Edgar Filing: CABOT OIL & GAS CORP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

For the quarterly period ended March 31, 2007

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

DELAWARE

04-3072771

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

1200 Enclave Parkway, Houston, Texas 77077

(Address of principal executive offices including ZIP Code)

(281) 589-4600

(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 and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is 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. (Check one):

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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

As of April 30, 2007, there were 96,899,682 shares of Common Stock, Par Value $.10 Per Share, outstanding.

CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS


Part I. Financial Information		Page

Item 1.	Financial Statements

	Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2007 and 2006	3

	Condensed Consolidated Balance Sheet at March 31, 2007 and December 31, 2006	4

	Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2007 and 2006	5

	Notes to the Condensed Consolidated Financial Statements	6

	Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information	19

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	29

Item 4.	Controls and Procedures	31

Part II. Other Information

Item 1.	Legal Proceedings	31

Item 1A.	Risk Factors	31

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31

Item 6.	Exhibits	32

Signatures		33

PART I. FINANCIAL INFORMATION

ITEM 1.

Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)


	Three Months Ended March 31,
(In thousands, except per share amounts)	2007		2006
OPERATING REVENUES
Natural Gas Production	$	146,750	$	155,167
Brokered Natural Gas		33,177		32,819
Crude Oil and Condensate		10,942		24,180
Other		704		2,602

		191,573		214,768
OPERATING EXPENSES
Brokered Natural Gas Cost		28,699		29,245
Direct Operations – Field and Pipeline		17,131		17,630
Exploration		5,652		11,614
Depreciation, Depletion and Amortization		33,395		31,935
Impairment of Unproved Properties		3,986		3,580
General and Administrative		18,280		14,252
Taxes Other Than Income		13,165		15,495

		120,308		123,751
Gain on Sale of Assets		7,920		207

INCOME FROM OPERATIONS		79,185		91,224
Interest Expense and Other		3,924		6,150

Income Before Income Taxes		75,261		85,074
Income Tax Expense		26,714		31,909

NET INCOME	$	48,547	$	53,165

Basic Earnings Per Share	$	0.50	$	0.55
Diluted Earnings Per Share	$	0.50	$	0.54

Weighted Average Common Shares Outstanding		96,695		97,360
Diluted Common Shares (Note 5)		98,047		98,747

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

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)


	March 31,			December 31,
(In thousands, except share amounts)	2007			2006
ASSETS
Current Assets
Cash and Cash Equivalents	$	57,442		$	41,854
Accounts Receivable, Net		97,507			116,546
Income Taxes Receivable		—			24,512
Inventories		15,410			32,997
Deferred Income Taxes		9,901			9,386
Derivative Contracts		30,373			81,982
Other		8,886			8,405

Total Current Assets		219,519			315,682
Properties and Equipment, Net (Successful Efforts Method)		1,568,108			1,480,201
Deferred Income Taxes		33,871			30,912
Other Assets		21,859			7,696

	$	1,843,357		$	1,834,491

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	137,798		$	147,680
Current Portion of Long-Term Debt		20,000			20,000
Deferred Income Taxes		12,012			31,962
Income Taxes Payable		9,499			9,282
Accrued Liabilities		37,801			42,103

Total Current Liabilities		217,110			251,027
Long-Term Liability for Pension Benefits (Note 10)		8,198			7,219
Long-Term Liability for Postretirement Benefits (Note 10)		19,132			18,204
Long-Term Debt (Note 4)		210,000			220,000
Deferred Income Taxes		367,387			347,430
Other Liabilities		55,637			45,413
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common Stock:
Authorized — 120,000,000 Shares of $0.10 Par Value in 2007 and 2006, respectively Issued and Outstanding — 102,053,232 Shares and 101,418,220 Shares in 2007 and 2006, respectively		10,205			10,142
Additional Paid-in Capital		424,490			417,995
Retained Earnings		612,205			565,591
Accumulated Other Comprehensive Income (Note 8)		4,683			37,160
Less Treasury Stock, at Cost: 5,204,700 Shares in both 2007 and 2006		(85,690	)		(85,690	)

Total Stockholders’ Equity		965,893			945,198

	$	1,843,357		$	1,834,491

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

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)


	Three Months Ended March 31,
(In thousands)	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	48,547		$	53,165
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		33,395			31,935
Impairment of Unproved Properties		3,986			3,580
Deferred Income Tax Expense		15,874			12,893
Gain on Sale of Assets		(7,920	)		(207	)
Exploration Expense		5,652			11,614
Stock-Based Compensation Expense and Other		7,170			4,870
Changes in Assets and Liabilities:
Accounts Receivable, Net		19,039			42,130
Income Taxes Receivable		17,902			11,850
Inventories		17,587			10,830
Other Current Assets		(481	)		913
Other Assets		(13,300	)		(79	)
Accounts Payable and Accrued Liabilities		(28,548	)		(34,124	)
Income Taxes Payable		10,963			6,461
Other Liabilities		10,127			2,130
Stock-Based Compensation Tax Benefit		(4,135	)		(2,952	)

Net Cash Provided by Operating Activities		135,858			155,009

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(113,748	)		(103,116	)
Proceeds from Sale of Assets		5,784			541
Exploration Expense		(5,652	)		(11,614	)

Net Cash Used in Investing Activities		(113,616	)		(114,189	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		—			55,000
Decrease in Debt		(10,000	)		(100,000	)
Sale of Common Stock Proceeds		1,144			1,062
Stock-Based Compensation Tax Benefit		4,135			2,952
Dividends Paid		(1,933	)		(1,946	)

Net Cash Used in Financing Activities		(6,654	)		(42,932	)


Net Increase / (Decrease) in Cash and Cash Equivalents		15,588			(2,112	)
Cash and Cash Equivalents, Beginning of Period		41,854			10,626

Cash and Cash Equivalents, End of Period	$	57,442		$	8,514

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

CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies used in its Annual Report to Stockholders and its Annual Report on Form 10-K for the year ended December 31, 2006 filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the financial statements and information presented in the Company’s 2006 Annual Report to Stockholders and its Annual Report on Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation. Additionally, certain amounts have been reclassified to conform to the fiscal year 2007 presentation. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Our independent registered public accounting firm has performed a review of these condensed consolidated interim financial statements in accordance with standards established by the Public Company Accounting Oversight Board (United States). Pursuant to Rule 436(c) under the Securities Act of 1933, this report should not be considered a part of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meanings of Sections 7 and 11 of the Act.

On February 23, 2007, the Board of Directors declared a 2-for-1 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 30, 2007 to stockholders of record on March 16, 2007. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company’s common stock. The pro forma effect on the December 31, 2006 Balance Sheet was a reduction to Additional Paid-in Capital and an increase to Common Stock of $5.1 million.

Effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” Due to this adoption, the Company recorded a charge of less than $0.1 million in the first quarter of 2007 for incremental interest expense that is more likely than not payable. For further information regarding the adoption of FIN No. 48, please refer to Note 12 of the Notes to the Condensed Consolidated Financial Statements.

Recently Issued Accounting Pronouncements

In February 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” which permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The objective of this Statement is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of the Statement apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. Additional disclosures are also required for instruments for which the fair value option is elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. The Company is currently evaluating what impact, if adopted, SFAS No. 159 may have on its financial position, results of operations.

value included in various accounting standards. However, the application of this Statement may change current practices for certain companies. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating what impact SFAS No. 157 may have on its financial position or results of operations.

2. PROPERTIES AND EQUIPMENT, NET

Properties and equipment, net are comprised of the following:


	March 31,			December 31,
(In thousands)	2007			2006
Unproved Oil and Gas Properties	$	117,546		$	114,108
Proved Oil and Gas Properties		2,221,989			2,109,045
Gathering and Pipeline Systems		209,121			205,473
Land, Building and Improvements		4,997			4,976
Other		34,499			34,067

		2,588,152			2,467,669
Accumulated Depreciation, Depletion and Amortization		(1,020,044	)		(987,468	)

	$	1,568,108		$	1,480,201

At March 31, 2007, the Company did not have any capitalized well costs that have been capitalized for greater than one year after drilling was suspended.

At December 31, 2006, the Company had four projects that had $0.1 million of exploratory well costs that were capitalized since 2005 for a period greater than one year. This amount related to three projects comprised of preliminary costs incurred in the preparation of well sites where drilling had not commenced as of December 31, 2006. In 2007, it was determined not to drill these projects and associated costs were expensed. Also included in the December 31, 2006 amount was another well that had completed drilling in January 2007 and was awaiting completion results before confirmation of proved reserves could be made. That well was completed in 2007 and proved reserves have been recorded in the first quarter of 2007.

Disposition of Assets

On September 29, 2006, the Company substantially completed the sale of its offshore portfolio and certain south Louisiana properties to Phoenix Exploration Company LP (Phoenix) for a gross sales price of $340.0 million. Through March 31, 2007, the Company had received approximately $333.3 million in net proceeds from the sale, comprised of $327.5 million received through December 31, 2006 and $5.8 million of net proceeds received during the first quarter of 2007 attributable to consents obtained for closing of certain property sales to Phoenix for which third party consents had not been obtained as of December 31, 2006. In addition to the net gain of $231.2 million ($144.5 million, net of tax) recorded for the year ended December 31, 2006, the Company recorded a net gain $7.9 million ($4.9 million, net of tax) in the Condensed Consolidated Statement of Operations for the quarter ended March 31, 2007. This gain recorded in the first quarter of 2007 reflects cash proceeds of $5.8 million and a $2.1 million increase due to purchase price adjustments. During the second quarter of 2007, approximately a $4.4 million additional gain is expected to be recognized in connection with the closing of sales to other parties that exercised their contractual preferential rights. This gain will be subject to customary purchase price adjustments.

3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:


	March 31,			December 31,
(In thousands)	2007			2006
ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	90,364		$	102,023
Joint Interest Accounts		11,966			18,574
Other Accounts		203			501

		102,533			121,098
Allowance for Doubtful Accounts		(5,026	)		(4,552	)

	$	97,507		$	116,546

INVENTORIES
Natural Gas and Oil in Storage	$	5,565		$	22,717
Tubular Goods and Well Equipment		8,151			7,680
Pipeline Imbalances		1,694			2,600

	$	15,410		$	32,997

OTHER CURRENT ASSETS
Drilling Advances	$	376		$	651
Prepaid Balances		8,172			7,416
Other Accounts		338			338

	$	8,886		$	8,405

ACCOUNTS PAYABLE
Trade Accounts	$	8,201		$	28,569
Natural Gas Purchases		6,221			8,356
Royalty and Other Owners		36,363			37,230
Capital Costs		68,564			59,524
Taxes Other Than Income		6,039			4,805
Drilling Advances		3,565			1,506
Wellhead Gas Imbalances		2,823			2,288
Other Accounts		6,022			5,402

	$	137,798		$	147,680

ACCRUED LIABILITIES
Employee Benefits	$	3,707		$	13,575
Current Liability for Pension Benefits		67			67
Current Liability for Postretirement Benefits		577			577
Taxes Other Than Income		20,299			15,696
Interest Payable		4,848			5,995
Other Accounts		8,303			6,193

	$	37,801		$	42,103

OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan	$	14,451		$	6,077
Accrued Plugging and Abandonment Liability		22,794			22,655
Other Accounts		18,392			16,681

	$	55,637		$	45,413

4. LONG-TERM DEBT

At March 31, 2007, the Company had no borrowings under its revolving credit facility. The credit facility provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. The term of the credit facility expires in December 2009. The credit facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of six months either to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or to pay down one-sixth of the excess during each of the six months.

The Company had the following debt outstanding at March 31, 2007:

•

$60 million of 12-year 7.19% Notes due in November 2009, which consisted of $40 million of long-term debt and $20 million of current portion of long-term debt, to be repaid in three remaining annual installments of $20 million in November of each year

•

$75 million of 10-year 7.26% Notes due in July 2011

•

$75 million of 12-year 7.36% Notes due in July 2013

•

$20 million of 15-year 7.46% Notes due in July 2016

The Company is in compliance in all material respects with its debt covenants.

5. EARNINGS PER SHARE

Basic Earnings per Share (EPS) is computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated using the treasury stock method except that the denominator is increased to reflect the potential dilution that could occur if stock options and stock awards outstanding at the end of the applicable period were exercised for common stock.

The following is a calculation of basic and diluted weighted average shares outstanding for the three months ended March 31, 2007 and 2006:


	Three Months Ended March 31,
	2007	2006
Weighted Average Shares - Basic	96,695,471	97,359,822
Dilution Effect of Stock Options and Awards at End of Period	1,351,187	1,386,958

Weighted Average Shares - Diluted	98,046,658	98,746,780

Weighted Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect	218,840	—

6. COMMITMENTS AND CONTINGENCIES

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of its business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s condensed consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

West Virginia Royalty Litigation

In December 2001, the Company was sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification and allege that the Company failed to pay royalty based upon the wholesale market value of the gas, that the Company had taken improper deductions from the royalty and that it failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings.

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The Court entered an order on June 1, 2005 granting the motion for class certification. The parties have negotiated a modification to the order which resulted in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and limiting the claims to those arising on and after December 17, 1991. The Court postponed a trial date of April 17, 2006, in light of the case involving an unrelated party pending before the West Virginia Supreme Court of Appeals described below. The Company intends to challenge the class certification order by filing a motion to decertify all or part of the class, or by appeal to the West Virginia Supreme Court of Appeals.

The West Virginia Supreme Court of Appeals issued a decision in 2006 in a case against another producer (the Tawney case) that raised some of the same issues as are raised in the Company’s case. This recent decision may negatively impact some of the defenses the Company has raised in its litigation with respect to the issue of deductibility of post-production expenses under certain leases, but it believes that in a significant number of leases the Company has lease language, factual distinctions and defenses that are not implicated by the ruling.

The Tawney case involves claims concerning the deductibility of post-production expenses and the failure to properly inform, issues shared with the Company’s case, but also involves additional claims not raised in its case. The most significant additional claims in the Tawney case are related to sales under long-term, fixed-price agreements at prices considered significantly below market value, as well as claims for certain volume reductions and unmetered production. The Tawney case went to trial in January 2007, and the jury returned a verdict against the producer for $130 million in compensatory damages and $270 million in punitive damages. Judgment has not yet been entered in the Tawney case, and an appeal is expected. The Company is closely monitoring developments in the Tawney case, and it continues to investigate how this recent ruling may impact its defense of the case. The case against the Company has been re-activated to the docket and trial is set for August 13, 2007.

The Company is vigorously defending the case. A reserve has been established that management believes is adequate based on its estimate of the probable outcome of this case.

Commitment and Contingency Reserves

The Company has established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the

Company could incur approximately $9.1 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

While the outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the condensed consolidated financial position or cash flow of the Company. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Firm Gas Transportation Agreements

The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. The agreements provide firm transportation capacity rights on pipeline systems in Canada, the West region and the East region. The remaining terms on these agreements range from less than one year to 21 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company.

The amount of demand charges on firm gas transportation agreements has decreased by approximately $2.4 million from the amount previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006. This is due to released volumes on one contract in the West region. As of March 31, 2007, demand charges for 2007 and 2008, respectively, are expected to be $8.2 million and $7.5 million, a decrease of $1.7 million and $0.7 million from the figures previously disclosed. For further information on these future obligations, please refer to Note 7 of the Notes to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2006.

Drilling Rig Commitments

In its Annual Report on Form 10-K for the year ended December 31, 2006, the Company disclosed that it had commitments on seven drilling rigs under contract in the Gulf Coast and that one of these rigs had not yet been delivered. This rig was delivered in April 2007. In addition, the total commitment increased by $0.7 million in the aggregate ($0.2 million, $0.3 million and $0.2 million in each of 2007, 2008 and 2009, respectively) as of March 31, 2007. This increase was due to an increase in the daily rig rates on two rigs as a result of an increase of 5% in the U.S. Department of Labor Wholesale Price Index for Oilfield Machinery and Tools from the base index, as required in the commitment agreement. For further information on these future obligations, please refer to Note 7 of the Notes to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2006.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. Under the Company’s revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At March 31, 2007, the Company had 22 cash flow hedges open: 21 natural gas price collar arrangements and one crude oil collar arrangement. At March 31, 2007, a $29.4 million ($18.3 million, net of tax) unrealized gain was recorded in Accumulated Other Comprehensive Income, along with a $30.4 million short-term derivative receivable, a $1.8 million short-term derivative liability (included within Accrued Liabilities on the Balance Sheet) and a $0.8 million long-term derivative receivable (included within Other Assets on the Balance Sheet). The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives, is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate. During the first three months of 2007 and 2006, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations.

Assuming no change in commodity prices, after March 31, 2007 the Company would expect to reclassify to the Condensed Consolidated Statement of Operations, over the next 12 months, $17.8 million in after-tax income associated with commodity hedges. This reclassification represents the net short-term receivable associated with open positions currently not reflected in earnings at March 31, 2007 related to anticipated 2007 and 2008 production.

During the first three months of 2007, the Company entered into two new natural gas collar contracts covering a portion of its 2008 production. As of March 31, 2007, natural gas price collars for 2008 cover 6,584 Mmcf of production at a weighted average floor of $8.62 per Mcf and a weighted average ceiling of $11.15 per Mcf.

8. COMPREHENSIVE INCOME

Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the three month periods ended March 31, 2007 and 2006:


	Three Months Ended March 31,
(In thousands)	2007						2006
Accumulated Other Comprehensive Income / (Loss) - Beginning of Period				$	37,160					$	(15,115	)
Net Income	$	48,547						53,165
Other Comprehensive (Loss) / Income
Reclassification Adjustment for Settled Contracts, net of taxes of $6,719 and $546, respectively		(11,056	)					(891	)
Changes in Fair Value of Hedge Positions, net of taxes of $12,904 and $(12,125), respectively		(21,886	)					19,785
Foreign Currency Translation Adjustment, net of taxes of $(282) and $135, respectively		465						(220	)

Total Other Comprehensive (Loss) / Income		(32,477	)		(32,477	)		18,674			18,674

Comprehensive Income	$	16,070					$	71,839

Accumulated Other Comprehensive Income - End of Period				$	4,683					$	3,559

Changes in the components of accumulated other comprehensive income, net of taxes, for the three months ended March 31, 2007 were as follows:


Accumulated Other Comprehensive Income (In thousands)	Net Gains / (Losses) on Cash Flow Hedges			Defined Benefit Pension and Postretirement Plans			Foreign Currency Translation Adjustment		Total
Balance at December 31, 2006	$	51,239		$	(14,168	)	$	89	$	37,160

Net change in unrealized gains on cash flow hedges, net of taxes of $19,623		(32,942	)		—			—		(32,942	)
Change in foreign currency translation adjustment, net of taxes of $(282)		—			—			465		465

Balance at March 31, 2007	$	18,297		$	(14,168	)	$	554	$	4,683

9. ASSET RETIREMENT OBLIGATIONS

The following table reflects the changes in the asset retirement obligations during the three months ended March 31, 2007:


(In thousands)
Carrying amount of asset retirement obligations at December 31, 2006	$	22,655
Liabilities added during the current period		342
Liabilities settled and divested during the current period		(452	)
Current period accretion expense		249

Carrying amount of asset retirement obligations at March 31, 2007	$	22,794

Accretion expense was $0.2 million and $0.3 million, respectively, for the three months ended March 31, 2007 and 2006 and is included within Depreciation, Depletion and Amortization expense on the Company’s Condensed Consolidated Statement of Operations.

10. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs for the three months ended March 31, 2007 and 2006 were as follows:


	Three Months Ended March 31,
(In thousands)	2007			2006
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	733		$	680
Interest Cost		692			583
Expected Return on Plan Assets		(754	)		(476	)
Amortization of Prior Service Cost		36			44
Amortization of Net Loss		272			303

Net Periodic Pension Cost	$	979		$	1,134

Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	224		$	197
Interest Cost		266			219
Plan Termination Gain		—			(21	)
Amortization of Net Loss		42			8
Amortization of Prior Service Cost		238			238
Amortization of Net Obligation at Transition		158			158

Total Postretirement Benefit Cost	$	928		$	799

Employer Contributions

The funding levels of the pension and postretirement plans are in compliance with standards set by applicable law or regulation. The Company previously disclosed in its financial statements for the year ended December 31, 2006 that it expected to contribute less than $0.1 million to its non-qualified pension plan and approximately $0.6 million to the postretirement benefit plan during 2007. It is anticipated that these contributions will be made prior to December 31, 2007. The Company does not have any required minimum funding obligations for its qualified pension plan in 2007. Management has not determined if any discretionary funding will be made to the qualified pension plan during the remainder of 2007.

11. STOCK-BASED COMPENSATION

Incentive Plans

On April 29, 2004, the 2004 Incentive Plan was approved by the stockholders. Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards. In the first quarter of 2007, the Compensation Committee eliminated the automatic award of an option to purchase 15,000 shares (pre 2-for-1 split) of common stock on the date the non-employee directors first join the board of directors. A total of 5,100,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 1,800,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 3,000,000 shares may be issued pursuant to incentive stock options.

Stock-Based Compensation Expense

Compensation expense charged against income for stock-based awards in the first quarter of 2007 and 2006 was $6.6 million and $4.9 million, pre-tax, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations.

For further information regarding Stock-Based Compensation, please refer to Note 10 of the Notes to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2006.

Restricted Stock Awards

Restricted stock awards vest either at the end of a three year service period, or on a graded-vesting basis of one-third at each anniversary date over a three year service period. Under the graded-vesting approach, the Company recognizes compensation cost over the three year requisite service period for each separately vesting tranche as though the awards are, in substance, multiple awards. For awards that vest at the end of the three year service period, expense is recognized ratably using a straight-line expensing approach over three years. For all restricted stock awards, vesting is dependant upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or retirement.

The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is three years. In accordance with SFAS No. 123(R), the Company accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs for awards issued after the adoption of SFAS No. 123(R). The Company used an annual forfeiture rate ranging from 0% to 3.3% based on the Company’s ten year history for this type of award to various employee groups.

During the first quarter of 2007, there were 92,400 shares of restricted stock granted to employees with a grant date per share value of $35.22. These awards vest over a three year service period on a graded-vesting schedule. Compensation expense recorded for all unvested restricted stock awards for the first three months of 2007 and 2006 was $2.0 million and $2.4 million, respectively. Included in the 2007 and 2006 expense figures were $0.9 million and $0.5 million, respectively, related to the immediate expensing of shares granted to retirement-eligible employees.

Restricted Stock Units

Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are paid out when the director ceases to be a director of the Company.

During the first quarter of 2007, 24,654 restricted stock units were granted with a grant date per share value of $35.49. The compensation cost, which reflects the total fair value of these units, recorded in the first quarter of 2007 is $0.9 million. During the first three months of 2006, the Company did not have any expense related to restricted stock units.

Stock Options

Option awards are granted with an exercise price equal to the fair market price (defined as the average of the high and low trading prices of the Company’s stock at the date of grant) of the Company’s stock at the date of grant. The grant date fair value of a stock option is calculated by using a Black-Scholes model. Compensation cost is recorded based on a graded-vesting schedule as the options vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. Stock options have a maximum contractual term of five years. No forfeiture rate is assumed for stock options

granted to directors due to the forfeiture rate history for these types of awards for this group of individuals. During the first quarter of 2007, there were no stock options granted.

Compensation expense recorded during the first three months of 2007 and 2006 for amortization of stock options was $0.1 million for each period.

Stock Appreciation Rights

During the first quarter of 2007, the Compensation Committee granted 107,200 SARs to employees. These awards allow the employee to receive any intrinsic value over the $35.22 grant date fair market value that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. As these SARs are paid out in stock, rather than in cash, the Company calculates the fair value in the same manner as stock options, by using a Black-Scholes model.

The assumptions used in the Black-Scholes fair value calculation for SARs are as follows:


	Three Months Ended March 31, 2007
Weighted Average Value per Stock Appreciation Right
Granted During the Period⁽¹⁾	$	11.26
Assumptions
Stock Price Volatility		32.6	%
Risk Free Rate of Return		4.6	%
Expected Dividend		0.2	%
Expected Term (in years)		4.0

(1)

Calculated using the Black-Scholes fair value based method.

Compensation expense recorded during the first three months of 2007 and 2006 for SARs was $0.8 million and $0.1 million, respectively. Included in the 2007 amount was $0.5 million related to the immediate expensing of shares granted to retirement-eligible employees.

Performance Share Awards

During 2007, the Compensation Committee granted two types of performance share awards to employees for a total of 294,700 performance shares. The performance period for both of these awards commences January 1, 2007 and ends December 31, 2009. Certain of these awards, totaling 98,200 performance shares, are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year vesting performance period. The grant date per share value of the equity portion of this award was $30.72. Depending on the Company’s performance, employees may earn up to 100% of the award in common stock, and an additional 100% of the award in cash. In addition, 196,500 performance shares are earned, or not earned, based on the Company’s internal performance metrics rather than a peer group. The grant date per share value of the equity portion of this award was $35.22. These awards represent the right to receive up to 100% of the award in shares of common stock. The actual number of shares issued at the end of the performance period will be determined based on three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at March 31, 2007, it is currently considered probable that these three criteria will be met.

Both of these types of awards vest at the end of a designated three year performance period. For all awards granted to employees before and after January 1, 2006, an annual forfeiture rate ranging from 0% to 5.0% has been assumed based on the Company’s history for this type of award to various employee groups.

For awards that are based on the internal metrics (performance condition) of the Company and for awards that were granted prior to the adoption of SFAS No. 123(R) on January 1, 2006, fair value is measured based on the average of the high and low stock price of the Company on grant date and expense is amortized over the three year vesting period. To determine the fair value for awards that were granted after January 1, 2006 that are based on the Company’s comparative performance against a peer group (market condition), the equity and liability components are bifurcated. On the grant date, the equity component was valued using a Monte Carlo binomial model and is amortized on a straight-line basis over three years. The liability component is valued at each reporting period by using a Monte Carlo binomial model.

The three primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns and correlation in stock price movement. The risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for six-month, one, two and three year bonds and is set equal to the yield, for the period over the remaining duration of the performance period, on treasury securities as of the reporting date. Volatility was set equal to the annualized daily volatility measured over a historic four year period ending on the reporting date. A sample of correlation statistics were reviewed between the Company and its peers and the average ranged between 87% and 93%.

The following assumptions were used as of March 31, 2007 for the Monte Carlo model to value the liability component of the peer group measured performance share awards issued during the first quarter of 2007. The equity portion of the award has already been valued on the date of grant using the Monte Carlo model and this portion was not marked to market.


	As of March 31, 2007
Risk Free Rate of Return	4.6	%
Stock Price Volatility	32.9	%
Correlation in Stock Price Movement	90	%
Expected Dividend	0.2	%

The Monte Carlo value per share for the liability component for this performance share award was $13.95 at March 31, 2007. The liability component for all outstanding market condition performance share awards ranged from $13.95 to $30.86 at March 31, 2007. The long-term liability for all market condition performance share awards, included in Other Liabilities in the Condensed Consolidated Balance Sheet at March 31, 2007 and 2006 was $5.3 million and $1.1 million, respectively.

Total compensation cost recognized for both the equity and liability components of all performance share awards during the three months ended March 31, 2007 and 2006 was $2.8 million and $2.3 million, respectively.

12.

UNCERTAIN TAX POSITIONS

In June 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.” This Interpretation provides guidance for recognizing and measuring uncertain tax positions as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a two-step process for accounting for income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the benefit of the uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN No. 48 provides additional guidance on measuring the amount of the uncertain tax position. Under FIN No. 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Guidance is also provided regarding derecognition, classification, interest and penalties, interim period accounting, transition and increased disclosure of these uncertain tax position. FIN No. 48 is effective for fiscal years beginning after December 15, 2006.

The Company adopted the provisions of FIN No. 48 on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized no change to the liability for unrecognized tax benefits.

As of January 1, 2007, after the implementation of FIN No. 48, the Company’s unrecognized tax benefits are $1.0 million. This amount, if recognized, would not affect the effective tax rate.

The Company recognizes interest accrued related to uncertain tax positions in the Interest Expense and Other line and penalties accrued in the General and Administrative line in the Condensed Consolidated Statement of Operations, which is consistent with the recognition of these items in prior reporting periods. During the first quarter of 2007, the Company recorded a $0.1 million increase to interest expense. As of January 1, 2007, the Company had recorded a liability of approximately $0.9 million for interest. As of March 31, 2007, the Company determined that no accrual for penalties was appropriate.

As of January 1, 2007, it is reasonably possible that the 2001-2004 years currently pending before the IRS Appeals Division will be settled within the next twelve months. However, no increase or decrease to the total amount of unrecognized tax benefits can be anticipated. All issues pending before Appeals relate to the proper timing of deductions for tax purposes.

It is possible that the amount of unrecognized tax benefits will change in the next twelve months. The Company does not expect that a change would have a significant impact on the results of operations, financial position or cash flows.

The U.S. federal statute of limitations remains open for years 2001 and onward. State income tax returns are generally subject to examination for a period of three to four years after filing of the respective return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by state authorities in major jurisdictions include Texas and West Virginia (2001 onward). The Company is not currently under examination, nor has it been notified of an upcoming examination, by West Virginia. The Company is not currently under examination by Texas; however, it has been notified of an upcoming routine examination.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the Company) as of March 31, 2007, and the related condensed consolidated statements of operations and of cash flows for the three month periods ended March 31, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated balance sheet as of December 31, 2006 and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006; and in our report dated February 28, 2007, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

May 2, 2007

ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following review of operations for the three month periods ended March 31, 2007 and 2006 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Annual Report on Form 10-K for the year ended December 31, 2006.

Overview

Operating revenues decreased by $23.2 million, or 11%, from the three months ended March 31, 2006 compared to the three months ended March 31, 2007 due to decreased realized commodity prices as well as decreased equivalent production that results from the disposition of assets substantially completed in the third quarter of 2006. Natural gas revenues decreased by $8.4 million, or five percent, for the three months ended March 31, 2007 as compared to the three months ended March 31, 2006. The decrease is due to a 10% decrease in natural gas prices, partially offset by a five percent increase in natural gas production. Oil revenues decreased by $13.3 million, or 55%, for the first three months of 2007 as compared to the first three months of 2006. This decrease is primarily due to a decrease in crude oil production as a result of the third quarter 2006 disposition of assets as well as a decrease in crude oil realized prices in the first three months of 2007 as compared to the first three months of 2006. After removing $27.3 million and $15.4 million, respectively, of natural gas and crude oil revenues attributable to properties sold from the first quarter 2006 revenues, natural gas revenues for the quarter increased by 15% and crude oil revenues increased by 25%. Brokered natural gas revenues increased by $0.4 million due to an increase in brokered volumes, partially offset by a decrease in sales price.

Our realized natural gas price for the first quarter of 2007 was $7.42 per Mcf, 10% lower than the $8.22 per Mcf price realized in the same period of the prior year. Our realized crude oil price was $53.36 per Bbl, 13% lower than the $61.11 per Bbl price realized in the same period of the prior year. These realized prices are impacted by realized gains and losses resulting from commodity derivatives (costless collars). For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” section. Commodity prices are determined by factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, cannot accurately predict revenues.

On an equivalent basis, our production for the first three months of 2007 decreased by one percent from the first three months of 2006. For the three months ended March 31, 2007, we produced 21.0 Bcfe compared to production of 21.3 Bcfe for the comparable period of the prior year. Natural gas production was 19.8 Bcf and oil production was 205 Mbbls. Natural gas production increased by approximately five percent when compared to the comparable period of the prior year, which had production of 18.9 Bcf. This increase was primarily a result of increased production in the West region, associated with an increase in the drilling program, and to a lesser extent an increase in Canada due to increased pipeline capacity in Canada for the Hinton field. The Gulf Coast region experienced an overall decrease in natural gas production of 0.8 Bcf, or 11%. After removing 3.0 Bcf of first quarter 2006 natural gas production related to the properties sold in the third quarter of 2006, the Gulf Coast region experienced a 2.2 Bcf, or 52% increase in production, primarily as a result of increased drilling in the Minden and McCampbell fields. Natural gas production in the East region remained relatively flat quarter over quarter. Oil production decreased by 191 Mbbls from 396 Mbbls in the first three months of 2006 to 205 Mbbls produced in the first three months of 2007. This was primarily the result of a decrease of 182 Mbbls in the Gulf Coast region. After removing 250 Mbbls of first quarter 2006 crude oil production related to the properties sold in the third quarter of 2006, oil production increased by 84% due primarily to the increase in drilling and workover activity in the McCampbell field, and to a lesser extent, in the Minden field. Oil production remained relatively flat in the East region, decreased slightly in the West region and increased slightly in Canada.

We had net income of $48.5 million, or $0.50 per share, for the three months ended March 31, 2007 compared to net income of $53.2 million, or $0.55 per share, for the comparable period of the prior year. The decrease in net income is primarily due to decreased natural gas and oil production revenues, as discussed above. Partially offsetting this revenue decrease was a decrease in total operating expenses of $3.5 million in the first three months of 2007 as

compared to the first three months of 2006, primarily due to decreased exploration charges and taxes other than income, partially offset by increased general and administrative expenses and depreciation, depletion and amortization (DD&A). Because of reduced income before taxes due to the reasons discussed above, income taxes decreased by $5.2 million.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. In 2007, we expect to spend approximately $434 million in capital and exploration expenditures. Funding of the program will come from operating cash flow, existing cash and increased borrowings, if required. For the three months ended March 31, 2007, approximately $129.2 million of capital and exploration expenditures have been invested in our exploration and development efforts.

During the three months ended March 31, 2007, we drilled 100 gross wells (97 development, 2 exploratory and 1 extension wells) with a success rate of 99.0% compared to 71 gross wells (66 development, 4 exploratory and 1 extension wells) with a success rate of 97.2% for the comparable period of the prior year. As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006, for the full year of 2007, we plan to drill approximately 440 gross wells compared to 387 gross wells drilled in 2006.

We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results and selectively pursuing impact exploration opportunities as we accelerate drilling on our accumulated acreage position. In the current year we have allocated our planned program for capital and exploration expenditures among our various operating regions. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long term.

During the first quarter of 2007, we recorded a gain of $7.9 million related to the completion of our disposition of certain south Louisiana and offshore properties. During the second quarter of 2007, we expect to record an additional gain of approximately $4.4 million.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the three months ended March 31, 2007 were from funds generated from the sale of natural gas and crude oil production. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, as described in our Annual Report on Form 10-K for the year ended December 31, 2006, have also influenced prices throughout the recent years. Working capital is also substantially influenced by these variables. Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on sales. Cash flows provided by operating activities were primarily used to fund development, and to a lesser extent, exploratory expenditures, reduce borrowings on our revolving credit facility and to pay dividends. See below for additional discussion and analysis of cash flow.


	Three Months Ended March 31,
(In thousands)	2007			2006
Cash Flows Provided by Operating Activities	$	135,858		$	155,009
Cash Flows Used in Investing Activities		(113,616	)		(114,189	)
Cash Flows Used in Financing Activities		(6,654	)		(42,932	)

Net Increase / (Decrease) in Cash and Cash Equivalents	$	15,588		$	(2,112	)

Operating Activities. Net cash provided by operating activities in the first three months of 2007 decreased by $19.1 million over the comparable period in 2006. This decrease is primarily due to a decrease in working capital changes as well as a decrease in net income due to reduced commodity prices and, to a lesser extent, decreased equivalent production. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices for the first three months of 2007 decreased by 10% over the 2006 period, and crude oil realized prices decreased by 13% over the same period. Equivalent production volumes decreased by approximately one percent in the first three months of 2007 compared to the comparable period in 2006. While we believe 2007 actual commodity production may exceed 2006 levels, we are unable to predict future commodity prices, and as a result, cannot provide any assurance about future levels of net cash provided by operating activities.

Investing Activities. The primary uses of cash in investing activities are capital spending and exploration expense. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices, our capital expenditures budget may be periodically adjusted during any given year. Cash flows used in investing activities decreased by $0.6 million from the first three months of 2006 compared to the first three months of 2007. The decrease from 2006 to 2007 is due to proceeds from the sale of assets related to the disposition of certain south Louisiana and offshore properties as well as a decrease in exploration expense, partially offset by an increase in capital expenditures.

Financing Activities. Cash flows used in financing activities were $6.7 million for the first quarter of 2007, and were comprised of payments made to decrease outstanding debt under our revolving credit facility and to pay dividends. Partially offsetting these cash uses were inflows from the exercise of stock options and the tax benefit received from stock-based compensation. Cash flows used by financing activities were $42.9 million for the first quarter of 2006, primarily from payments made to reduce outstanding borrowings on our revolving credit facility by $45 million as well as dividend payments, partially offset by cash inflows from the exercise of stock options and the tax benefit received from stock-based compensation.

At March 31, 2007, we had no borrowings outstanding under our credit facility. The credit facility provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks’ petroleum engineer) and other assets. The revolving term of the credit facility ends in December 2009. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions.

In August 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure was adjusted to three million shares. In October 2006, we announced that our Board of Directors increased the number of shares of our common stock authorized for repurchase by an additional two million shares for a total of five million shares. As a result of the 2-for-1 stock split effected in March 2007, this figure was adjusted to 10 million shares. During the first quarter of 2007, we did not repurchase any shares of our common stock. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. The maximum number of shares that may yet be purchased under the plan as of March 31, 2007 was 4,795,300. See “Unregistered Sales of Equity Securities – Issuer Purchases of Equity Securities” in Item 2 of Part II of this quarterly report.

Capitalization

Information about our capitalization is as follows:


	March 31,			December 31,
(In millions)	2007			2006
Debt ⁽¹⁾	$	230.0		$	240.0
Stockholders’ Equity		965.9			945.2

Total Capitalization	$	1,195.9		$	1,185.2

Debt to Capitalization		19	%		20	%
Cash and Cash Equivalents	$	57.4		$	41.9

⁽¹⁾	Includes $20.0 million of current portion of long-term debt at both March 31, 2007 and December 31, 2006. Includes $10.0 million of borrowings outstanding under our revolving credit facility at December 31, 2006. No borrowings were outstanding under our revolving credit facility at March 31, 2007.

During the three months ended March 31, 2007, we paid dividends of $1.9 million on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990. After the March 2007 2-for-1 stock split, the dividend was increased to $0.03 per share per quarter, or a 50% increase from pre-split levels.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding significant oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.

The following table presents major components of capital and exploration expenditures for the three months ended March 31, 2007 and 2006:


	Three Months Ended March 31,
(In millions)	2007		2006
Capital Expenditures
Drilling and Facilities	$	115.0	$	89.2
Leasehold Acquisitions		4.4		14.7
Pipeline and Gathering		3.7		3.1
Other		0.4		0.7

		123.5		107.7
Proved Property Acquisitions		—		0.2
Exploration Expense		5.7		11.6

Total	$	129.2	$	119.5

We plan to drill approximately 440 gross wells in 2007. This drilling program includes approximately $434 million in total capital and exploration expenditures. See the “Overview” discussion for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment and may increase or decrease the capital and exploration expenditures accordingly.

Contractual Obligations

During the three months ended March 31, 2007, certain events have occurred changing the amounts previously reported in our contractual obligations table for drilling rig commitments and firm gas transportation agreements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Our firm gas transportation agreements provide firm transportation capacity rights on pipeline systems in Canada, the West region and the East region. The amount of transportation demand charges under these agreements that we are estimated to pay, regardless of the amount of pipeline capacity we utilize, has decreased by approximately $2.4 million from the total $85.1 million figure previously disclosed. This is due to released volumes on one contract in the West region.

Drilling rig commitments increased by $0.7 million from the $120.3 million figure reported in our Annual Report on Form 10-K for the year ended December 31, 2006. This increase was due to an increase in the daily rig rates on two rigs as a result of an increase of 5% in the U.S. Department of Labor Wholesale Price Index for Oilfield Machinery and Tools from the base index, as required in the commitment agreement.

For further information, please refer to “Firm Gas Transportation Agreements” and “Rig Commitments” under Note 6 in the Notes to the Condensed Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted and adopted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Annual Report on Form 10-K for the year ended December 31, 2006, for further discussion of our critical accounting policies.

Effective January 1, 2007, we adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” Due to this adoption, we recorded a charge of less than $0.1 million in the first quarter of 2007 for incremental interest expense that is more likely than not payable. This adoption did not have a material impact on any of our financial statements.

Results of Operations

First Quarters of 2007 and 2006 Compared

We reported net income in the first quarter of 2007 of $48.5 million, or $0.50 per share. During the corresponding quarter of 2006, we reported net income of $53.2 million, or $0.55 per share. Net income decreased in the first quarter by $4.7 million, primarily due to a decrease in operating income of $12.0 million from $91.2 million in the first quarter of 2006 to $79.2 million in the first quarter of 2007. This decrease in net income was primarily due a decrease in natural gas and crude oil production revenues, partially offset by a decrease of $5.2 million in income tax expense and a decrease in operating expenses of $3.5 million, primarily as a result of reduced exploration expense, partially offset by general and administrative and other operating expense increases.

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $7.42 per Mcf for the three months ended March 31, 2007 compared to $8.22 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instrument settlements which increased the price by $0.89 per Mcf in 2007 and $0.08 per Mcf in 2006. There was no unrealized impact from the change in derivative fair value for the three months ended March 31, 2007 or 2006.


	Three Months Ended March 31,					Variance
	2007			2006		Amount			Percent
Natural Gas Production (Mmcf)
East		5,757			5,765		(8	)	0	%
Gulf Coast		6,479			7,248		(769	)	(11	%)
West		6,458			5,390		1,068		20	%
Canada		1,072			477		595		125	%

Total Company		19,766			18,880		886		5	%

Natural Gas Production Sales Price ($/Mcf)
East	$	8.08		$	9.31	$	(1.23	)	(13	%)
Gulf Coast	$	7.75		$	8.21	$	(0.46	)	(6	%)
West	$	6.51		$	7.08	$	(0.57	)	(8	%)
Canada	$	7.46		$	8.12	$	(0.66	)	(8	%)
Total Company	$	7.42		$	8.22	$	(0.80	)	(10	%)
Natural Gas Production Revenue (In thousands)
East	$	46,498		$	53,666	$	(7,168	)	(13	%)
Gulf Coast		50,240			59,475		(9,235	)	(16	%)
West		42,020			38,157		3,863		10	%
Canada		7,992			3,869		4,123		107	%

Total Company	$	146,750		$	155,167	$	(8,417	)	(5	%)

Price Variance Impact on Natural Gas Production Revenue
(In thousands)
East	$	(7,097	)
Gulf Coast		(2,957	)
West		(3,699	)
Canada		(706	)

Total Company	$	(14,459	)

Volume Variance Impact on Natural Gas Production Revenue
(In thousands)
East	$	(71	)
Gulf Coast		(6,278	)
West		7,562
Canada		4,829

Total Company	$	6,042

The decrease in Natural Gas Production Revenue is primarily due to the decrease in realized natural gas sales prices, partially offset by an increase in natural gas production. Prices were lower in all regions quarter over quarter for the Company. The decrease in the realized natural gas price and increase in production resulted in a net revenue decrease of $8.4 million. After removing $27.3 million of natural gas revenues and 2,986 Mmcf of natural gas production associated with properties in the Gulf Coast region sold in third quarter of 2006 divestiture from 2006 results, total natural gas revenue would have increased by $18.9 million, or 15%, and natural gas production would have increased by 3,872 Mmcf, or 24%, from the first quarter of 2006 to the first quarter of 2007.

Brokered Natural Gas Revenue and Cost


	Three Months Ended March 31,					Variance
	2007			2006		Amount			Percent
Sales Price ($/Mcf)	$	8.96		$	9.20	$	(0.24	)	(3	%)
Volume Brokered (Mmcf)		3,703			3,566		137		4	%

Brokered Natural Gas Revenues (In thousands)	$	33,177		$	32,819

Purchase Price ($/Mcf)	$	7.75		$	8.20	$	(0.45	)	(5	%)
Volume Brokered (Mmcf)		3,703			3,566		137		4	%

Brokered Natural Gas Cost (In thousands)	$	28,699		$	29,245

Brokered Natural Gas Margin (In thousands)	$	4,478		$	3,574	$	904		25	%

(In thousands)
Sales Price Variance Impact on Revenue	$	(899	)
Volume Variance Impact on Revenue		1,260

	$	361

(In thousands)
Purchase Price Variance Impact on Purchases	$	1,666
Volume Variance Impact on Purchases		(1,123	)

	$	543

The increased brokered natural gas margin of $0.9 million is driven by a decrease in purchase price that outpaced the decrease in sales price in addition to an increase in the volumes brokered in the first quarter of 2007 over the same period in the prior year.

Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price was $53.36 per Bbl for the first quarter of 2007. The 2007 price includes the realized impact of derivative instrument settlements which increased the price by $0.89 per Bbl. Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $61.11 per Bbl for the first quarter of 2006. There was no realized impact of derivative instruments in the first quarter of 2006. There was no unrealized impact from the change in derivative fair value for the either first quarter of 2007 or 2006.


	Three Months Ended March 31,					Variance
	2007			2006		Amount			Percent
Crude Oil Production (Mbbl)
East		6			7		(1	)	(14	%)
Gulf Coast		148			331		(183	)	(55	%)
West		45			54		(9	)	(17	%)
Canada		6			4		2		50	%

Total Company		205			396		(191	)	(48	%)

Crude Oil Sales Price ($/Bbl)
East	$	53.49		$	59.15	$	(5.66	)	(10	%)
Gulf Coast	$	53.07		$	61.36	$	(8.29	)	(14	%)
West	$	54.17		$	60.64	$	(6.47	)	(11	%)
Canada	$	54.44		$	48.67	$	5.77		12	%
Total Company	$	53.36		$	61.11	$	(7.75	)	(13	%)
Crude Oil Revenue (In thousands)
East	$	324		$	412	$	(88	)	(21	%)
Gulf Coast		7,872			20,284		(12,412	)	(61	%)
West		2,434			3,303		(869	)	(26	%)
Canada		312			181		131		72	%

Total Company	$	10,942		$	24,180	$	(13,238	)	(55	%)

Price Variance Impact on Crude Oil Revenue
(In thousands)
East	$	(34	)
Gulf Coast		(1,230	)
West		(291	)
Canada		33

Total Company	$	(1,522	)

Volume Variance Impact on Crude Oil Revenue
(In thousands)
East	$	(54	)
Gulf Coast		(11,182	)
West		(578	)
Canada		98

Total Company	$	(11,716	)

The decrease in the realized crude oil price combined with the decline in production resulted in a net revenue decrease of $13.3 million. The decrease in oil production is mainly the result of the sale in the third quarter of 2006 of certain south Louisiana and offshore properties in the Gulf Coast region. After removing $15.4 million of crude oil revenues and 250 Mbbls of crude oil production associated with properties in the Gulf Coast region sold in third quarter of 2006 divestiture from 2006 results, total crude oil revenue would have increased by $2.2 million, or 25%, and crude oil production would have increased by 59 Mbbls, or 40%, from the first quarter of 2006 to the first quarter of 2007.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:


	Three Months Ended March 31,
	2007				2006
*(In thousands)*	Realized		Unrealized		Realized		Unrealized
Operating Revenues - Increase to Revenue
Cash Flow Hedges
Natural Gas Production	$	17,593	$	—	$	1,437	$	—
Crude Oil		182		—		—		—

Total Cash Flow Hedges	$	17,775	$	—	$	1,437	$	—

We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity.

Other Operating Revenues

Other operating revenues decreased by $1.9 million between the first quarter of 2007 and the first quarter of 2006 primarily due to an increase in our payout liability, which correspondingly decreased other revenues.

Operating Expenses

Total costs and expenses from operations decreased $3.5 million in the first quarter of 2007 compared to the same period of 2006. The primary reasons for this fluctuation are as follows:

•

Exploration expense decreased by $5.9 million in the first quarter of 2007, primarily as a result of a decrease in total dry hole expense of $3.2 million and a decrease in geophysical and geological expenses of $2.4 million, primarily in Canada and the Gulf Coast region

•

General and Administrative expense increased by $4.0 million in the first quarter of 2007 primarily due to increased stock compensation charges of $1.7 million resulting from new stock awards issued during the first quarter of 2007, increased performance share expense as a result of a favorable company ranking against its peers and the associated increase in the liability related to the cash portion of the awards, and increased SAR expense for retirement eligible employees which are expensed immediately upon grant. Additionally, expense for litigation accruals increased by $0.5 million.

•

Taxes Other Than Income decreased by $2.4 million in the first three months of 2007 compared to the first three months of 2006, primarily due to decreased production taxes of $1.1 million as a result of decreased natural gas and crude oil prices as well as a decrease of $1.1 million in ad valorem taxes.

•

Depreciation, Depletion and Amortization increased by $1.5 million in the first quarter of 2007. This is primarily due to negative reserve revisions due to lower prices at year-end, higher capital costs and commencement of production in an East Texas field.

Interest Expense, Net

Interest expense, net decreased by $2.2 million in the first quarter of 2007 due to lower credit facility borrowings, lower borrowings on our 7.19% fixed rate debt and increased interest on our short term investments. Weighted average borrowings on our credit facility based on daily balances were approximately $3 million during the first quarter of 2007 compared to approximately $70 million during the first quarter of 2006.

Income Tax Expense

Income tax expense decreased by $5.2 million due to a comparable decrease in our pre-tax income, primarily as a result of the decrease in revenues. The effective tax rate for the first quarter of 2007 and 2006 was 35.5% and 37.5%, respectively. The decrease in the effective tax rate is primarily due to the recognition of a change in the Texas state income tax rate due to a change in the tax law in May 2006. In addition, there was a reduction in the overall blended state income tax rate due to the sale of certain south Louisiana and offshore properties and an increase in the qualified production activities deduction rate from three percent to six percent.

Recently Issued Accounting Pronouncements

In February 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” which permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The objective of this Statement is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of the Statement apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. Additional disclosures are also required for instruments for which the fair value option is elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. We are currently evaluating what impact SFAS No. 159, if adopted, may have on our financial position, results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by United States. generally accepted accounting principles (GAAP) to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement (CON) No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. No new fair value measurements are prescribed, and SFAS No. 157 is intended to codify the several definitions of fair value included in various accounting standards. However, the application of this Statement may change current practices for certain companies. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating what impact SFAS No. 157 may have on our financial position, results of operations.

Forward-Looking Information

The statements regarding future financial performance and results, market prices and the other statements which are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

ITEM 3.

Quantitative and Qualitative Disclosures about Market Risk

Derivative Instruments and Hedging Activity

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below and Note 7 of the Notes to the Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

Hedges on Production – Options

From time to time, we enter into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. During the first three months of 2007, natural gas price collars covered 10,487 Mmcf, or 53%, of our first quarter 2007 gas production, with a weighted average floor of $8.99 per Mcf and a weighted average ceiling of $12.19 per Mcf.

At March 31, 2007, we had open natural gas price collar contracts covering a portion of our 2007 and 2008 production as follows:


	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling / Floor *(per Mcf)*		Net Unrealized Gain / (Loss) *(In thousands)*
As of March 31, 2007
Second Quarter 2007	10,604	$	12.19 / $8.99
Third Quarter 2007	10,721		12.19 / 8.99
Fourth Quarter 2007	10,721		12.19 / 8.99

Nine Months Ended December 31, 2007	32,046	$	12.19 / $8.99	$	30,032

First Quarter 2008	1,637	$	11.15 / $8.62
Second Quarter 2008	1,637		11.15 / 8.62
Third Quarter 2008	1,655		11.15 / 8.62
Fourth Quarter 2008	1,655		11.15 / 8.62

Full Year 2008	6,584	$	11.15 / $8.62	$	(650	)

During the first three months of 2007, a crude oil price collar covered 90 Mbbls, or 44%, of our first quarter 2007 oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.

At March 31, 2007, we had one open crude oil price collar contract covering a portion of our 2007 production as follows:


	Crude Oil Price Collar
Contract Period	Volume in Mbbl	Ceiling / Floor *(per Bbl)*		Net Unrealized Gain *(In thousands)*
As of March 31, 2007
Second Quarter 2007	91	$	80.00 / $60.00
Third Quarter 2007	92		80.00 / 60.00
Fourth Quarter 2007	92		80.00 / 60.00

Nine Months Ended December 31, 2007	275	$	80.00 / $60.00	$	35

We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.

ITEM 4.

Controls and Procedures

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

Legal Proceedings

The information set forth under the caption “West Virginia Royalty Litigation” in Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q is incorporated by reference in response to this item.

ITEM 1A.

Risk Factors

For additional information about the risk factors facing the Company, see Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

In August 1998, the Company announced that its Board of Directors authorized the repurchase of two million shares of its common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure was adjusted to three million shares. In October 2006, the Company announced that its Board of Directors increased the number of shares of our common stock authorized for repurchase by an additional two million shares for a total of five million shares. As a result of the 2-for-1 stock split effected in March 2007, this figure was adjusted to 10 million shares. During the first quarter of 2007, the Company did not repurchase any shares of its common stock. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase these securities. The maximum number of shares that may yet be purchased under the plan as of March 31, 2007 was 4,795,300.

ITEM 6.

Exhibits


4.2		By-laws as amended and restated May 2, 2007

4.3		Rights Agreement dated as of March 28, 1991 between the Company and The First National Bank of Boston, as Rights Agent, as amended and restated as of December 8, 2000, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-K for December 21, 2000).

		(a) Amendment to Rights Agreement dated as of January 1, 2003 (The Bank of New York as rights agent).

		(b) Amendment to Rights Agreement dated as of March 30, 2007(regarding uncertified shares).

10.24		Amendment to the Cabot Oil & Gas Corporation 2004 Incentive Plan

15.1		Awareness letter of PricewaterhouseCoopers LLP

31.1		302 Certification - Chairman, President and Chief Executive Officer

31.2		302 Certification - Vice President and Chief Financial Officer

32.1		906 Certification

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	CABOT OIL & GAS CORPORATION
	(Registrant)

May 2, 2007	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

May 2, 2007	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

May 2, 2007	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)

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