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 June 30, 2006

OR

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

(713) 830-6800
(Registrant’s Telephone Number, including Area 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ      Accelerated filer o      Non-accelerated filer o

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

As of August 7, 2006, 27,994,964 shares of Common Stock, par value $0.01 per share, were outstanding.

 

 

TABLE OF CONTENTS

Forward-Looking Statements			2
Available Information			2
Part I. Financial Information			3
Item 1. Condensed Consolidated Financial Statements			3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
Item 3. Quantitative and Qualitative Disclosures About Market Risk			34
Item 4. Controls and Procedures			36
Part II. Other Information			37
Item 1. Legal Proceedings			37
Item 1A. Risk Factors			37
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities			38
Item 4. Submission of Matters to a Vote of Security Holders			38
Item 6. Exhibits			38
SIGNATURES			40
First Amendment to Amended and Restated Credit Agreement
Form of Indemnification Agreement
Form of Non-Qualified Stock Option Agreement
Form of Director Restricted Stock Award Agreement
Form of Employee Restricted Stock Award Agreement
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

Certain statements in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the documents we have incorporated by reference into this Quarterly Report, other than purely historical information, including estimates, projections, statements relating to our business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, 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 forward-looking statements generally may be identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “would,” “will continue,” “will likely result,” and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to numerous risks and uncertainties which may cause actual results to differ materially from the forward-looking statements. A detailed discussion of these and other risks and uncertainties that could cause actual results and events to differ materially from such forward-looking statements is included in Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2005, as amended, our Quarterly Report on Form 10-Q for the three months ended March 31, 2006 and this Quarterly Report, as well as Risk Factors set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”). We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge on our Web site at http://www.houstonexploration.com as soon as reasonably practicable after we electronically file such material with, or otherwise furnish it to, the SEC.

Information contained on or connected to our Web site is not incorporated by reference into this Quarterly Report and should not be considered part of this report or any other filing that we make with the SEC.

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 our subsidiaries, THEC, LLC and THEC, LP, on a consolidated basis. Also, unless the context requires otherwise, we are reporting historical results as of June 30, 2006 and December 31, 2005, and for the three-month and six-month periods ended June 30, 2006 and 2005.

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, 2005, as amended. 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)

		June 30,				December 31,
		2006				2005
Assets:
Cash and cash equivalents		$	3,488			$	7,979
Accounts receivable			83,390				146,020
Inventories			4,215				2,726
Deferred tax asset			67,439				145,922
Prepayments and other			15,549				19,709
Total current assets			174,081				322,356
Natural gas and oil properties, full cost method
Unevaluated properties			39,381				107,146
Properties subject to amortization			3,129,560				3,556,755
Other property and equipment			13,880				12,971
			3,182,821				3,676,872
Less: Accumulated depreciation, depletion and amortization			1,799,997				1,658,532
			1,382,824				2,018,340
Designated cash			323,675				—
Other non-current assets			16,730				20,928
Total non-current assets			340,405				20,928
Total Assets		$	1,897,310			$	2,361,624
Liabilities:
Accounts payable and accrued expenses		$	185,743			$	177,159
Derivative financial instruments			44,165				352,457
Asset retirement obligation			—				7,265
Total current liabilities			229,908				536,881
Long-term debt and notes			275,000				597,000
Derivative financial instruments			36,928				65,201
Deferred income taxes			410,511				341,302
Asset retirement obligation			36,868				112,406
Other non-current liabilities			10,648				15,696
Total Liabilities			999,863				1,668,486
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, $0.01 par value, 100,000,000 shares authorized and 27,942,610 and 28,980,128 shares issued and outstanding at June 30, 2006 and December 31, 2005, respectively			279				289
Additional paid-in capital			245,100				297,218
Retained earnings			716,510				663,367
Accumulated other comprehensive (loss)			(64,442	)			(267,736	)
Total Stockholders’ Equity			897,447				693,138
Total Liabilities and Stockholders’ Equity		$	1,897,310			$	2,361,624

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 June 30,								Six Months Ended June 30,
		2006				2005				2006				2005
Revenues:
Natural gas and oil revenues		$	143,813			$	175,524			$	320,832			$	341,014
Other			2,101				293				2,686				523
Total revenues			145,914				175,817				323,518				341,537
Operating expenses:
Lease operating			18,032				19,124				39,844				34,492
Severance tax			4,830				4,530				10,989				7,464
Transportation expense			2,859				2,993				5,630				5,759
Asset retirement accretion expense			1,069				1,326				2,396				2,651
Depreciation, depletion and amortization			57,858				71,944				141,619				142,547
General and administrative, net of amounts capitalized			8,705				6,200				17,311				17,323
Total operating expenses			93,353				106,117				217,789				210,236
Income from operations			52,561				69,700				105,729				131,301
Other (income) expense			(791	)			(1,067	)			(2,198	)			387
Interest expense, net of amounts capitalized			6,451				3,196				15,172				6,630
Income before income taxes			46,901				67,571				92,755				124,284
Provision for taxes			23,530				23,741				39,612				47,016
Net income		$	23,371			$	43,830			$	53,143			$	77,268
Earnings per share:
Net income per share — basic		$	0.82			$	1.53			$	1.85			$	2.70
Net income per share — diluted		$	0.81			$	1.51			$	1.84			$	2.67
Weighted average shares outstanding — basic			28,625				28,679				28,770				28,589
Weighted average shares outstanding — diluted			28,678				28,973				28,824				28,920

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

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

		Six Months Ended June 30,
		2006				2005
Operating Activities:
Net income		$	53,143			$	77,268
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			141,619				142,547
Deferred income tax expense			36,293				30,988
Asset retirement accretion expense			2,396				2,651
Stock compensation expense			4,872				2,022
Tax benefit from non-qualified stock options			—				1,881
Unrealized (gain) loss on derivative instruments			(21,871	)			1,424
Debt extinguishment			572				—
Changes in operating assets and liabilities:
Accounts receivable			62,630				1,063
Inventories			(1,489	)			(663	)
Prepayments and other			4,160				6,397
Other non-current assets			3,825				1,411
Accounts payable and accrued expenses			(27,795	)			(11,160	)
Other non-current liabilities			(5,048	)			1,363
Net cash provided by operating activities			253,307				257,192
Investing Activities:
Investment in property and equipment			(278,572	)			(254,836	)
Designated cash			(323,675	)			—
Dispositions and other			723,648				165
Net cash provided by (used in) investing activities			121,401				(254,671	)
Financing Activities:
Proceeds from long-term borrowings			340,000				207,000
Repayments of long-term borrowings			(662,000	)			(232,000	)
Proceeds from issuance of common stock from exercise of stock options			4,426				8,596
Repurchase of common stock			(61,638	)			—
Debt issue costs			(199	)			—
Tax benefit from non-qualified stock options			212				—
Net cash used in financing activities			(379,199	)			(16,404	)
Decrease in cash and cash equivalents			(4,491	)			(13,883	)
Cash and cash equivalents, beginning of period			7,979				18,577
Cash and cash equivalents, end of period		$	3,488			$	4,694
Supplemental Information:
Non-cash transactions:
Investments in property and equipment accrued, not paid		$	(36,379	)		$	(24,046	)
Cash paid during period for:
Interest		$	16,470			$	10,494
Federal and state income taxes			—				10,860

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. We were founded in December 1985 as a Delaware corporation and wholly-owned subsidiary of our then parent company, KeySpan Corporation. We completed our initial public offering in September 1996. Through three separate transactions, the last of which occurred in November 2004, KeySpan completely divested of its ownership in the common stock of our company. At June 30, 2006, we had operations in four producing regions within the United States: South Texas; the Arkoma Basin of Arkansas and Oklahoma; East Texas; and the Uinta and DJ Basins in the Rocky Mountains.

In November 2005, we announced a strategic plan to restructure the company by pursuing the sale of our Gulf of Mexico assets, shifting our operating focus primarily onshore and repurchasing up to $200 million of our outstanding common stock. On March 31, 2006, we completed the sale of the Texas portion of our Gulf of Mexico assets and on June 1, 2006, we completed the sale of substantially all of our Louisiana Gulf of Mexico assets (see Note 6 – Acquisitions and Dispositions). The sale of these assets had a significant impact on our operating results for both the three- and six-month periods ended June 30, 2006 and on the comparability of those results both quarter-over-quarter and period-over-period. We received $721.6 million in net cash proceeds from the sale of substantially all of our Gulf of Mexico assets, of which we used $374.0 million to repay and reduce borrowings under our revolving credit facility; deposited $323.7 million with qualified intermediaries for potential reinvestment in like-kind exchange transactions under Section 1031 of the Internal Revenue Code; and used the balance of $23.9 million for working capital purposes.

On June 12, 2006, we received an unsolicited proposal from JANA Partners LLC, a hedge fund, to acquire our company for $62 per share. According to its public filings, JANA Partners beneficially owned approximately 12.3% of our outstanding common stock as of the date of the proposal. On June 26, 2006, we announced our Board of Directors’ determination that the unsolicited proposal made by JANA Partners was not in the best interest of our shareholders and that Lehman Brothers Inc. had been engaged to assist us in exploring a broad range of strategic alternatives to further enhance shareholder value. These alternatives may complement or replace the continued execution of our previously announced business plan and include, but are not limited to, a recapitalization of our company either through additional share repurchases or a special dividend; operating partnerships and / or strategic alliances; and the sale or merger of the company. As of the date of this Quarterly Report, this strategic review is ongoing.

Principles of Consolidation

Our consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. All significant inter-company balances and transactions have been eliminated.

Interim Financial Statements

Our balance sheet at June 30, 2006, 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 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, 2005 is derived from our December 31, 2005 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, 2005, as amended.

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

 

 

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 Annual Report for the year ended December 31, 2005, as amended.

Recent Accounting Pronouncements

In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement 109 (“FIN 48”)”, which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We are currently evaluating the impact of adopting FIN 48 on our financial statements

Overview of Results for the Second Quarter of 2006

During the second quarter of 2006, we continued to implement our restructuring plan to focus our operations primarily onshore. Completion of the sale of our Texas offshore properties on March 31, 2006 and our Louisiana offshore properties on June 1, 2006 had a significant impact on our operating results for the second quarter of 2006. Our total production volume for the second quarter of 2006 was 23% lower than first quarter 2006 and 27% lower than the second quarter of 2005 due primarily to the sale of our Gulf of Mexico assets combined with continued hurricane-related curtailments of certain offshore Louisiana fields prior to the completion of their sale on June 1, 2006. We expect that production volume, natural gas revenues and operating income will be lower unless and until we are able to replace the production generated from the Gulf of Mexico assets sold. In addition to lower production volume, we experienced lower operating expenses during the second quarter of 2006 as a result of the sale of our offshore assets. Natural gas prices during the second quarter of 2006 continued to decline from the record highs in the fourth quarter of 2005 primarily as a result of mild winter and spring weather combined with an increase in natural gas in U.S. storage. As a result of the lower natural gas prices, our cash losses from hedging activities improved significantly from the prior two quarters.

Our results of operations for the second quarter of 2006 include production, revenues and expenses relating to the Louisiana Gulf of Mexico properties until completion of the sale transactions on June 1, 2006. The sale of our Gulf of Mexico assets had a significant impact on our operating results for the second quarter of 2006 and on the comparability of those results quarter-over-quarter. During the second quarter of 2006:

	§		We generated $23.4 million in net income, a decrease of 47% from $43.8 million in the second quarter 2005;
	§		We produced approximately 22 Bcfe, and our average daily production rate was 239 MMcfe per day compared to 312 MMcfe per day during the first quarter of 2006 and 328 MMcfe per day during the second quarter of 2005, a 23% decrease from the previous quarter and a 27% decrease from a year ago;
	§		We generated $133.0 million cash flows from operating activities compared to $123.8 million generated during the second quarter of 2005, an increase of 7%;
	§		We invested $193.1 million in natural gas and oil properties, which included $21.3 million for the acquisition of producing properties and acreage with an estimated 16.2 Bcfe of proved reserves located in the Willow Springs Field of Gregg County, adjacent to our existing East Texas operations (see Note 6 – Acquisitions and Dispositions – East Texas Acquisition) and an estimated $30 million accrued for the payment of a net profits interest to the predecessor owner of certain Gulf of Mexico properties that was accelerated by the sale (see Note 6 – Acquisitions and Dispositions – Sale of Louisiana Gulf of Mexico Assets and Note 7 – Subsequent Events – Payment of Gulf of Mexico Net Profits Interest);
	§		We deposited $323.7 million in proceeds from the sale of our Gulf of Mexico assets with qualified intermediaries for potential reinvestment in like-kind exchange transactions under Section 1031 of the Internal Revenue Code;
	§		We decreased net borrowings under our revolving credit facility by $149 million during the second quarter of 2006 and by $322 million during the first six months of 2006, using a portion of the net proceeds from the sale of our Gulf of Mexico assets;
	§		We paid $14.3 million to liquidate and settle derivative contracts covering 60,000 MMBtu per day for each of the months July through December 2006, reducing our volume hedged from 250,000 MMBtu per day to 190,000

			MMBtu per day for each of the remaining six months of 2006 as required by our revolving credit facility in connection with our Gulf of Mexico sale;
	§		We commenced share repurchases under our previously announced $200 million stock repurchase authorization in May 2006, and during May and June 2006, we repurchased 1,176,500 shares, or approximately 4% of our outstanding common stock, in the open market for approximately $61.6 million, funded with cash on hand and borrowings under our revolving credit facility;
	§		We drilled 85 wells, of which 78, or 92%, were successful, with one offshore, six in East Texas, 23 in South Texas, 16 in Arkoma and 32 in the Rockies;
	§		In South Texas, we added an eighth drilling rig and began drilling on the properties acquired in November 2005;
	§		In the Rockies, we began to process seismic data and identify drilling locations on leased acreage in the DJ Basin covered by the 150 square mile 3D seismic survey completed during the first quarter of 2006 and continued to bring new wells on-line;
	§		Effective June 1, 2006 and in connection with the completion of the sale of the Louisiana portion of our Gulf of Mexico assets, the borrowing base on our revolving credit facility was reduced by $50 million, from $550 million to $500 million, and as a result of this reduction, we wrote-off unamortized loan costs of $0.6 million;
	§		On June 12, 2006, we received an unsolicited proposal from JANA Partners LLC to acquire our company for $62 per share; and
	§		On June 26, 2006, we announced our Board of Directors’ determination that the unsolicited proposal made by JANA Partners was not in the best interest of our shareholders and that Lehman Brothers Inc. had been engaged to assist us in exploring a broad range of strategic alternatives to further enhance shareholder value.

Operating and Financial Results for the Three – Month and Six – Month Periods Ended June 30, 2006 Compared to the Three – Month and Six – Month Periods Ended June 30, 2005.

Our operating results for the three-month and six-month periods ended June 30, 2006, include production, revenues and expenses relating to our Texas Gulf of Mexico properties until the completion of their sale on March 31, 2006 and our Louisiana Gulf of Mexico properties until the completion of their sale on June 1, 2006. The sale of our Gulf of Mexico assets had a significant impact on operating results for both the three-month and six-month periods ended June 30, 2006 and on the comparability of those results both quarter-over-quarter and period-over-period.

		Three Months Ended June 30,																Six Months Ended June 30,
		2006				2005				$ change				%				2006				2005				$ change				%
		(in thousands, except prices and percentages)
Natural gas revenues		$	129,785			$	181,054			$	(51,269	)			-28	%		$	328,290			$	345,023			$	(16,733	)			-5	%
Oil revenues			15,167				18,805				(3,638	)			-19	%			35,620				35,925				(305	)			-1	%
Gain (loss) on settled derivatives			(18,424	)			(24,335	)			5,911				-24	%			(64,949	)			(38,510	)			(26,439	)			69	%
Unrealized gain (loss) derivatives			17,285				—				17,285				100	%			21,871				(1,424	)			23,295				100	%
Operating revenues			145,914				175,817				(29,903	)			-17	%			323,518				341,537				(18,019	)			-5	%
Operating expenses			93,353				106,117				(12,764	)			-12	%			217,789				210,236				7,553				4	%
Income from operations			52,561				69,700				(17,139	)			-25	%			105,729				131,301				(25,572	)			-19	%
Net income			23,371				43,830				(20,459	)			-47	%			53,143				77,268				(24,125	)			-31	%
Production:
Natural gas (MMcf)			20,244				27,440				(7,196	)			-26	%			46,267				54,797				(8,530	)			-16	%
Oil (MBbls)			257				406				(149	)			-37	%			605				812				(207	)			-25	%
Total (MMcfe) (1)			21,786				29,876				(8,090	)			-27	%			49,897				59,669				(9,772	)			-16	%
Average daily production (MMcfe/d)			239				328				(89	)			-27	%			276				330				(54	)			-16	%
Average Sales Prices:
Natural Gas (per Mcf) unhedged		$	6.41			$	6.60			$	(0.19	)			-3	%		$	7.10			$	6.30			$	0.80				13	%
Natural Gas (per Mcf) realized (2)			5.50				5.71				(0.21	)			-4	%			5.69				5.59				0.10				2	%
Natural Gas (per Mcf) “all-in”(3)			6.35				5.71				0.64				11	%			6.16				5.57				0.60				11	%
Oil (per Bbl) realized			59.02				46.32				12.70				27	%			58.88				44.24				14.63				33	%

Income from Operations

Operating revenues, expenses and income were all lower during the second quarter of 2006 as compared to the second quarter of 2005 as a result of the sale of our offshore producing assets combined with continued hurricane-related curtailments of certain offshore Louisiana fields prior to completion of their sale on June 1, 2006. Production from the Gulf of Mexico assets sold accounted for approximately 42% of our total production and 45% of our natural gas and oil revenues before hedging activities during the second quarter of 2005.

For the first six months of 2006, the sale of our offshore assets had less of an impact, as the sale of the Texas portion of these assets was not completed until March 31, 2006 and the sale of the Louisiana portion was not completed until June 1, 2006. Operating revenues decreased to $18.0 million, or 5% lower during the first six months of 2006 as compared to the first six months of 2005, primarily as a result of a 16% decline in equivalent production volumes due primarily to the sale of our offshore producing assets, offset in part by an 11% increase in our average “all-in” natural gas price. While higher market prices for natural gas during the first six months of 2006 caused our losses from hedging activities to increase from the first six months of 2005, our losses from hedging activities narrowed considerably over the last two consecutive quarters due to the decline in natural gas prices from the record highs seen during the fourth quarter of 2005. Income from operations for the first six months of 2006 decreased by $25.6 million, or 19%, as compared to the first six months of 2005,

as operating expenses increased by 4% due primarily to rising service costs and higher severance tax rates, offset in part by lower depreciation, depletion and amortization expense.

Production Volume

As a result of the sale of the Texas portion of our offshore assets on March 31, 2006 and the Louisiana portion of our offshore assets on June 1, 2006, combined with continued hurricane-related curtailments from certain Louisiana fields, total company production volumes were 27% lower during the second quarter of 2006 compared to the second quarter of 2005 and 16% lower for the first six months of 2006 as compared to the first six months of 2005. The following table provides a comparison of average daily production by area:

		Three Months Ended June 30,																Six Months Ended June 30,
		2006				2005				change				%				2006				2005				change				%
		(MMcfe per day)																(MMcfe per day)
South Texas			142				139				3				2	%			143				137				6				4	%
Arkoma			39				41				(2	)			-5	%			40				42				(2	)			-5	%
East Texas			10				4				6				150	%			11				3				8				267	%
Rockies			6				4				2				50	%			6				5				1				20	%
Other			1				1				—				—				1				1				—				—
Total onshore			198				189				9				5	%			201				188				13				7	%
Offshore			41				139				(98	)			-71	%			75				142				(67	)			-47	%
Total company			239				328				(89	)			-27	%			276				330				(54	)			-16	%

Onshore. For the second quarter of 2006, daily production rates increased by 9 MMcfe per day, or 5%, from an average of 189 MMcfe per day during the second quarter of 2005 to an average of 198 MMcfe per day during the second quarter of 2006. For the first six months of 2006, onshore production increased by 13 MMcfe per day, or 7% from the first six months of 2005.

In South Texas, production increased quarter-over-quarter and period-over-period, primarily from the production added by the properties acquired in November 2005 from Kerr-McGee and Westport. In Arkoma, average daily production declined approximately 2 MMcfe per day, or 5% during the second quarter and the first half of 2006, due in part to a partial curtailment of our drilling activity late in the third quarter of 2005 as one of our drilling rigs left the field for repair, combined with curtailments during the second quarter of 2006 caused by over supply in the gathering system. In January 2006, the Arkoma rig returned to the field, where we currently have three rigs drilling. In East Texas, production is up over 100% from prior year levels, with an increase of 6 MMcfe per day for the second quarter of 2006 and 8 MMcfe per day for the first six months of 2006. The increase in East Texas production is due to our acquisition of acreage and producing wells during 2005 combined with the drilling program initiated in the second quarter of 2005 that added 16 new producing wells during 2005. This successful acquisition and development drilling program continued into the first half of 2006 with the acquisition of approximately 28 producing wells in the Willow Springs field in April 2006 and the successful drilling of 12 new wells. However, our East Texas production was curtailed during the second quarter of 2006 due to compression and pipeline issues. In the Rockies, we continue to add production and connect completed wells to sales as average daily production rates increased by 50% quarter-over-quarter and 20% period-over-period. However, high pressure in the Uinta pipeline caused curtailments during the second quarter of 2006.

Offshore. Production for the second quarter of 2006 includes offshore production from our Louisiana Gulf of Mexico assets during April and May, as the sale of these assets was completed June 1, 2006. Offshore production for the first six months of 2006 includes production from our Louisiana Gulf of Mexico during the first five months of 2006 and production from our Texas Gulf of Mexico assets for the first three months of 2006 as the sale of the Texas assets was completed on March 31, 2006. During both the three-month and six-month periods ended June 30, 2006, offshore production was lower than prior year rates due primarily to continued curtailments from Louisiana fields subsequent to Hurricanes Katrina and Rita during August and September 2005.

Commodity Prices and Effects of Hedging

During the fourth quarter of 2005 and the first quarter of 2006, a portion of our derivative contracts became ineffective as hedges. In conjunction with our entry into an agreement on February 28, 2006 to sell our Texas Gulf of Mexico assets, forecasted production volume attributable to these properties was deemed no longer available to cover open hedge positions and, because of the method we utilized to allocate hedged production, the remaining portion of all our open derivative contracts that previously qualified for hedge accounting ceased to qualify for hedge accounting. As a result, applicable accounting guidelines precluded our use of hedge accounting for all open derivative contracts at the end of the first quarter

of 2006. Accordingly, mark-to-market accounting is now utilized and all subsequent changes in the fair value of open derivative contracts are recognized as an increase or reduction to natural gas revenues.

The following table summarizes the components of our realized and unrealized gains and losses due to derivative contracts for the three-month and six-month periods ended June 30, 2006 and 2005. All amounts in the following table are shown on a pre-tax basis and are included in our statement of operations on the line item “natural gas and oil revenues.”

		Three Months Ended June 30,								Six Months Ended June 30,
		2006				2005				2006				2005
						(in thousands)
Cash (loss) realized on contracts settled (1)		$	(18,424	)		$	(24,335	)		$	(64,949	)		$	(38,510	)
Non-cash unrealized gain (loss):
Ineffectiveness gain (loss)			16,110				—				31,900				(1,424	)
Mark-to-market change in fair value gain (loss)			30,620				—				68,786				—
Deferred loss prior quarter production shortfalls			—				—				(20,600	)			—
Recognition of all deferred losses relating to Gulf of Mexico production sold during period			(29,445	)			—				(58,215	)			—
Total non-cash unrealized gain (loss)			17,285				—				21,871				(1,424	)
Total gain (loss) from hedging activities		$	(1,139	)		$	(24,335	)		$	(43,078	)		$	(39,934	)

For the three months ended June 30, 2006, our average unhedged sales price for natural gas decreased by 3% from $6.60 per Mcf during the second quarter of 2005 to $6.41 per Mcf during the second quarter of 2006. Because of the decrease in the market price for natural gas, our hedge positions were more effective and our total loss from hedging activities decreased by $23.2 million quarter-over-quarter. Included in natural gas revenues for the second quarter of 2006 is a net loss of $1.1 million from natural gas hedging activities, which is comprised of a realized loss of $18.4 million relating to contracts settled during the period and a net unrealized gain of $17.3 million as a result of accounting under SFAS 133. The $18.4 million realized loss during the second quarter of 2006 includes $14.3 million paid in connection with the completion of the sale of our Gulf of Mexico assets to liquidate and settle contracts totaling 60,000 MMBtu per day for each of the months July through December 2006. As a result of the cash loss from derivative contracts settled during the second quarter of 2006, we realized an average natural gas price during the quarter of $5.50 per Mcf, which was 14% lower than our average unhedged sales price of $6.41 per Mcf for the 2006 quarter. During the second quarter of 2005, we incurred a total loss from hedging activities of $24.3 million, which represented only realized losses on derivative contracts settled during the quarter, with no unrealized gains or losses due to ineffectiveness of our open contracts accounted for as cash flow hedges under SFAS 133. As a result of the cash loss from hedge contracts settled during the second quarter of 2005, we realized an average price of $5.71 per Mcf, which was 13% lower than our average unhedged sales price of $6.60 per Mcf for the 2005 quarter.

For the six months ended June 30, 2006, our average unhedged sales price for natural gas increased by 13% from $6.30 per Mcf during the first six months of 2005 to $7.10 per Mcf during the first six months of 2006. Our total loss from hedging activities increased by $3.1 million during the first six months of 2006 as compared to the first six months of 2005. Included in natural gas revenues for the first six months of 2006 is a net loss of $43.1 million from natural gas hedging activities, which includes a realized loss of $64.9 million relating to contracts settled during the six-month period and a net unrealized gain of $21.9 million as a result of accounting under SFAS 133. As a result of the cash loss from derivative contracts settled during the first six months of 2006, we realized an average natural gas price during the quarter of $5.69 per Mcf, which was 20% lower than our average unhedged sales price for the first six months of $7.10 per Mcf. During the corresponding six months of 2005, we incurred a total loss from hedging activities of $39.9 million, which includes realized losses on derivative contracts settled during the period of $38.5 million and an unrealized loss of $1.4 million due to ineffectiveness of our open contracts accounted for as cash flow hedges under SFAS 133. As a result of the cash loss from hedge contracts settled during the first six months of 2005, we realized an average price of $5.59 per Mcf, which was 11% lower than our average unhedged sales price for the first six months of 2005 of $6.30 per Mcf.

We may continue to experience volatility in our natural gas and oil revenues during future periods as mark-to-market accounting is utilized for all of our open derivative contracts.

Operating Expenses

		Three Months Ended June 30,																Six Months Ended June 30,
		2006				2005				$ change				%				2006				2005				$ change				%
														($ per MMcfe)
Lease operating expense		$	0.83			$	0.64			$	0.19				30	%		$	0.80			$	0.58			$	0.22				38	%
Severance tax			0.22				0.15				0.07				47	%			0.22				0.13				0.09				69	%
Transportation expense			0.13				0.10				0.03				30	%			0.11				0.10				0.01				10	%
Asset retirement accretion expense			0.05				0.04				0.01				25	%			0.05				0.04				0.01				25	%
Depreciation, depletion and amortization			2.66				2.41				0.25				10	%			2.84				2.39				0.45				19	%
General and administrative, net			0.40				0.21				0.19				90	%			0.35				0.29				0.06				21	%
Total operating expenses per unit of production		$	4.29			$	3.55			$	0.74				21	%		$	4.37			$	3.53			$	0.84				24	%

Total operating expenses on an absolute dollar basis decreased 12% during the second quarter of 2006 as compared to the second quarter of 2005, primarily as a result of lower lease operating expense and depreciation, depletion and amortization expense subsequent to the sale of the Texas Gulf of Mexico assets on March 31, 2006 and the sale of the Louisiana Gulf of Mexico assets on May 31 and June 1, 2006. For the first six months of 2006, total operating expenses on an absolute dollar basis increased 4% from the first six months of 2005, primarily as a result of higher lease operating expenses and severance tax expense as we continued to expand our operations prior to the sale of our offshore assets. On a unit of production basis, operating expenses increased $0.74 per Mcfe, or 21%, quarter-over-quarter and $0.84 per Mcfe, or 24% period-over-period. Per unit expenses were higher for all categories of operating expense for both the three-month and the six-month periods ended June 30, 2006 due to a higher level of operating expenses combined with a lower level of production due in part to the sale of our offshore producing assets and continued curtailment of production from these assets during the first five months of 2006 due to Hurricanes Katrina and Rita.

Lease Operating Expense. On an absolute dollar basis, lease operating expense decreased by 6% for the second quarter of 2006 as compared to the second quarter of 2005 and increased by 16% for the first six months of 2006 as compared to the first six months of 2005. The quarter-over-quarter decrease is a result of the disposition of our offshore assets, the Texas portion of which closed on March 31, 2006 and the Louisiana portion of which closed on June 1, 2006, offset in part by additional expense of $1.9 million during the second quarter of 2006 as a result of a cumulative adjustment for a net profits interest in the Rincon Field, located in South Texas that was acquired in November 2005. The increase in lease operating expense for the first six months of 2006 relates primarily to the continued upward pressure on service costs, labor, materials, insurance and property taxes resulting from the sustained strength of commodity prices driving increased activity levels across the industry, combined with the continued expansion of our operating base from acquisitions and the escalation of our onshore drilling program prior to the sale of our offshore assets.

Severance Tax. Severance tax is a function of volumes and revenues generated from onshore production. During the second quarter of 2006, severance tax expense increased by 7% on an absolute dollar basis and by $0.07 per Mcfe on a unit of production basis from the second quarter 2005. During the first six months of 2006, severance tax expense increased by 47% on an absolute dollar basis and by $0.09 on a unit of production basis from the first six months of 2005. These absolute dollar and per unit rate increases reflect higher commodity prices, an increase in severance tax rates and an increase in onshore production both quarter-over-quarter and period-over-period, due in part to the South Texas properties acquired in November 2005. We expect our severance tax per unit of production to increase considerably now that we have sold all our offshore producing assets.

Depreciation, Depletion and Amortization. The decrease in our depreciation, depletion and amortization expense for the both the three-month and six-month periods ended June 30, 2006 as compared to the corresponding periods of 2005 was primarily a result of lower production volume subsequent to the sale of our offshore producing assets, offset in part by higher depletion rates during 2006. Our depreciation, depletion and amortization rate for the second quarter of 2006 was $2.66 per Mcfe, or 10% higher than the $2.41 per Mcfe during the second quarter of 2005. For the first six months of 2006, our depreciation, depletion and amortization rate of $2.84 per Mcfe was $0.45 per Mcfe or 19% higher than our depreciation, depletion and amortization rate of $2.39 per Mcfe during the first six months of 2005. The higher rates during the three-month and six-month periods ended June 30, 2006 compared to corresponding periods of 2005 are a result of the increases in both our finding and future development costs.

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

		Absolute Dollars
		Three Months Ended June 30,																Six Months Ended June 30,
		2006				2005				$ change				%				2006				2005				$ change				%
		(in thousands)
Gross general and administrative expense		$	15,008			$	10,516			$	4,492				43	%		$	29,406			$	26,478			$	2,928				11	%
Operating overhead reimbursements			(583	)			(525	)			(58	)			11	%			(1,181	)			(1,075	)			(106	)			10	%
Capitalized general and administrative			(5,720	)			(3,791	)			(1,929	)			51	%			(10,914	)			(8,080	)			(2,834	)			35	%
General and administrative expense, net		$	8,705			$	6,200			$	2,505				40	%		$	17,311			$	17,323			$	(12	)			—

Gross and net general and administrative expenses were higher during the second quarter of 2006 and the first six months of 2006 as compared to the corresponding three-month and six-month periods of 2005 due to increases in salaries, benefits and incentive compensation expenses, stock compensation expense, legal and consulting fees and office rent and utilities. In addition, during the second quarter of 2006 we incurred additional expenses of approximately $1.7 million, which included approximately $1.3 million in bonuses paid to certain employees in connection with the completion of the sale of our Gulf of Mexico assets and approximately $0.4 million in severance payments to certain employees in our offshore group who were terminated following the sale of the assets. During the first six months of 2005 we incurred additional expenses of approximately $5.0 million pursuant to the February 2005 renegotiation of executive employment agreements. Excluding the $5.0 million in additional expenses incurred during the first six months of 2005 and the additional $1.7 million for special bonuses and severance payments to offshore employees during the second quarter of 2006, gross general and administrative expenses would reflect an increase of $6.2 million, or 29%, and net general and administrative expenses would reflect an increase of $4.7 million, or 38%, for the first six months of 2006. Capitalized general and administrative expense increased during the second quarter of 2006 and the first six months of 2006 as a result of the increase in salaries, benefits and incentive compensation expenses for our technical workforce.

		Unit of Production - Mcfe
		Three Months Ended June 30,																Six Months Ended June 30,
General and Administrative Expense		2006				2005				Variance								2006				2005				Variance
		($ per MMcfe)
Gross general and administrative expense		$	0.69			$	0.35			$	0.34				97	%		$	0.59			$	0.44			$	0.15				34	%
Operating overhead reimbursements			(0.03	)			(0.02	)			(0.01	)			50	%			(0.02	)			(0.02	)			—				—
Capitalized general and administrative			(0.26	)			(0.12	)			(0.14	)			117	%			(0.22	)			(0.13	)			(0.09	)			69	%
General and administrative expense, net		$	0.40			$	0.21			$	0.19				90	%		$	0.35			$	0.29			$	0.06				21	%

On a per-unit of production basis, both gross and net general and administrative expenses were higher during the three-month and six-month periods of 2006 and reflect the increase in gross general and administrative expense and the decrease in production volume resulting primarily from the sale of our offshore assets. The additional $1.7 million in special bonuses and severance expense incurred during the second quarter of 2006 in connection with the completion of the sale of our offshore assets contributed $0.08 to the increase in gross general and administrative expense per-unit for the second quarter of 2006 and $0.03 per Mcfe of the increase for the first six months of 2006. The additional $5.0 million in employment contract renegotiation expenses incurred during the first quarter of 2005 accounted for $0.08 of gross and net general and administrative expenses per-unit of production for the first six months of 2005. We expect that general and administrative expenses on a per-unit of production basis will be higher in future periods unless and until we are able to replace the production from the assets sold.

Other Income and Expense, Interest and Taxes

Other Income and Expense. For the second quarter of 2006 and 2005, other income and expense is comprised of income of $0.8 million and $1.0 million, respectively, related to refunds of prior years’ severance tax expense. For the first six months of 2006, other income and expense includes $2.2 million related to refunds of prior years’ severance tax expense. For the first six months of 2005 income and expense includes (i) income of $2.4 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%. Refunds of prior years’ severance tax expense relate to our July 2002 application and receipt from the Railroad Commission of Texas of 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 June 30,																Six Months Ended June 30,
Interest and Average Borrowings		2006				2005				Variance								2006				2005				Variance
		(dollars in thousands)
Gross interest		$	7,451			$	5,621			$	1,830				33	%		$	17,827			$	11,045			$	6,782				61	%
Capitalized interest			(1,000	)			(2,425	)			1,425				59	%			(2,655	)			(4,415	)			1,760				40	%
Interest expense, net of capitalized interest		$	6,451			$	3,196			$	3,255				102	%		$	15,172			$	6,630			$	8,542				129	%
Average total borrowings (1)		$	371,000			$	346,000			$	25,000				7	%		$	494,000			$	345,000			$	149,000				43	%
Average total interest rate (1)			6.97	%			6.04	%			0.93	%			15	%			6.66	%			5.94	%			0.72	%			12	%
Average bank borrowings		$	196,000			$	171,000			$	25,000				15	%		$	319,000			$	170,000			$	149,000				88	%
Average bank interest rate			7.02	%			5.13	%			1.89	%			37	%			6.50	%			4.88	%			1.62	%			33	%

For both the three-month and six-month periods ended June 30, 2006, 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. In addition, gross interest expense for the three-month and six-month periods ended June 30, 2006 includes an additional $0.6 million for debt extinguishment incurred in connection with the decrease in the borrowing base of our revolving credit facility upon completion of the Gulf of Mexico asset sale transactions. Our average bank debt increased after the first quarter of 2005 and through the end of the first quarter of 2006 as we utilized bank borrowings to fund acquisitions in East Texas and South Texas and to settle obligations under derivative contracts. Using a portion of the proceeds from the sale of our Gulf of Mexico assets, we reduced bank borrowings by a net $322 million during the first six months of 2006 to an outstanding balance of $100 million at June 30, 2006. Although the majority of our bank debt bears interest at LIBOR-based rates, the Federal Reserve raised rates by one quarter of a percent eight times during 2005 and four times during the first six months of 2006. We expect to continue to see an increase in the average interest rates on our bank debt if the Federal Reserve continues to increase interest rates. Capitalized interest is a function of unevaluated properties, and decreased significantly by 59% during the second quarter of 2006 and by 40% during the first six months of 2006 as compared to the corresponding three-month and six-month periods of 2005. The decrease corresponds directly to the decrease in the balance of our unevaluated properties, of which approximately $75.8 million related to our Gulf of Mexico assets sold during the first six months of 2006. We expect our capitalized interest to be lower and our net interest expense to be proportionally higher with the shift in our operating focus onshore. We expect our unevaluated property balance to be lower given the lower cost structure of onshore projects and the shorter timeline to complete the evaluation of onshore projects.

Income Tax Provision. Our provision for taxes includes both state and federal taxes. In May 2006, the State of Texas enacted substantial changes to its tax structure beginning in 2007 by implementing a new margin tax of 1% to be imposed on revenues less certain costs, as specified in the legislation. During the second quarter of 2006, we increased our provision by an additional $6.8 million to provide for deferred taxes to the State of Texas under the newly enacted state margin tax.

Liquidity

Capital Requirements

Our principal requirements for capital are to fund our planned exploration, development and acquisition activities and to satisfy our contractual obligations, primarily including the repayment of debt and any amounts owing during the period relating to our derivative contracts, as well as repurchases of common stock from time to time. Our principal uses of capital include the following:

	§		Drilling and completing new natural gas and oil wells;
	§		Constructing and installing new production infrastructure;
	§		Acquiring additional reserves and producing properties;
	§		Acquiring and maintaining our lease acreage position and our seismic resources;
	§		Maintaining, repairing, and enhancing existing natural gas and oil wells;