance of letters of credit. Outstanding borrowings are unsecured and rank senior in right of payment to our 7% senior subordinated notes. The facility matures on April 1, 2008. At September 30, 2005, we had $174 million in outstanding borrowings under the credit facility and $17.3 million in outstanding letter of credit obligations. See Note 7 – Subsequent Events for discussion of our plans to amend the facility to increase the borrowing capacity to $750 million.

Interest is payable on borrowings under our revolving bank credit facility, as follows:

	n		on base rate loans, at a fluctuating rate, or base rate, equal to the sum of (a) the greater of the Federal funds rate plus 0.5% or Wachovia’s prime rate plus (b) a variable margin between 0.00% and 0.50%, depending on the amount of borrowings outstanding under the credit facility, or
	n		on fixed rate loans, a fixed rate equal to the sum of (a) a quoted LIBOR rate divided by one minus the average maximum rate during the interest period set for certain reserves of member banks of the Federal Reserve System in Dallas, Texas, plus (b) a variable margin between 1.25% and 2.00%, depending on the amount of borrowings outstanding under the credit facility.

Interest is payable on base-rate loans on the last day of each calendar quarter. Interest on fixed rate loans is generally payable at maturity or at least every 90 days if the term of the loan exceeds three months. In addition to interest, we must pay a quarterly commitment fee of between 0.30% and 0.50% per annum on the unused portion of the borrowing base.

Our revolving bank credit facility contains customary negative covenants that place restrictions and limits on, among other things, the incurrence of debt, guarantees, liens, leases and certain investments. Our subsidiaries are guarantors under the credit facility, and we are restricted and limited in our ability to pay cash dividends, to purchase or redeem our stock and to sell or encumber our assets. Financial covenants require us to, among other things:

	n		maintain a ratio of earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) to cash interest payments of at least 3.00 to 1.00;
	n		maintain a ratio of total debt to EBITDA of not more than 3.50 to 1.00; and
	n		hedge no more than 85% of our projected production during any calendar year.

At September 30, 2005, and December 31, 2004, we were in compliance with all covenants.

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Senior Subordinated Notes

On June 10, 2003, we issued $175 million of 7% senior subordinated notes due June 15, 2013. The notes bear interest at a rate of 7% per annum with interest payable semi-annually on June 15 and December 15, beginning December 15, 2003. We may redeem the notes at our option, in whole or in part, at any time on or after June 15, 2008, at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium that decreases yearly from 3.5% in 2008 to 0% in 2011 and thereafter. In addition, at any time prior to June 15, 2006, we may redeem up to a maximum of 35% of the aggregate principal amount with the net proceeds of one or more equity offerings at a price equal to 107% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any. The notes are general unsecured obligations and rank subordinate in right of payment to all existing and future senior debt, including the revolving bank credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness.

The indenture governing the notes contains covenants that, among other things, restrict or limit:

	n		incurrence of additional indebtedness and issuance of preferred stock;
	n		repayment of certain other indebtedness;
	n		payment of dividends or certain other distributions;
	n		investments and repurchases of equity;
	n		use of the proceeds of assets sales;
	n		transactions with affiliates;
	n		creation, incurrence or assumption of liens;
	n		merger or consolidation and sales or other dispositions of all or substantially all of our assets;
	n		entering into agreements that restrict the ability of our subsidiaries to make certain distributions or payments; or
	n		guarantees by our subsidiaries of certain indebtedness.

In addition, upon the occurrence of a change of control (as defined in the indenture), we will be required to offer to purchase the notes at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest and liquidated damages, if any.

At September 30, 2005, and December 31, 2004, we were in compliance with all covenants.

NOTE 3 — Stockholders’ Equity

Increase in Number of Shares Outstanding

At our annual meeting of stockholders on April 26, 2005, our Board of Directors received shareholder approval to increase the number of shares we are authorized to issue to up to 105,000,000 shares of stock, including up to 100,000,000 shares of common stock and up to 5,000,000 shares of preferred stock. An amendment to our Restated Certificate of Incorporation was filed with the Secretary of State of the State of Delaware on April 26, 2005 to reflect the increase.

NOTE 4 — Commitments and Contingencies

Legal Proceedings

We are involved from time to time in various claims and lawsuits incidental to our business. In the opinion of management, the ultimate liability, if any, will not have a material adverse effect on our financial position or results of operations.

Operating Leases

We have entered into non-cancelable operating lease agreements in the ordinary course of our business activities. These leases include those for our office space at 1100 Louisiana Street in Houston, Texas, and at 700 17^th Street in Denver, Colorado, together with various types of office equipment (telephones, copiers and faxes). The terms of these agreements have various expiration dates from 2005 through 2009. Future minimum lease payments for the remainder of 2005 and

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

each of the subsequent four years from 2006 through 2009 are $0.4 million, $1.5 million, $1.6 million, $1.6 million and $0.9 million, respectively.

Purchase Obligations

We have committed to acquire additional offshore seismic data under an existing license agreement for up to $7.7 million which is payable in January 2006.

Letters of Credit

We had $17.3 million and $0.4 million, respectively, in letters of credit outstanding at September 30, 2005, and December 31, 2004. Of the outstanding balance at September 30, 2005, $17 million was issued to guarantee performance on open derivative contracts with one counterparty, with remaining $0.3 million issued for natural gas and oil operating activities. None were collateralized.

Drilling Contract

In February 2005, we entered into a one-year contract for the use of a drilling rig in the Uinta Basin. Under the terms of the contract, we are obligated for up to an estimated $1.5 million in fees for use of the rig during the remaining portion of the one-year term.

NOTE 5 — Related Party Transactions

Employment Agreements

On February 8, 2005, with the approval of our Board of Directors, we entered into amended and restated employment agreements with five senior executive officers, including our President and Chief Executive Officer. Each agreement is for a term of three years, with automatic one-year extensions thereafter unless the executive or we provide notice of termination at least 90 days prior to the end of the applicable term.

By entering into the amended and restated employment agreements and terminating their prior employment agreements with us, the senior executive officers gave up certain rights, including the right to receive severance for a termination of employment following a change of control of our company absent the existence of “good reason” and the right to guaranteed annual stock option grants and incentive compensation bonuses which will now be subject to the discretion of our Compensation and Management Development Committee. In addition to these rights, our President and Chief Executive Officer gave up the right to receive a transaction bonus upon the occurrence of certain corporate transactions involving our company, and all of the executives have agreed to broader non-competition provisions under the amended and restated agreements.

In consideration for entering into the amended and restated agreements and foregoing such rights, in February 2005, we paid these senior executive officers an aggregate of $5.1 million in cash and issued a total of 30,105 shares of restricted stock. In accordance with the terms of our 2004 Long-Term Incentive Compensation Plan, the restricted stock vests over a period of five years.

All of the employment agreements provide that if we terminate an executive’s agreement without “cause” (as defined in the employment agreement), or if the executive terminates his or her employment with us for “good reason” (as defined in the agreement, which includes the occurrence of certain events following a change in control of our company), we are obligated to pay the executive a lump-sum severance payment equal to 2.99 times his or her then current annual rate of total compensation and to continue certain welfare benefits. The agreements further provide that if any payments made to the executives, whether or not under the agreement, would result in an excise tax being imposed on the executives under Section 4999 of the Internal Revenue Code; we will make each of the executives “whole” on a net after-tax basis.

We may terminate any employment agreement for cause or upon the death or disability of the executive without financial obligation (other than payment of any accrued obligations). Each executive may terminate his or her employment agreement at any time for any reason upon at least 30 days prior written notice. In the event the executive’s employment is terminated by us without cause or upon death or disability, or if the executive terminates his or her employment with us for good reason, any unvested shares of restricted stock, unvested options or similar deferred compensation automatically will

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

vest and any other conditions to such awards shall be deemed satisfied.

As a result of the amended and restated employment agreements, we incurred approximately $5.3 million in additional compensation expense during the first nine months of 2005. The additional expense includes the cash payments made during the first quarter of 2005 together with the compensation expense incurred for the amortization of the restricted stock during the first nine months of 2005.

NOTE 6 — Acquisitions

South Texas Acquisition

See Note 7 – Subsequent Events.

East Texas Acquisitions

On March 15, 2005, we completed the purchase of certain natural gas and oil producing properties and associated gathering pipelines and equipment, together with developed and undeveloped acreage, located in the Rusk County, Texas, from Dale Gas Partners, L.P. The $22.0 million purchase price was paid in cash and financed by borrowings under our revolving bank credit facility. The properties purchased cover approximately 5,776 gross acres located in South Oak Hill Field, which is in close proximity to our existing operations in the Willow Springs Field, and represents interests in three producing wells and one well in the completion stage. We operate all of the wells acquired and our working interest is 100%. Total proved reserves associated with the interests acquired were 9.1 Bcfe as of March 15, 2005, the effective date of the transaction.

On April 5, 2005, we completed the acquisition of a 50% working interest in seven producing wells together with undeveloped acreage located in the North Blocker Field located in Harrison County, Texas from Dale Resources East Texas L.L.C. The $9.2 million purchase price was paid in cash and financed by borrowings under our revolving bank credit facility. The properties purchased cover approximately 4,679 gross acres and, we operate all seven wells. Total proved reserves associated with the interests acquired are estimated at 7.7 Bcfe, as of April 1, 2005, the effective date of the transaction.

NOTE 7 — Subsequent Events

Acquisition of South Texas Properties

On October 21, 2005, we entered into a purchase and sale agreement with Kerr-McGee Oil & Gas Onshore LP and Westport Oil and Gas Company, L.P. to acquire certain interests in natural gas and oil producing properties and undeveloped acreage in four fields located in South Texas for $163 million in cash, subject to customary closing adjustments. Upon signing the purchase and sale agreement, we paid $16.3 million in cash towards the purchase price, which amount we borrowed under our revolving bank credit facility and is generally nonrefundable, except upon certain limited circumstances. The transaction is expected to close on or before November 30, 2005 and the remaining portion of the purchase price is expected to be financed with borrowings under our revolving bank credit facility.

Increase in Borrowing Base of Revolving Bank Credit Facility

Effective October 25, 2005, our revolving bank credit facility was amended to increase the borrowing base from $400 million to $450 million. Subsequent to September 30, 2005, and as of the date of our report, outstanding borrowings under the credit facility increased by $112 million to $286 million. Additional borrowings were used in part to fund the $16.3 million deposit towards the South Texas Properties to be acquired from Kerr-McGee and Westport with the balance used to fund working capital obligations. In addition, outstanding letters of credit were subsequently reduced by a net $7 million from $17.3 million to $10.3 million as of the date of our report.

Disposition of Gulf of Mexico Assets.

On November 8, 2005, we announced our intention to divest all our Gulf of Mexico assets and to shift our operating focus onshore. We hope to reinvest the net cash proceeds from the sale into longer-lived oil and gas assets onshore in North America or retire debt. Where possible, our plans include structuring the reinvestment to minimize taxes on any gain realized from the sale. A data room is expected to open to potential bidders in January 2006 and, we expect to close the transaction by the end of the first quarter of 2006. The sale of our Golf of Mexico assets is subject to a number of contingencies, including final Board approval of the price and terms of the sale. At December 31, 2004, our offshore reserves totaled 292

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Bcfe, or 37% of our total proved reserves. Historically, production from our offshore properties has averaged 40% to 45% of total production.

Divesting our Gulf of Mexico assets will result in the reclassification of the fair value of the derivative obligations allocated to offshore production from accumulated other comprehensive income to earnings. At September 30, 2005, the fair value of derivative obligations allocated to offshore production for years 2006, 2007 and 2008 was a liability of $194.5 million ($142.8 million net of tax). The ultimate amount of this reclassification and possible charge against earnings will depend on the fair value of the obligations at the time that receipt of offshore production allocated to these hedges no longer appears probable, which we expect to occur in the first quarter of 2006. This reclassification and possible charge to earnings will not affect cash flow.

Concurrent with the divestiture, we plan to liquidate that portion of our current 2006 hedge position which exceeds 85% of our forecasted production for 2006 after taking into account the divestiture of our Gulf of Mexico assets and any acquisitions that appear imminent at the time of the divestiture. We estimate that we will liquidate approximately 70 MMBtu per day, subject to superseding operational developments and acquisition activities.

Repurchase of Common Stock.

On November 8, 2005, our Board of Directors approved up to $200 million of discretionary common stock repurchases. These purchases may be made from time to time throughout 2006 in either the open market or in privately negotiated transactions, and will be subject to a number of factors including market conditions, applicable legal requirements, available cash, competing reinvestment opportunities in the acquisition market for oil and gas assets and other factors.

Expansion of Revolving Bank Credit Facility.

We plan to amend our revolving bank credit facility to increase the size of our bank syndicate’s lending commitment from $450 million to $750 million, which may be further increased at our request and with prior approval from our lenders to a maximum of $850 million. Following the amendment, we expect our initial borrowing base to be set at $600 million. Pursuant to the amendment, borrowings will be secured by 80% of our onshore natural gas and oil assets. The amendment is expected to be effective by November 29, 2005; however, it is subject to a number of closing conditions, including negotiation of definitive documentation. We plan to use a portion of the additional borrowing capacity to fund up to $146.7 million of the remaining purchase price of the South Texas properties to be acquired from Kerr-McGee and Westport with the balance to be readily available for general corporate purposes, including future acquisition opportunities and the repurchase of common stock.

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

The following discussion is intended to assist you in understanding our business and the results of operations together with our present financial condition. This section should be read in conjunction with our Consolidated Financial Statements and the accompanying notes included elsewhere in this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2004.

Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. See “Forward-Looking Statements and Other Information” at the beginning of this Quarterly Report and “Risk Factors Affecting Our Business” beginning on page 15 of our Annual Report on Form 10-K for additional discussion of some of these factors and risks.

Overview of Our Business

We are an independent natural gas and oil producer concentrating on growing reserves and production through the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. Currently, our core areas of operations are South Texas, offshore in the shallow waters of the Gulf of Mexico and the Arkoma Basin of Oklahoma and Arkansas. On November 8, 2005, we announced plans to divest all our Gulf of Mexico assets and focus operations onshore in North America. During 2003, we initiated operations in the Rocky Mountain Region, with an initial focus in the Uinta Basin of northeastern Utah, and during 2004, we expanded our focus to include the DJ Basin of Eastern Colorado. We operate as one segment as each of our operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 131, “Disclosures about Segments of an Enterprise and Related Information.”

At December 31, 2004, net proved reserves were 793 billion cubic feet equivalent, or Bcfe, with a standardized measure of future net cash flows including income taxes, discounted at 10% per annum, of $1.4 billion. Our reserves are fully engineered on an annual basis by independent petroleum engineers. Approximately 94% of our proved reserves at December 31, 2004, were natural gas, approximately 63% of which were classified as proved developed. As of December 31, 2004, we operated approximately 77% of our producing wells. Daily production averaged 339 million cubic feet of natural gas equivalent or MMcfe in 2004.

We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and oil on behalf of KeySpan Corporation, our then parent company. In September 1996 we completed our initial public offering and sold approximately 31% of our shares to the public. Through three separate transactions, the first in February 2003 and the last in November 2004, KeySpan completely divested of its investment in the common stock of our company.

Plan to Divest of Gulf of Mexico Assets

On November 8, 2005, we announced plans to divest all our Gulf of Mexico assets and to shift our operating focus onshore. We hope to reinvest the net cash proceeds from the sale into longer-lived oil and gas assets onshore in North America or retire debt. Where possible, our plans include structuring the reinvestment to minimize taxes on any gain realized from the sale. A data room is expected to open to potential bidders in January 2006 and, we expect to close the transaction by the end of the first quarter of 2006. The sale of our Gulf of Mexico assets is subject to a number of contingencies, including final Board approval of the price and terms of the sale.

At December 31, 2004, our offshore reserves totaled 292 Bcfe, or 37% of our total proved reserves. Historically, production from our offshore properties has averaged 40% to 45% of total production. Our offshore properties are located in the shallow waters of the Outer Continental Shelf. Key producing properties are located in the western and central Gulf of Mexico and include the Mustang Island, High Island, East Cameron, Vermilion and West Cameron areas. At September 30, 2005, we held interests in 136 blocks in federal and state waters, of which 78 are developed. We have a total of 96 producing platforms and production caissons, of which we operate 59. During the first nine months of 2005, offshore production averaged 136 MMcfe/day, and prior to shut-ins caused by Hurricanes Katrina and Rita, an estimated 155 MMcfe/day.

Divesting our Gulf of Mexico assets will result in the reclassification of the fair value of the derivative obligations allocated to offshore production from accumulated other comprehensive income to earnings. At September 30, 2005, the fair value of derivative obligations allocated to offshore production for years 2006, 2007 and 2008 was a liability of $194.5 million ($142.8 million net of tax). The ultimate amount of this reclassification and possible charge against earnings will depend on the fair value of the obligations at the time that receipt of offshore production allocated to these hedges no longer appears probable, which we expect to occur in the first quarter of 2006. This reclassification and possible charge to earnings will not affect cash flow.

Concurrent with the divestiture, we plan to liquidate that portion of our current 2006 hedge position which exceeds 85% of our forecasted production for 2006 after taking into account the divestiture of our Gulf of Mexico assets and any acquisitions that appear imminent at the time of the divestiture. We estimate that we will liquidate approximately 70 MMBtu per day, subject to superseding operational developments and acquisition activities.

As part of the plan to shift our operational focus to the onshore, on October 21, 2005, we entered into a purchase and sale agreement with Kerr-McGee Oil & Gas Onshore LP and Westport Oil and Gas Company, L.P. to acquire certain interests in natural gas and oil producing properties and undeveloped acreage in four fields located in South Texas for $163 million in cash, subject to customary closing adjustments. Upon signing the purchase and sale agreement, we paid $16.3 million in cash towards the purchase price. The transaction is expected to close on or before November 30, 2005 and the remaining portion of the purchase price is expected to be financed with borrowings under our revolving bank credit facility.

The properties cover approximately 26,000 net acres, include approximately 300 wells and are located in the Rincon Field in Starr County, the Tijerina-Canales-Blucher Field in Jim Wells and Kleberg Counties, the Vaquillas Ranch Field in Webb County, and the San Carlos Field in Hidalgo County. As of October 1, 2005, proved reserves, based on our internal estimates, are approximately 88 Bcfe, of which 75% is natural gas. Current production from the four fields is estimated at approximately 10 MMcfe/day, net to the interests to be acquired. We will operate 100% percent of the proved reserves with an average working interest of 60%.

Our Board of Directors also approved discretionary repurchases from time to time of up to $200 million in company stock. These purchases may be in the open market or in privately negotiated transactions, and will be subject to a number of considerations, including market conditions for our shares, applicable legal requirements, available cash, competing reinvestment opportunities in the acquisition market for oil and gas assets and other factors.

To provide additional funds for general corporate purposes and acquisition liquidity, we plan to amend our revolving bank credit facility to increase the amount of our banks’ lending commitments from $450 million to $750 million. Following the amendment, all borrowings will be secured by 80% of our onshore natural gas and oil assets. The amendment is expected to be effective by November 29, 2005; however, it is subject to a number of closing conditions, including negotiation of definitive documentation .

Source of Our Revenues

We derive our revenues from the sale of natural gas and oil that is produced from our natural gas and oil properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of natural gas is the primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our natural gas production. During the first nine months of both 2005 and 2004, the use of derivative instruments prevented us from realizing the full benefit of upward price movements and may continue to do so in future periods.

Critical Accounting Estimates and Significant Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make assumptions and prepare estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and revenues and expenses. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ. We evaluate our assumptions and estimates on a regular basis and discuss the development and disclosure process with our Audit Committee. Estimates of proved reserves are key components of our most significant financial estimates involving unevaluated properties, depreciation, depletion and amortization and our full cost ceiling limitation. In addition, estimates are used to accrue production revenues and operating expenses, drilling costs, federal and state taxes, the fair value of derivative contracts, including the calculation of ineffectiveness and the fair value of our stock options. There has been no change in our critical accounting policies and use of estimates since our most recent Annual Report for the year ended December 31, 2004.

Recent Accounting Pronouncements

On December 16, 2004, the FASB revised Statement 123 (revised 2004), “Share-Based Payment” that will require compensation costs related to share-based payment transactions (e.g., issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. Statement 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” For us, SFAS 123(R), as amended by SEC Release 34-51558, is effective for our first fiscal year beginning after June 15, 2005, or January 1, 2006. Entities that use the fair-value-based method for either recognition or disclosure under SFAS 123 are required to apply SFAS 123(R) using a modified version of prospective application. Under this method, an entity records compensation expense for all awards it grants after the date of adoption. In addition, the entity is required to record compensation expense for the unvested portion of previously granted awards that remain outstanding at the date of adoption. In addition, entities may elect to adopt SFAS 123(R) using a modified retrospective method where by previously issued financial statements are restated based on the expense previously calculated and reported in their pro forma footnote disclosures.

On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” using the “prospective method” as defined by the SFAS 148. As a result, we have recognized compensation expense for all stock options granted subsequent to January 1, 2003, with no expense recognized for grants made prior to 2003. Adoption of SFAS 123(R) will require us to recognize compensation expense over the remaining service period for the unvested portion of all options granted during 2000, 2001 and 2002. All options granted prior to 2000 are fully vested. We expect to adopt SFAS 123(R) on January 1, 2006, using the modified version of the prospective application. We continue to evaluate the effect of adopting SFAS 123(R) and based on current estimates, we expect to incur an additional $2.0 to $3.0 million in gross stock compensation expense ($1.5 to $2.5 million net of amounts capitalized) during 2006. We do not believe the adoption of SFAS 123(R) will have a material impact to our financial statements.

On March 29, 2005, the SEC released Staff Accounting Bulletin (“SAB”) 107 providing additional guidance in applying the provisions of SFAS 123(R), “Share-Based Payment.” SAB 107 should be applied when adopting SFAS 123(R) and addresses a wide range of issues, focusing on valuation methodologies and the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC guidance.

Overview of Results for the Third Quarter of 2005

While commodity prices reached record levels during the quarter, our production volumes were materially curtailed as a result of Hurricanes Katrina and Rita as well as from drilling delays. As a result of the upsurge in natural gas prices, the fair value of our open derivative contracts (based on a NYMEX price of $13.91 at September 30, 2005) increased from a liability of $231.6 million ($149.6 million net of tax) at June 30, 2005, to a liability of $696.7 million ($450.1 million net of tax) at September 30, 2005 and as a result of the measured ineffectiveness of these open contracts at the end of the period, we recognized an additional loss of $45.9 million ($29.7 million after tax) during the third quarter. These factors, combined with an increase in operating expenses and capital spending were the primary drivers behind results for operations, net income and cash flows during the third quarter of 2005. During the third quarter of 2005:

	n		We incurred relatively minor structural damage from Hurricanes Katrina and Rita and anticipate these losses will be covered by insurance. However, the curtailment of production as a result of these storms impacted operating revenues by an estimated $12.9 million during the third quarter and will impact the fourth quarter of 2005 and possibly 2006 as we wait for repairs to third-party pipelines and processing facilities;
	n		We currently estimate total deferred production for 2005 as a result of hurricanes of between 8 Bcfe and 10 Bcfe, of which an estimated 2.0 Bcfe was deferred during the third quarter of 2005. Further, we estimate additional production shortfall for 2005 of between 6 Bcfe and 7 Bcfe caused by drilling delays, in part due to offshore rig availability during the first six months of 2005 and in part to delays caused by the third quarter hurricanes, and various operational issues;
	n		We generated $8.1 million in net income, a decrease of 81% from $43.0 million in the third quarter 2004 due primarily to hedge ineffectiveness of $29.7 million net of tax in the third quarter of 2005;
	n		We produced approximately 28 Bcfe and our average daily production rate was 308 MMcfe per day compared to 328 Mcfe/day during the second quarter of 2005 and 343 MMcfe per day during the third quarter of 2004, a decrease of 6% and 10%, respectively;

	n		We generated $102.7 million in net cash flows from operating activities compared to $156.9 million during the third quarter of 2004, a decrease of 35%;
	n		We increased our outstanding borrowings under our revolving bank credit facility by a net $19 million:
	n		We invested $142.1 million in natural gas and oil properties compared to $136.7 million during the third quarter of 2004, an increase of 4% ;
	n		We drilled 79 wells, of which 73, or 92%, were successful with three offshore, seven in East Texas, 20 in South Texas, 13 in Arkoma and 30 in the Rockies;
	n		Onshore, we had 12 rigs drilling by quarter end: six in South Texas; two in Arkansas, two in East Texas, one in Colorado and one in Utah;
	n		We were able to begin development projects at Main Pass 264 and Eugene Island 331 and to spud exploratory wells at Brazos 366 and West Cameron 39; and
	n		The side track to our deep well at High Island 115 was unsuccessful and the side track of the A1 well at High Island 47, completed during the second quarter of 2005, is not producing as anticipated. Both of these fields were key producers prior to being shut-in December 2004;

Subsequent to September 30, 2005:

	n		We entered into a purchase and sale agreement, on October 21, 2005, to acquire producing properties and undeveloped acreage in four South Texas fields for $163 million in cash, representing an estimated 88 Bcfe of proved reserves. We made a cash deposit of $16.3 million and plan to finance the remaining portion of the net purchase price with borrowings on our revolving bank credit facility. The acquisition is expected to close on or before November 30, 2005;
	n		Effective, October 25, 2005, the borrowing base on our revolving bank credit facility was increased from $400 million to $450 million and as of the date of our report, we have increased our outstanding borrowings by $112 million for a total outstanding of $286 million, excluding letter of credit obligations of $10.3 million;
	n		On October 25, 2005, we increased our 2005 capital expenditure budget by $221 million from $512 million to $733 million. A portion of the increase will cover the planned acquisition of the four South Texas fields for $163 million;
	n		On November 8, 2005, we announced our intention to divest all our Gulf of Mexico assets and to shift our operating focus onshore. We plan to reinvest the net cash proceeds from the sale into longer-lived oil and gas assets onshore in North America or retire debt;
	n		Our Board of Directors approved discretionary stock repurchases from time to time up to $200 million of our common stock, subject to market conditions, applicable legal requirements, available cash, competing reinvestment opportunities in the acquisition market for oil and gas assets and other factors; and
	n		We plan to amend our revolving bank credit facility to increase our banks’ lending commitments from $450 million to $750 million. Following the amendment, all borrowings will be secured by 80% of our onshore natural gas and oil assets. The amendment is planned to be effective by November 29, 2005 and our initial borrowing base is expected to be set at $600 million.

Operating and Financial Results for the Three Months Ended September 30, 2005 Compared to the Three Months Ended September 30, 2004 and the Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004.

		Three Months Ended September 30,																Nine Months Ended September 30,
Summary Operating Information:		2005				2004				Variance								2005				2004				Variance
										(in thousands, except average sales price)
Natural gas revenues		$	213,643			$	160,924			$	52,719				33	%		$	558,666			$	490,103			$	68,563				14	%
Oil revenues			19,470				13,269				6,201				47	%			55,395				34,801				20,594				59	%
Gain (loss) on settled derivatives			(62,216	)			(10,821	)			(51,395	)			475	%			(100,726	)			(38,220	)			(62,506	)			164	%
Unrealized gain (loss) derivative ineffectiveness			(45,900	)			(900	)			(45,000	)			n/a				(47,324	)			(2,600	)			(44,724	)			n/a
Operating revenues			125,413				162,760				(37,347	)			-23	%			466,950				487,418				(20,468	)			-4	%
Operating expenses			109,180				94,366				14,814				16	%			319,416				278,907				40,509				15	%
Income from operations			16,233				68,394				(52,161	)			-76	%			147,534				208,511				(60,977	)			-29	%
Net income			8,081				42,998				(34,917	)			-81	%			85,349				128,038				(42,689	)			-33	%
Production:
Natural gas (MMcf)			26,217				29,465				(3,248	)			-11	%			81,014				87,735				(6,721	)			-8	%
Oil (MBbls)			360				343				17				5	%			1,172				995				177				18	%
Total (MMcfe) (1)			28,377				31,523				(3,146	)			-10	%			88,046				93,705				(5,659	)			-6	%
Average daily production (MMcfe/d)			308				343				(35	)			-10	%			323				342				(19	)			-6	%
Average Sales Prices:
Natural Gas (per Mcf) unhedged		$	8.15			$	5.46			$	2.69				49	%		$	6.90			$	5.59			$	1.31				23	%
Natural Gas (per Mcf) realized (2)			5.78				5.09				0.69				14	%			5.65				5.18				0.47				9	%
Natural Gas (per Mcf) “all-in”(3).			4.03				5.06				(1.03	)			-20	%			5.07				5.15				(0.08	)			-2	%
Oil (per Bbl) realized			54.08				38.69				15.39				40	%			47.27				34.98				12.29				35	%

Income from Operations

Operating revenues were 23% lower during the third quarter of 2005 as compared to the third quarter 2004 primarily as a result of a 20% decrease in average realized prices, combined with a 10% decrease in production volumes. As a result of the continued increase in natural gas prices, the loss on derivative contracts settled during the third quarter of 2005 was $62.2 million compared to $10.8 million during the third quarter of 2004 and we recognized additional non-cash expense of $45.9 million due to the ineffectiveness of our open contracts at the end of the period, which compares to $0.9 million during the corresponding period of 2004. Operating income for the third quarter of 2005 decreased by $52.2 million, or 76%, as compared to the third quarter of 2004, as operating expenses increased by 16% during the third quarter of 2005.

For first nine months of 2005, operating income decreased by $61.0 million, or 29%, as a result of a 4% decrease in operating revenues combined with a 15% increase in operating expenses.

Production Volume

Production volumes were 10% lower during the third quarter of 2005 compared to the third quarter of 2004 and were 6% lower during the first nine months of 2005 compared to the first nine months of 2004.

Onshore. Daily production rates were flat at an average of 185 MMcfe per day during the third quarter of 2005 and the third quarter of 2004.

Quarter-over-quarter, we added 8 MMcfe per day in newly developed production in Arkoma, increasing our average daily rate by 21% from 38 MMcfe per day during the third quarter of 2004 to 46 MMcfe per day during the third quarter of 2005. In South Texas, our average daily production declined by 12%, or 18 MMcfe per day from 145 MMcfe per day during the third quarter of 2004 to 127 MMcfe per day during the third quarter of 2005. We estimate that approximately 90 MMcfe was shut-in and deferred due to the shut down of the Kingsville processing plant for Hurricane Rita, which resumed operation in October 2005.

For the nine-month period ended September 30, 2005, onshore production was flat at an average of 187 MMcfe per day during the first nine months of 2005 and 2004. Production added from developmental drilling in Arkoma and the Rockies was offset by production declines in South Texas and from the divesture of our South Louisiana properties in February 2004 and our Appalachian Basin properties in June 2004.

Offshore. For the three months ended September 30, 2005, offshore daily production rates decreased by 22%, or 35 MMcfe per day, from an average of 158 MMcfe per day during the third quarter of 2004 to an average of 123 MMcfe per day during the third quarter of 2005. For the nine months ended September 30, 2005, offshore daily production rates decreased by 12%, or 19 MMcfe per day, from an average of 155 MMcfe per day during the first nine months of 2004 to an average of 136 MMcfe per day during the first nine months of 2005.

Production rates were lower during the current three month period as a result of delays in our development program caused by delays in rig availability during the first half of 2005 combined with the impact of shut-in production during August and continuing through the end of September as a result of Hurricanes Katrina and Rita. We estimate that approximately 2.0 Bcfe, or 22 Mcfe/day was shut-in and deferred during the third quarter of 2005 as a result of Hurricanes Katrina and Rita. At the end of August and prior to Hurricane Rita, our offshore properties were producing an estimated 155 Mcfe per day, primarily as a result of newly developed production at Galveston 210, Matagorda A-5, West Cameron 77 Main Pass 264 and High Island 47.

For 2005, we forecasted production growth of approximately 6% from the 124 Bcfe produced in 2004 to approximately 132 Bcfe for the current year. We currently estimate total deferred production for 2005 as a result of Hurricanes Katrina and Rita, drilling delays and operational issues to fall between 14 Bcfe and 17 Bcfe, which will decrease our forecasted production for 2005 to approximately 115 Bcfe for the twelve-month period.

Commodity Prices and Effects of Hedging

For the three months ended September 30, 2005, our average unhedged or sales price for natural gas increased by 49% from $5.46 per Mcf during the third quarter of 2004 to $8.15 per Mcf during the third quarter of 2005. Because of the increase in the market price for natural gas, our total loss from hedging activities increased by $96.4 million quarter-over-quarter. Included in natural gas revenues for the third quarter of 2005 is a loss of $108.1 million from natural gas hedging activities, which includes $45.9 million for ineffectiveness. As a result of the cash loss from hedge contracts settled during the current quarter, we realized an average natural gas price during the third quarter of 2005 of $5.78 per Mcf which was 71% of, or $2.37 per Mcf lower than, our average sales price. During the third quarter of 2004, we incurred a hedge loss from natural gas derivatives of $11.7 million, which includes an unrealized loss of $0.9 million recognized for ineffectiveness. As a result of the cash loss from hedge contracts settled during the third quarter of 2004, we realized an average natural gas price of $5.09 per Mcf, which was 93% of, or $0.37 per Mcf lower than, our average sales price during the third quarter of 2004.

For the nine months ended September 30, 2005, our average unhedged or sales price for natural gas increased by 23% from $5.59 per Mcf during the first nine months of 2004 to $6.90 per Mcf. Included in natural gas revenues for the first nine months of 2005 is a loss of $148.0 million from natural gas hedging activities, which includes $47.3 million in ineffectiveness, and is $109.8 million higher than the $38.2 million loss from hedge activities incurred during the first nine months of 2004, which includes $2.6 million recognized for ineffectiveness. As a result of the cash loss from hedge contracts settled during the period, our realized price for natural gas for the first nine months of 2005 of $5.65 was 82% of, or $1.25 per Mcf lower than, our average unhedged natural gas price of $6.90 per Mcf, which compares to a realized price during the first nine months of 2004 of $5.18 per Mcf that was 93% of, or $0.41 per Mcf lower than, the unhedged price of $5.59 per Mcf.

Operating Expenses

		Three Months Ended September 30,																Nine Months Ended September 30,
Operating Expenses per Mcfe		2005				2004				Variance								2005				2004				Variance
Lease operating expense		$	0.63			$	0.45			$	0.18				40	%		$	0.59			$	0.42			$	0.17				40	%
Severance tax			0.15				0.11				0.04				36	%			0.13				0.11				0.02				18	%
Transportation expense			0.11				0.10				0.01				10	%			0.10				0.10				¯				¯
Asset retirement accretion expense			0.05				0.03				0.02				67	%			0.05				0.04				0.01				25	%
Depreciation, depletion and amortization			2.56				2.12				0.44				21	%			2.44				2.08				0.36				17	%
General and administrative, net			0.36				0.18				0.18				100	%			0.31				0.23				0.08				35	%
Total operating expenses per unit of production		$	3.86			$	2.99			$	0.87				29	%		$	3.62			$	2.98			$	0.64				21	%

Total operating expenses on an absolute dollar basis increased 16% for the third quarter of 2005 as compared to the third quarter of 2004 and 15% for the current nine-month period compared to the prior nine-month period, primarily as a result of higher lease operating expenses, depreciation, depletion and amortization expense and general and administrative expenses. On a unit of production basis, operating expenses increased $0.87 per Mcfe, or 29%, quarter-over-quarter and $0.64 per Mcfe, or 21%, period-over-period. Per unit expenses were higher for all categories of operating expense due to curtailed production combined with higher costs.

Lease Operating Expense. On an absolute dollar basis, lease operating expense increased by 24% for the third quarter of 2005 as compared to the third quarter of 2004 and by 32% for the first nine months of 2005 as compared to the first nine months of 2004. The increase during the third quarter and first nine months of 2005 relates primarily to increased expenses incurred in connection with the integration of the Gulf of Mexico properties acquired in September and October of 2004, as well as a general increase in service costs and the continued expansion of our operating base from the escalation of our drilling program. During 2004 we successfully drilled and completed 177 new wells and acquired 12 new blocks in the central Gulf of Mexico pursuant to the September and October Gulf of Mexico acquisitions. During the first nine months of 2005, we successfully drilled and completed an additional 203 new wells and acquired seven wells in East Texas.

Severance Tax. Severance tax is a function of volume and revenues generated from onshore production. On an absolute dollar basis, severance tax increased by 24% from the third quarter of 2004 and by 13% from the first nine months of 2004 primarily as a result of the respective 49% and 23% increase in the market price for natural gas during the third quarter and first nine months of 2005 as compared to the corresponding three-month and nine-month periods of 2004. On a unit of production basis, severance tax increased by $0.04 per Mcfe for the third quarter of 2005 and by $0.02 per Mcfe for the first nine months of 2005 as a result of the increase in severance tax expense combined with the effects of a decrease in production volumes during each of the respective periods.

Depreciation, Depletion and Amortization. The increase in our depreciation, depletion and amortization expense for the three months ended September 30, 2005 and for the nine-month period then ended was primarily a result of a higher depletion rate, offset in part by lower production volume during each of the respective periods. Our depletion rate for the third quarter of 2005 of $2.56 per Mcfe was 21% higher than the $2.12 per Mcfe during the third quarter of 2004. For first nine months of 2005 our depletion rate of $2.44 per Mcfe was 17% higher than our rate of $2.08 per Mcfe during the first nine months of 2004. The higher depletion rate during 2005 is primarily a result of a higher finding and development costs.

Asset Retirement Accretion Expense. ARO accretion expense was $1.3 million for the third quarter of 2005 compared to $1.1 million for the third quarter of 2004. For the nine-month period ended September 30, 2005, ARO accretion expense was $4.0 million compared to $3.6 million during the corresponding nine months of 2004. On a per unit of production basis, ARO accretion was $0.05 per Mcfe for the third quarter of 2005 compared to $0.03 for the third quarter of 2004. Period-over-period, ARO accretion per Mcfe was $0.05 for the first nine months of 2005 compared to $0.04 during the corresponding nine months of 2004. The increase in expense reflects the increase in our abandon ment obligations as we drill and acquire new wells.

General and Administrative Expenses, Net of Overhead Reimbursements and Capitalized General and Administrative Expenses

		Absolute Dollars																Unit of Production - Mcfe
		Three Months Ended September 30,																Three Months Ended September 30,
General and Administrative Expense		2005				2004				Variance								2005				2004				Variance
						(in thousands)
Gross general and administrative expense		$	14,917			$	10,086			$	4,831				48	%		$	0.53			$	0.32			$	0.21				66	%
Operating overhead reimbursements			(508	)			(529	)			21				-4	%			(0.02	)			(0.02	)			—				—
Capitalized general and administrative			(4,180	)			(3,878	)			(302	)			8	%			(0.15	)			(0.12	)			(0.03	)			25	%
General and administrative expense, net		$	10,229			$	5,679			$	4,550				80	%		$	0.36			$	0.18			$	0.18				100	%

For the three months ended September 30, 2005, aggregate general and administrative expenses increased by $4.8 million, or 48%, as compared to the corresponding three months of 2004 and net general and administrative expenses increased by $4.5 million, or 80%, during this same period. The higher aggregate and net general and administrative expense incurred during the third quarter of 2005 included approximately $3.8 million in additional outside professional fees attributable to the review of an acquisition which was not consummated. Excluding these third quarter 2005 expenses, both aggregate and net general and administrative expenses would have increased during the third quarter of 2005 by approximately $1.0 million, or 10%, and $0.8 million, or 13%, respectively, primarily as a result of increases in stock compensation expense, legal and accounting expenses and engineering and consulting fees. Because we adopted SFAS 123 in January 2003, our stock compensation expense will increase each period as we continue to issue new stock options. In addition, upon our adoption of SFAS 123(R) in January 2006, we will begin to recognize compensation expense over the remaining vesting period for the unvested portion of all options granted prior to 2003. We expect aggregate general and administrative expenses to increase as our workforce keeps pace with the continued growth and expansion of our operations.

For general and administrative expense on a per-unit of production basis, the additional $3.8 million in outside professional fees incurred during the third quarter of 2005 in conjunction with an unsuccessful acquisition resulted in a $0.13 per Mcfe increase for the third quarter of 2005. The remaining increase in both aggregate and net general and administrative expense per Mcfe is a result of a 10% increase in aggregate expenses combined with a 10% decrease in production volume during the third quarter of 2005.

		Absolute Dollars																Unit of Production - Mcfe
		Nine Months Ended September 30,																Nine Months Ended September 30,
General and Administrative Expense		2005				2004				Variance								2005				2004				Variance
						(in thousands)
Gross general and administrative expense		$	41,395			$	34,826			$	6,569				19	%		$	0.47			$	0.37			$	0.10				27	%
Operating overhead reimbursements			(1,583	)			(1,618	)			35				-2	%			(0.02	)			(0.02	)			—				—
Capitalized general and administrative			(12,260	)			(11,680	)			(580	)			5	%			(0.14	)			(0.12	)			(0.02	)			17	%
General and administrative expense, net		$	27,552			$	21,528			$	6,024				28	%		$	0.31			$	0.23			$	0.08				35	%

For the first nine months of 2005, aggregate general and administrative expenses increased by 19%, or $6.6 million, as compared to the first nine months of 2004. Net general and administrative expenses increased by 28%, or $6.0 million, during this period. During the first nine months of 2005 we incurred additional expenses totaling $9.7 million ($0.11 per Mcfe) that include $5.0 million incurred during the in the first quarter pursuant to the February 2005 renegotiation of executive employment agreements (see Note 5 – Related Party Transactions – Employment Agreements); $0.9 million in the second quarter and another $3.8 million in the third quarter for outside professional fees incurred pursuant to the review of two corporate transactions that were not completed. The first nine months of 2004 also includes additional expenses totaling $4.4 million ($0.05 per Mcfe) incurred during the second quarter for special bonuses paid to executives and other key employees in connection with the June 2004 asset exchange transaction with KeySpan. The remaining portion of the increase in both aggregate and net general and administrative expense for the current nine month period, $1.3 million and $0.7 million, respectively, is a result of higher outside professional fees combined with an increase in stock compensation expense related to both options and restricted stock.

On a per unit of production basis, aggregate general and administrative expense increased by $0.10 per Mcfe and net general and administrative expense increased by $0.08 per Mcfe for the nine month period. The increase in both aggregate and net general and administrative expense per Mcfe is a result of a 19% increase in aggregate expense combined with the effect of a 6% decrease in production volume during the first nine months of 2005.

Other Income and Expense, Interest and Taxes

Other Income and Expense. For the third quarter of 2005, other income and expense is comprised of income of $0.1 million related to refunds of prior years’ severance tax expense. For the first nine months of 2005, other income and expense includes (i) income of $2.5 million related to refunds of prior years’ severance tax expense and (ii) expense of $2.8 million incurred as a result of a payout settlement at East Cameron 82/83 during the first quarter of 2005, whereby our working interest in the A3 well was subsequently reduced from 50% to 35%. In July 2002, we applied for and received from the Railroad Commission of Texas a “high-cost/tight-gas formation” designation for a portion of our South Texas production. For qualifying wells, production is either exempt from tax or taxed at a reduced rate until certain capital costs are recovered.

Interest Expense, Net of Capitalized Interest.

		Three Months Ended September 30,																Nine Months Ended September 30,
Interest and Average Borrowings		2005				2004				Variance								2005				2004				Variance
														(dollars in thousands)
Gross interest		$	5,898			$	4,162			$	1,736				42	%		$	16,943			$	12,771			$	4,172				33	%
Capitalized interest			(2,357	)			(2,162	)			(195	)			9	%			(6,772	)			(6,178	)			(594	)			10	%
Interest expense, net of capitalized interest		$	3,541			$	2,000			$	1,541				77	%		$	10,171			$	6,593			$	3,578				54	%
Average total borrowings (1)		$	350,435			$	265,207			$	85,228				32	%		$	347,066			$	269,920			$	77,146				29	%
Average total interest rate (1)			6.24	%			5.79	%			0.45	%			8	%			6.04	%			5.69	%			0.35	%			6	%
Average bank borrowings		$	175,435			$	90,207			$	85,228				94	%		$	172,066			$	94,920			$	77,146				81	%
Average bank interest rate			5.64	%			3.60	%			2.04	%			57	%			5.14	%			3.46	%			1.68	%			49	%

For both the three-month and nine-month periods ended September 30, 2005, the increase in gross interest expense is due to an increase in outstanding borrowings under our revolving bank credit facility combined with an increase in average interest rates associated with our bank debt. Our average bank debt has continued to increase from the second half of 2004 through the first nine months of 2005 as we utilized our revolving facility to fund a portion of the asset exchange transaction with KeySpan in June 2004, two producing property acquisitions in September and October 2004 and the East Texas acquisitions in March and April 2005. Although the majority of our bank debt bears interest at LIBOR-based rates, we have seen and expect to continue to see an increase in rates if the Federal Reserve continues its expected plan to slowly increase Federal interest rates. Since January 2005, Federal interest rates have increased by one quarter of a percent on seven occasions. Capitalized interest is a function of unevaluated properties and the 9% increase for the third quarter of 2005 as well as the 10% increase during the first nine months of 2005 as compared to the corresponding periods of 2004, correlates to the increase in our borrowing rates and with our average unevaluated property balance during the first nine months of 2005. The increase in unevaluated properties is due in part to timing of projects in progress and to the expansion of our drilling program during the first nine months of 2005.

Income Tax Provision. Our provision for taxes includes both state and federal taxes. Our current provision for the first nine months of 2005 includes $1.4 million relating to nondeductible excess executive compensation expense incurred as a result of the contract renegotiation payment made to our Chief Executive Officer in February 2005 (see Note 5 – Related Party Transactions – Employment Agreements). In addition, the provision for the first nine months of 2005 includes additional expense of $2.0 million, primarily related to adjustments to estimates for federal and state liabilities incurred during the first quarter of 2005.

Liquidity

Capital Requirements

Our principal requirements for capital are to fund our capital investment program and to satisfy our contractual obligations, primarily the repayment of long-term debt and any amounts owing in the period relating to our hedging positions. Our capital investments include the following:

	n		Funding our South Texas acquisition, expected to close November 30, 2005;
	n		Costs of acquiring and maintaining our lease acreage position and our seismic resources;
	n		Costs of drilling and completing new natural gas and oil wells;

	n		Costs of acquiring additional reserves;
	n		Costs of installing new production infrastructure;
	n		Costs of maintaining, repairing, and enhancing existing natural gas and oil wells;
	n		Costs related to plugging and abandoning unproductive or uneconomic wells; and
	n		Indirect costs related to our exploration activities, including payroll and other expense attributable to our exploration professional staff.

On October 25, 2005, our Board of Directors increased the capital expenditure budget for 2005 from $512 million to $733 million. The $221 million increase was made in part to accommodate our $163 million South Texas acquisition expected to close November 30, 2005, which we intend to finance with borrowings under our revolving bank credit facility. As of September 30, 2005, we had spent $420.4 million of our capital budget for 2005. To maintain flexibility of our capital program, we typically do not enter into material long-term obligations with any of our drilling contractors or service providers with respect to our operated properties; however, we may choose to do so if an opportunity is economically beneficial. Throughout the remaining months of the current year, we will continue to evaluate our capital spending. Actual levels may vary due to a variety of factors, including service costs, drilling results, natural gas prices, economic conditions and future acquisitions.

On November 8, 2005, we announced that our capital expenditure budget for 2006 is expected to be $423 million, which excludes acquisitions but includes expenditures for our offshare assets for only the first quarter of 2006. Generally we do not include property acquisition costs in our capital budget because the size and timing of capital requirements for acquisitions are inherently unpredictable.

Future Commitments

As of September 30, 2005, we have a purchase obligation under an existing seismic license agreement to acquire additional seismic data for up to $7.7 million payable in January 2006 and we are obligated for up to $1.5 million under a one-year contract for a drilling rig in the Uinta Basin, which expires in February 2006. Our commitment under the drilling contract is reduced each month as the rig is utilized. As of September 30, 2005, we do not have any capital leases nor have we entered into any additional long-term contracts for drilling rigs or equipment.

The table below provides estimates of the timing of future payments that we were obligated to make based on agreements in place at September 30, 2005. In addition to the contractual obligations listed on the table below, our balance sheet at September 30, 2005, reflects accrued interest payable on our bank credit facility of approximately $0.4 million which is payable over the next 90-day period. We expect to make annual interest payments of $12.3 million per year on our $175 million of 7% senior subordinated notes due June 2013, and we anticipate making no further income tax payments during the remaining three months of 2005.

		Future Commitments
		Payments Due by Period
		Reference				Total				1 year or less				2 – 3 years				4 – 5 years				after 5 years
										(in thousands)
Contractual Obligations:
Revolving bank credit facility, due April 2008		Note 7				$	286,000			$	—			$	286,000				—			$	—
7% senior subordinated notes, due June 2013		Note 2					175,000				—				—				—				175,000
Derivative instruments		Note 1					696,679				537,139				159,540				—				—
South Texas acquisition, remaining purchase price		Note 7					146,700				146,700				—				—				—
Operating leases		Note 4					6,098				1,549				3,196				1,353				—
Letters of credit		Note 7					10,300				10,300				—				—				—
Seismic data purchase		Note 4					7,749				7,749				—				—				—
Drilling contract		Note 4					1,492				1,492				—				—				—
							1,330,018				704,929				448,736				1,353				175,000
Other Long-Term Obligations:
Asset retirement obligations		Note 1					101,204				1,503				12,288				7,065				80,348
Total contractual obligations and commitments						$	1,431,222			$	706,432			$	461,024			$	8,418			$	255,348

Capital Resources

We intend to fund our capital expenditure program, contractual commitments, the South Texas and any other acquisitions and possible stock repurchases with the proceeds from the sale of our Gulf of Mexico assets and/or from cash flows from our operations and borrowings under our revolving bank credit facility. Effective October 25, 2005, the borrowing base on our revolving bank credit facility was increased from $400 million to $450 million. In addition, we plan to further amend the facility to increase our banks’ lending commitment to $750 million, which may be further increased at our request and with prior approval from our lenders to a maximum of $850 million. We expect our initial borrowing base to be set at $600 million and following the amendment, all borrowings will be secured by 80% of our natural gas and oil assets. We anticipate the amendment to be effective by November 29, 2005; however, it is subject to a number of closing conditions, including negotiation of definitive documentation. If a significant acquisition opportunity arises, we may also access public markets for debt or to issue additional equity securities.

Our primary sources of cash during the first nine months of 2005 were from funds generated from operations. Cash was used to fund acquisitions, exploration and development expenditures and to reduce debt under our revolving bank credit facility. We made aggregate cash payments of $12.7 million for interest during the first nine months of 2005 and $19.3 million for federal or state income taxes during the same nine-month period. The table below summarizes the sources of cash for the first nine months of 2005 and 2004.

		Nine Months Ended September 30,
		2005				2004				variance				% change
		(in thousands)
Net cash provided by operating activities		$	383,981			$	402,302			$	(18,321	)			-5	%
Net cash (used) for investments in property and equipment			(400,998	)			(294,677	)			(106,321	)			36	%
Net cash provided by (used in) financing activities			7,217				(105,873	)			113,090				-107	%
Net change in cash		$	(9,800	)		$	1,752			$	(11,552	)			-659	%

At September 30, 2005, we had a working capital deficit of $362.0 million, long-term debt of $349 million and $203.7 million of borrowing capacity available under our revolving bank credit facility. The working capital deficit at September 30, 2005, was due to a current liability of $537.1 million representing the fair value of our derivative instruments estimated to be payable over the next 12 months, offset in part by the associated deferred tax asset of $190.1 million. As a result of the sustained high level of natural gas prices, the fair value of our open derivative contracts payable within the next 12 months increased by $469 million from a liability of $68.1 million at December 31, 2004, to a liability of $537.1 million at September 30, 2005. Corresponding to the increase in the liability, the associated deferred tax asset increased by $166 million during this same nine-month period. The fair value of our derivative instruments will fluctuate with commodity prices, and as commodity prices increase, our liquidity exposure tends to increase as a result of open derivative instruments. Consequently, we are more likely to have the largest unfavorable mark-to-market position in a high commodity price environment. Our working capital balance fluctuates as a result of the timing and amount of cash receipts and disbursements for operating activities and borrowings or repayments under our revolving bank credit facility. As a result, we often have a working capital deficit or a relatively small amount of positive working capital, which we believe is typical of companies of our size in the exploration and production industry. However, the sharp rise in prices at the end of September triggered in part by Hurricanes Katrina and Rita, resulted in a larger negative fair value than we consider normal.

Operating Activities. Net cash provided by operating activities decreased by $18.3 million during the first nine months of 2005. The decrease was primarily a result of the 29% decrease in operating income during the current nine-month period. In addition to fluctuations in operating assets and liabilities that are caused by timing of cash receipts and disbursements, commodity prices, production volume and operating expenses are the key factors driving changes in operating cash flows. For the current nine month period, we experienced lower production volumes together with higher operating expenses.

Investing Activities. Total capital expenditures during the first nine months of 2005 were $421.2 million, which includes $19.3 million in drilling costs accrued and unpaid at September 30, 2005. We invested $420.4 million in natural gas and oil properties, which included $31.7 million for producing property acquisitions during the first and second quarters, and we spent $0.8 million for non-oil and gas property and equipment. Non-oil and gas property and equipment includes expenditures to upgrade our information technology systems and office equipment and compares to $0.7 million spent during the first nine months of 2004. For the first nine months of 2005, we spent 40% offshore and 55% onshore with the balance of 5% on capitalized interest and general and administrative costs. We completed the drilling of 238 gross wells (192.8 net), of which 85%, or 203 (163.3 net), were successful and 15%, or 35 (29.5 net), were unsuccessful, with an additional 12 wells (8.5 net) in progress at September 30, 2005. During the corresponding nine months of 2004, we drilled 167 gross wells (139.6 net) of which 85% or 142 (119.0 net) were successful, with an additional 10 wells (8.5 net) in

progress at September 30, 2004. The following table provides a summary of our capital expenditures for natural gas and oil properties during the three-month and nine-month periods ended September 30, 2005 and 2004.

		Natural Gas and Oil Expenditures and Dispositions
		Three Months Ended September 30,								Nine Months Ended September 30,
		2005				2004				2005				2004
						(in thousands)
Producing property acquisitions		$	57			$	30,042			$	31,691			$	32,742
Leasehold and lease acquisition costs (1)			10,398				17,427				45,973				44,063
Development			102,732				63,858				250,784				180,558
Exploration			28,857				25,327				91,986				44,026
Total natural gas and oil capital expenditures			142,044				136,654				420,434				301,389
Producing property dispositions (2)			(718	)			(287	)			(868	)			(72,854	)
Net natural gas and oil capital expenditures		$	141,326			$	136,367			$	419,566			$	228,535