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, 2006

¨	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, 2006, there were 48,844,732 shares of Common Stock, Par Value $.10 Per Share, outstanding.

CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS


		Page
Part I. Financial Information

Item 1.	Financial Statements

Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2006 and 2005		3

Condensed Consolidated Balance Sheet at March 31, 2006 and December 31, 2005		4

Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2006 and 2005		5

Notes to the Condensed Consolidated Financial Statements		6

Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information		21

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32

Item 4.	Controls and Procedures	33

Part II. Other Information

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 6.	Exhibits	34

Signatures		35

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)*	2006			2005
OPERATING REVENUES
Natural Gas Production	$	155,167		$	104,272
Brokered Natural Gas		32,819			26,492
Crude Oil and Condensate		24,180			11,978
Other		2,602			1,332

		214,768			144,074

OPERATING EXPENSES
Brokered Natural Gas Cost		29,245			23,298
Direct Operations - Field and Pipeline		17,630			14,618
Exploration		11,614			19,369
Depreciation, Depletion and Amortization		31,935			26,656
Impairment of Unproved Properties		3,580			3,411
General and Administrative		13,849			8,960
Taxes Other Than Income		15,495			9,718

		123,348			106,030
Gain on Sale of Assets		207			—

INCOME FROM OPERATIONS		91,627			38,044
Interest Expense and Other		6,150			4,988

Income Before Income Taxes		85,477			33,056
Income Tax Expense		31,909			12,294

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		53,568			20,762
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX (Note 11)		(403	)		—

NET INCOME	$	53,165		$	20,762

Basic Earnings Per Share - Before Accounting Change	$	1.10		$	0.43
Diluted Earnings Per Share - Before Accounting Change	$	1.09		$	0.42
Basic Loss Per Share - Accounting Change	$	(0.01	)	$	—
Diluted Loss Per Share - Accounting Change	$	(0.01	)	$	—
Basic Earnings Per Share	$	1.09		$	0.43
Diluted Earnings Per Share	$	1.08		$	0.42

Weighted Average Common Shares Outstanding		48,680			48,724
Diluted Common Shares (Note 5)		49,373			49,306

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

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)


*(In thousands, except share amounts)*	March 31, 2006			December 31, 2005
ASSETS
Current Assets
Cash and Cash Equivalents	$	8,514		$	10,626
Accounts Receivable		114,268			168,248
Inventories		13,786			24,616
Deferred Income Taxes		7,734			15,674
Derivative Contracts		11,552			1,736
Other		8,499			9,412

Total Current Assets		164,353			230,312
Properties and Equipment, Net (Successful Efforts Method)		1,310,680			1,238,055
Deferred Income Taxes		23,843			19,587
Other Assets		7,755			7,416

	$	1,506,631		$	1,495,370

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	115,327		$	140,006
Current Portion of Long-Term Debt		20,000			20,000
Deferred Income Taxes		4,605			941
Derivative Contracts		2,079			22,478
Accrued Liabilities		36,796			35,159

Total Current Liabilities		178,807			218,584
Long-Term Debt		275,000			320,000
Deferred Income Taxes		306,125			289,381
Other Liabilities		70,962			67,194
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common Stock:
Authorized — 80,000,000 Shares of $.10 Par Value Issued — 50,308,632 Shares and 50,081,983 Shares in 2006 and 2005, respectively		5,031			5,008
Additional Paid-in Capital		402,959			397,349
Retained Earnings		303,386			252,167
Accumulated Other Comprehensive Income / (Loss)		3,559			(15,115	)
Less Treasury Stock, at Cost:
1,513,850 Shares in 2006 and 2005		(39,198	)		(39,198	)

Total Stockholders’ Equity		675,737			600,211

	$	1,506,631		$	1,495,370

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)*	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	53,165		$	20,762
Adjustments to Reconcile Net Income to Cash
Provided by Operating Activities:
Cumulative Effect of Accounting Change		403			—
Depreciation, Depletion and Amortization		31,935			26,656
Impairment of Unproved Properties		3,580			3,411
Deferred Income Tax Expense		12,893			3,022
Gain on Sale of Assets		(207	)		—
Exploration Expense		11,614			19,369
Unrealized Loss on Derivatives		—			7,512
Stock-Based Compensation Expense and Other		4,467			1,923
Changes in Assets and Liabilities:
Accounts Receivable		53,980			27,089
Inventories		10,830			10,957
Other Current Assets		913			102
Other Assets		(79	)		(12	)
Accounts Payable and Accrued Liabilities		(27,663	)		(13,956	)
Other Liabilities		2,130			1,182
Stock-Based Compensation Tax Benefit		(2,952	)		—

Net Cash Provided by Operating Activities		155,009			108,017

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(103,116	)		(41,070	)
Proceeds from Sale of Assets		541			588
Exploration Expense		(11,614	)		(19,369	)

Net Cash Used by Investing Activities		(114,189	)		(59,851	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		55,000			—
Decrease in Debt		(100,000	)		—
Sale of Common Stock Proceeds		1,062			2,731
Stock-Based Compensation Tax Benefit		2,952			—
Dividends Paid		(1,946	)		(1,339	)

Net Cash (Used) / Provided by Financing Activities		(42,932	)		1,392

Net (Decrease) / Increase in Cash and Cash Equivalents		(2,112	)		49,558
Cash and Cash Equivalents, Beginning of Period		10,626			10,026

Cash and Cash Equivalents, End of Period	$	8,514		$	59,584

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, 2005 filed with the Securities and Exchange Commission. People using financial information produced for interim periods are encouraged to refer to the footnotes in the Annual Report on Form 10-K for the year ended December 31, 2005 when reviewing interim financial results. 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. The results of operations for any interim period are not necessarily indicative of the results of operations 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.

Effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 123(R), “Share Based Payment (revised 2004),” which replaces the provisions of Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees” and SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended. The Company has elected the modified prospective transition method for adoption, and accordingly, no adjustments to prior period financial statements have been made. Upon adoption, the Company recorded a cumulative effect of change in accounting principle totaling $0.4 million, net of tax, in the 2006 Condensed Consolidated Statement of Operations. Further, the impact of adoption of SFAS No. 123(R) increased income from operations and income before income taxes by approximately $0.6 million and increased net income by $0.4 million for the three months ended March 31, 2006 and there was no material impact on the Condensed Consolidated Statement of Cash Flows. See Note 11 of the Notes to the Condensed Consolidated Financial Statements for additional disclosure.

Recently Issued Accounting Pronouncements

In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for in a similar fashion, regardless of the instrument’s form. The Company does not believe that its financial position, results of operations or cash flows will be impacted by SFAS No. 155 as the Company does not currently hold any hybrid financial instruments.

2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:


*(In thousands)*	March 31, 2006			December 31, 2005
Unproved Oil and Gas Properties	$	119,324		$	107,787
Proved Oil and Gas Properties		2,060,741			1,970,407
Gathering and Pipeline Systems		182,366			178,876
Land, Building and Improvements		4,914			4,892
Other		33,447			33,077

		2,400,792			2,295,039
Accumulated Depreciation, Depletion and Amortization		(1,090,112	)		(1,056,984	)

	$	1,310,680		$	1,238,055

As of March 31, 2006, the Company did not have any significant changes from year-end in its amount of capitalized well costs that have been capitalized for greater than one year after drilling was suspended.

3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:


*(In thousands)*	March 31, 2006			December 31, 2005
Accounts Receivable
Trade Accounts	$	101,397		$	147,016
Joint Interest Accounts		16,857			14,319
Current Income Tax Receivable		389			12,239
Other Accounts		1,585			315

		120,228			173,889
Allowance for Doubtful Accounts		(5,960	)		(5,641	)

	$	114,268		$	168,248

Inventories
Natural Gas and Oil in Storage	$	5,559		$	18,279
Tubular Goods and Well Equipment		7,856			7,161
Pipeline Imbalances		371			(824	)

	$	13,786		$	24,616

Other Current Assets
Drilling Advances	$	1,441		$	2,169
Prepaid Balances		6,754			6,939
Other Accounts		304			304

	$	8,499		$	9,412

Accounts Payable
Trade Accounts	$	14,585		$	18,227
Natural Gas Purchases		8,217			12,208
Royalty and Other Owners		33,510			49,312
Capital Costs		42,758			37,489
Taxes Other Than Income		7,148			10,329
Drilling Advances		4,009			5,760
Wellhead Gas Imbalances		2,160			2,175
Other Accounts		2,940			4,506

	$	115,327		$	140,006

Accrued Liabilities
Employee Benefits	$	4,943		$	9,020
Taxes Other Than Income		21,508			16,188
Interest Payable		4,748			6,818
Income Taxes Payable		3,551			41
Other Accounts		2,046			3,092

	$	36,796		$	35,159

Other Liabilities
Postretirement Benefits Other Than Pension	$	7,305		$	6,517
Accrued Pension Cost		6,916			5,904
Rabbi Trust Deferred Compensation Plan		5,072			4,883
Accrued Plugging and Abandonment Liability		43,587			42,991
Other Accounts		8,082			6,899

	$	70,962		$	67,194

4. LONG-TERM DEBT

At March 31, 2006, the Company had $45 million of debt outstanding 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 to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or pay down one-sixth of the excess during each of the six months.

In addition to the $45 million of debt outstanding on the credit facility, the Company has the following debt outstanding at March 31, 2006:

•

$80 million of 12-year 7.19% Notes, which consisted of $60 million of long-term debt and $20 million of current portion of long-term debt, to be repaid in four 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

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 outstanding 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, 2006 and 2005.


	Three Months Ended March 31,
	2006	2005
Shares - basic	48,679,911	48,724,241
Dilution effect of stock options and awards at end of period	693,479	581,543

Shares - diluted	49,373,390	49,305,784

Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	—	—

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 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 it had taken improper deductions from the royalty and 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 will result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and that will limit the claims to those arising on and after December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of a case pending before the West Virginia Supreme Court of Appeals which may decide issues of law that may apply to the issue of deductibility of post-production expenses. The Company intends to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.

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.

Texas Title Litigation

On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs filed their Third Amended Original Petition on February 21, 2006, which incorporated all prior supplemental petitions. Plaintiffs allege that they are the owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. Cody Energy, LLC, a subsidiary of the Company, acquired certain leases and wells in 1997 and 1998.

The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass and conversion, all for unspecified actual and exemplary damages. Plaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a claim of fraudulent concealment to avoid the affirmative defense of limitations. In August 2005, the case was abated until late February 2006, during which time the parties were allowed to amend pleadings or add additional parties to the litigation. Plaintiffs did not join additional parties by the abatement deadline. Defendants, including the Company, re-urged its motion to dismiss, and on April 5, 2006, the

Court granted the motion, dismissing the oil company defendants, without prejudice. Because all defendants were not dismissed, the order dismissing the Company is not yet final and can be appealed. A motion to finalize the proceedings in the trial court via severance of the dismissed defendants was filed April 25, 2006. Once final judgment is entered in the trial court, it is anticipated that the Plaintiffs will appeal the dismissal order.

On April 25, 2006, the same day that the oil company defendants, including the Company, filed the motion for severance, Plaintiffs filed a motion to modify the dismissal order. Plaintiffs allege that the dismissal order should not operate to dismiss any defendant that ever had or now has an oil and gas lease with the remaining defendants. It appears that the Company may have at one time had a lease from such defendants under which wells were drilled and produced for a period of time. Therefore, if the Court grants the motion to modify the dismissal order, there is a possibility that the Company would remain in the suit with respect to that lease only. The Company is researching the total production volume from that lease.

The Company estimates that production revenue from this field since Cody Energy, LLC acquired title is approximately $16.1 million, and that the carrying value of this property is approximately $33.5 million.

If the Company is not fully dismissed and receives an adverse ruling in this case, an impairment review would be assessed to determine whether the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

Raymondville Area

In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of its co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody had proposed a new prospect under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

The working interest owners who elected not to participate notified Cody that they believed that they had the right to participate in wells drilled after the initial well. Cody contends that the working interest owners that elected not to participate are required to assign their interest in the prospect to those who elected to participate. The defendants have filed a counter claim against the Company, and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville area.

Cody has signed a settlement agreement with certain of the defendants representing approximately 3% of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. In August 2005, the trial judge entered an order granting Cody’s Motion for Summary Judgment requiring the remaining defendant to assign to Cody all of its interest in the prospect and to remove the lien filed against Cody’s interest. The defendant has filed a Motion for Reconsideration and Opposition to Proposed Order. The Court, on March 24, 2006, denied the Motion. A decision has not been made on the counter claims.

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 $11.0 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 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.

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, 2006, the Company had 12 cash flow hedges open: 11 natural gas price collar arrangements and one crude oil collar arrangement. At March 31, 2006, a $9.7 million ($6.0 million net of tax) unrealized gain was recorded to Accumulated Other Comprehensive Income, along with a $2.1 million short-term derivative liability, an $11.6 million short-term derivative receivable, and a $0.2 million long-term derivative receivable, which is shown in 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.

Assuming no change in commodity prices, after March 31, 2006 the Company would expect to reclassify to the Statement of Operations, over the next 12 months, $5.9 million in after-tax charges associated with commodity hedges. This reclassification represents the net short-term receivable associated with open positions currently not reflected in earnings at March 31, 2006 related to anticipated 2006 and a portion of anticipated 2007 production.

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, 2006 and 2005.


	Three Months Ended March 31,
*(In thousands)*	2006						2005
Accumulated Other Comprehensive Loss -
Beginning of Period				$	(15,115	)				$	(20,351	)
Net Income	$	53,165					$	20,762

Other Comprehensive Income / (Loss)
Reclassification Adjustment for Settled Contracts		(1,437	)					6,180
Changes in Fair Value of Hedge Positions		31,910						(36,791	)
Minimum Pension Liability		—						2,081
Foreign Currency Translation Adjustment		(355	)					(49	)
Deferred Income Tax		(11,444	)					10,783

Total Other Comprehensive Income / (Loss)		18,674			18,674			(17,796	)		(17,796	)

Comprehensive Income	$	71,839					$	2,966

Accumulated Other Comprehensive Income / (Loss) -
End of Period				$	3,559					$	(38,147	)

Deferred income tax of $11.4 million for the three months ended March 31, 2006 represents the net deferred tax liability of $0.6 million on the Reclassification Adjustment for Settled Contracts, ($12.1) million on the Changes in Fair Value of Hedge Positions and $0.1 million on the Foreign Currency Translation Adjustment.

Deferred income tax of $10.8 million for the three months ended March 31, 2005 represents the net deferred tax liability of ($2.4) million on the Reclassification Adjustment for Settled Contracts, $14.0 million on the Changes in Fair Value of Hedge Positions, ($0.8) million on the Minimum Pension Liability Adjustment and less than $0.1 million on the Foreign Currency Translation Adjustment.

9. ASSET RETIREMENT OBLIGATIONS

The following table reflects the changes of the asset retirement obligations during the three months ended March 31, 2006.


*(In thousands)*
Carrying amount of asset retirement obligations at December 31, 2005	$	42,991
Liabilities added during the current period		248
Liabilities settled during the current period		—
Current period accretion expense		348

Carrying amount of asset retirement obligations at March 31, 2006	$	43,587

Accretion expense was $0.3 million and $0.4 million for the three months ended March 31, 2006 and 2005, respectively, 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, 2006 and 2005 are as follows:


	For the Three Months Ended March 31,
*(In thousands)*	2006			2005
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	680		$	545
Interest Cost		583			471
Expected Return on Plan Assets		(476	)		(356	)
Amortization of Prior Service Cost		44			41
Amortization of Net Loss		303			187

Net Periodic Benefit Cost	$	1,134		$	888

Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	197		$	169
Interest Cost		219			151
Plan Termination (Gain) / Loss		(85	)		80
Recognized Net Actuarial Loss / (Gain)		8			(20	)
Amortization of Prior Service Cost		238			227
Amortization of Net Obligation at Transition		158			162

Total Postretirement Benefit Cost	$	735		$	769

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, 2005 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 2006. It is anticipated that these

contributions will be made prior to December 31, 2006. The Company does not have any required minimum funding obligations for its qualified pension plan in 2006. Management has not determined if any discretionary funding will be made to the qualified pension plan during the last three quarters of 2006.

11. STOCK-BASED COMPENSATION

Incentive Plans

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 addition to the automatic award of an option to purchase 15,000 shares of common stock on the date the non-employee directors first join the board of directors. A total of 2,550,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 900,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 1,500,000 shares may be issued pursuant to incentive stock options.

Adoption of SFAS No. 123(R)

Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by APB No. 25. Under the intrinsic value based method, no compensation expense was recorded for stock options granted when the exercise price for options granted was equal to or greater than the fair value of the Company’s common stock on the date of the grant.

Beginning January 1, 2006, the Company began accounting for stock-based compensation under SFAS No. 123(R), which applies to new awards and to awards modified, repurchased or cancelled after December 31, 2005. The Company records compensation expense based on the fair value of awards as described below. Additionally, compensation expense for the portion of the awards for which the requisite service period has not been rendered that are outstanding at December 31, 2005 is recognized as the requisite service is rendered on or after January 1, 2006.

Compensation expense that has been charged against income for stock-based awards in the first quarter of 2006 and 2005 is $4.5 million and $1.0 million, pre-tax, respectively, and is included in the General and Administrative Expense line of the Condensed Consolidated Statement of Operations. In the first quarter of 2006, compensation expense includes fair value amortization on restricted stock grants, stock options, SARs and performance shares. Compensation expense in the first quarter of 2005 only includes amortization on restricted stock grants and expense related to performance shares.

Prior to the adoption of SFAS No. 123(R), the Company presented tax savings resulting from tax deductions related to stock-based compensation as an operating cash flow. Under SFAS No. 123(R), the tax savings resulting from tax deductions in excess of expense is reported as an operating cash outflow and a financing cash inflow. For the first quarter of 2006, $3.0 million is reported in these two separate line items in the Condensed Consolidated Statement of Cash Flows.

The cumulative effect of adoption was due primarily to the recording of the liability component of the Company’s performance share awards at fair value, rather than intrinsic value.

The following table illustrates the effect on Net Income and Earnings per Share if the Company had applied the fair value recognition provisions of SFAS No. 123(R) to stock-based employee compensation during the three months ended March 31, 2005:


*(In thousands, except per share amounts)*
Net Income, as reported	$	20,762
Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported		640
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax, previously not included in Net Income		(932	)

Pro forma Net Income	$	20,470

Earnings per Share:
Basic - as reported	$	0.43
Basic - pro forma	$	0.42
Diluted - as reported	$	0.42
Diluted - pro forma	$	0.42

Share Count		48,724
Diluted Share Count		49,306

Restricted Stock Awards

Restricted stock awards vest either at the end of a three year service period, or on a graded-vesting basis for awards that vest 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.

The fair value of restricted stock grants is based on the average of the high and low stock price on grant date. The maximum contractual term is three years. In accordance with SFAS No. 123(R), the Company accelerates 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.

There were 46,850 restricted stock awards granted to employees in the first quarter of 2006. These awards will vest over a three year service period on a graded-vesting schedule. Compensation expense recorded for restricted stock awards for the first quarter of 2006 and 2005 is $2.4 million and $0.6 million, respectively. Included in the 2006 expense is $0.5 million related to the immediate expensing of shares granted to retirement-eligible employees. Unamortized expense as of March 31, 2006 for all outstanding restricted stock awards is $8.2 million.

The following table is a summary of activity of restricted stock awards as of March 31, 2006:


Restricted Stock Awards	Shares	Weighted- Average Grant Date Fair Value per share		Weighted- Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Non-vested shares outstanding at December 31, 2005	588,465	$	26.68
Granted	46,850		47.60
Vested	197,221		20.27
Forfeited	200		30.43

Non-vested shares outstanding at March 31, 2006	437,894	$	31.80	0.9	$	20,988

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.

No restricted stock units were issued in the first quarter of 2006. Total shares granted and fully vested, but not yet issued, are 30,100 as of March 31, 2006. The weighted-average grant date fair value per share is $31.30. The aggregate intrinsic value of these awards is $1.4 million.

Stock Options

During the first quarter of 2006, 30,000 stock options were granted to two incoming non-employee directors of the Company. 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. Option awards are generally granted with an exercise price equal to the fair market price of the Company’s stock at the date of grant. No stock options were issued in the first quarter of 2005.

Compensation expense recorded during the first quarter of 2006 for these stock options is $0.1 million. Since the Company had not yet adopted SFAS No. 123(R) in the first quarter of 2005, stock options were not expensed through the income statement during 2005 and no compensation expense was recorded. Unamortized expense as of March 31, 2006 for all outstanding stock options is $0.4 million. The weighted average period over which this compensation will be recognized is one year.

The assumptions used in the Black-Scholes fair value method calculation for stock options are disclosed in the following table:


	Three Months Ended March 31, 2006
Weighted Average Value per Option Granted During the Period⁽¹⁾	$	14.65
Assumptions
Stock Price Volatility		31.5	%
Risk Free Rate of Return		4.6	%
Expected Dividend		0.3	%
Expected Term (in years)		4.0

⁽¹⁾

Calculated using the Black-Scholes fair value based method.

The following table is a summary of activity of stock options for the three months ended March 31, 2006:


Stock Options	Shares	Weighted- Average Grant Date Fair Value		Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value (in thousands) ⁽¹⁾
Outstanding at December 31, 2005	913,348	$	15.32
Granted	30,000		47.60
Exercised	65,748		15.91
Forfeited or Expired	—		—

Outstanding at March 31, 2006	877,600	$	16.38	1.6	$	27,784

Options Exercisable at March 31, 2006	830,100	$	15.25	1.5	$	27,224

⁽¹⁾

The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.

At March 31, 2006, the exercise price range for outstanding options was $12.84 to $47.60 per share. The following tables provide more information about the options by exercise price.

Options with exercise prices between $12.84 and $15.00 per share:


Options Outstanding
Number of Options		217,075
Weighted Average Exercise Price	$	12.84
Weighted Average Contractual Term (in years)		0.9

Options Exercisable
Number of Options		217,075
Weighted Average Exercise Price	$	12.84
Weighted Average Contractual Term (in years)		0.9

Options with exercise prices between $15.01 and $30.00 per share:


Options Outstanding
Number of Options		630,525
Weighted Average Exercise Price	$	16.12
Weighted Average Contractual Term (in years)		1.7

Options Exercisable
Number of Options		613,025
Weighted Average Exercise Price	$	16.11
Weighted Average Contractual Term (in years)		1.7

Options with exercise prices between $30.01 and $47.60 per share:


Options Outstanding
Number of Options		30,000
Weighted Average Exercise Price	$	47.60
Weighted Average Contractual Term (in years)		4.9

None of the options with exercise prices between $30.01 and $47.60 are exercisable as of March 31, 2006.

Stock Appreciation Rights

On February 23, 2006, the Company granted 132,800 SARs to employees. These awards allow the employee to receive any intrinsic 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 following assumptions were used for SARs valued using the Black-Scholes model:


	Three Months Ended March 31, 2006
Weighted Average Value per Stock Appreciation Right Granted During the Period⁽¹⁾	$	14.19

Assumptions
Stock Price Volatility		31.6	%
Risk Free Rate of Return		4.6	%
Expected Dividend		0.3	%
Expected Term (in years)		3.75

⁽¹⁾

Calculated using the Black-Scholes fair value based method.

Compensation expense recorded during the first quarter of 2006 for these SARs is $0.1 million. As no SARs were outstanding in the first quarter of 2005, no compensation expense was recorded for this type of award. In addition, all SARs were unvested at March 31, 2006. Unamortized expense as of March 31, 2006 for all outstanding SARs is $1.8 million which will be recognized over the next 2.9 years.

Performance Share Awards

The Company grants two types of performance share awards to employees. Certain of these awards 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. 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. A new type of award has been granted in 2006 that measures the Company’s performance based on internal metrics rather than a peer group. These awards represent the right to receive up to 100% in shares of common stock. The actual number of shares paid out 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 metric performance criteria 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.

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.

On February 23, 2006, the Board of Directors granted a series of 89,850 performance share awards with performance conditions and 52,900 performance share awards with market conditions to employees of the Company. The performance period for both of these awards commences January 1, 2006 and ends December 31, 2008.

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 is 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 is 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, 2006 for the Monte Carlo model to value equity and liability components of the performance share awards granted to executives in 2006 as well as the liability components of the 2004 and 2005 performance share awards granted:


	As of March 31, 2006
Risk Free Rate of Return		4.8	%
Stock Price Volatility		31.9	%
Correlation in stock price movement		90	%
Valuation Date Price	$	47.93

The Monte Carlo value per share for the liability for performance share awards at March 31, 2006 ranged from $2.31 to $13.00. The long-term liability represented on the balance sheet for performance share awards at March 31, 2006 is $1.1 million.

The following table is a summary of activity of performance share awards as of March 31, 2006:


Performance Share Awards	Shares	Weighted- Average Grant Date Fair Value per share ⁽¹⁾		Weighted- Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Non-vested shares outstanding at December 31, 2005	330,850	$	24.30
Granted	142,750		43.35
Vested	—		—
Forfeited	450		21.49

Non-vested shares outstanding at March 31, 2006	473,150	$	30.05	1.7	$	22,678

⁽¹⁾

The fair value figures in this table represent the fair value of the equity component of the performance share awards.

Total unamortized compensation cost related to the equity component of performance shares at March 31, 2006 is $9.1 million and will be recognized over the next 1.7 years. Total compensation cost recognized for performance shares during the quarter ended March 31, 2006 was $1.9 million.

12. SUBSEQUENT EVENT

On May 4, 2006, the stockholders of the Company approved an increase in the authorized number of shares of common stock from 80 million to 120 million shares. Following this approval, the authorized capital stock of the Company consists of 120 million shares of common stock, par value $0.10 per share, and five million shares of preferred stock, par value $0.10 per share.

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, 2006, and the related condensed consolidated statements of operations and of cash flows for the three month periods ended March 31, 2006 and 2005. 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, 2005 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, 2005 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005; and in our report dated March 6, 2006, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” 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 as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

As discussed in Notes 1 and 11 to the condensed consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share Based Payment (revised 2004).”

/s/ PricewaterhouseCoopers LLP

Houston, Texas

May 8, 2006

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, 2006 and 2005 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 Form 10-K for the year ended December 31, 2005.

Overview

Natural gas revenues increased by $50.9 million, or 49%, for the three months ended March 31, 2006 as compared to the three months ended March 31, 2005. The increase is due to higher realized natural gas prices as well as increased production in the East and Canada. Oil revenues increased by $12.2 million, or over 100%, for the first three months of 2006 as compared to the first three months of 2005. This increase is primarily due to an increase in oil prices in the first three months of 2006 as compared to the first three months of 2005. Additionally, first quarter 2005 crude oil revenues included an unrealized loss on crude oil derivatives of $7.0 million, and there was no unrealized impact in the first quarter of 2006. Somewhat offsetting the crude oil price increase and the change in the unrealized loss on crude oil derivatives discussed above was the decrease in crude oil production of approximately 12% in the first three months of 2006.

In the first three months of 2006, natural gas and crude oil prices were higher than the comparable period of the prior year and our financial results reflect their impact. Our realized natural gas price was $8.22 per Mcf, 44% higher than the $5.71 per Mcf price realized in the same period of the prior year. Our realized crude oil price was $61.11 per Bbl, 45% higher than the $42.11 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. 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.

For the three months ended March 31, 2006, we produced 21.3 Bcfe compared to production of 21.1 Bcfe for the comparable period of the prior year. Natural gas production was 18.9 Bcf and oil production was 396 Mbbls. Natural gas production increased by approximately 3% when compared to the comparable period of the prior year, which had production of 18.4 Bcf. Our East region improved natural gas production with the success of the increased drilling program. In addition, production in Canada increased as a result of the continued drilling success in the Musreau/Kakwa area and the addition of production from the Hinton field. These increases are partially offset by reduced production in our Gulf Coast and West regions as a result of natural production declines. Oil production decreased by 54 Mbbls from 450 Mbbls in the first three months of 2005 to 396 Mbbls produced in the first three months of 2006. Oil production increased in the East and West, remained flat in Canada and decreased in the Gulf Coast primarily due to the continued natural decline of the CL&F lease in south Louisiana.

We had net income of $53.2 million, or $1.09 per share, for the three months ended March 31, 2006 compared to net income of $20.8 million, or $0.43 per share, for the comparable period of the prior year. The increase in net income is primarily due to increased natural gas and oil production revenues, as discussed above. This increase is partially offset by an increase in total operating expenses of $17.3 million and an increase in income tax expense of $19.6 million in the first three months of 2006 as compared to the first three months of 2005. In addition, current year expense includes a $0.4 million, net of tax, cumulative loss relating to a change in accounting principle for the adoption of Statement of Financial Accounting Standards (SFAS) No. 123(R), “Share Based Payment (revised 2004).”

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 2006, we expect to spend approximately $435 million in capital and exploration expenditures, which includes a layer of investment for new projects that may arise during 2006. This figure has increased by $39 million from the approximately $396 million figure previously reported in our Form 10-K in order to reflect increased drilling costs as well as new projects.

For the three months ended March 31, 2006, $119.5 million of capital and exploration expenditures have been invested in our exploration and development efforts.

During the three months ended March 31, 2006, we drilled 71 gross wells (66 development, 4 exploratory and 1 extension wells) with a success rate of 97.2% compared to 44 gross wells (33 development, 9 exploratory and 2 extension wells) with a success rate of 86% for the comparable period of the prior year. For the full year, we plan to drill approximately 377 gross wells compared to 316 gross wells in 2005. The 2006 figure has changed from the 391 number previously reported in our Annual Report on Form 10-K due to the cost of the horizontal drilling program in the East.

We remain focused on our strategies of balancing our capital investments between higher risk projects with the potential for higher returns and lower risk projects with more stable returns, along with balancing longer life investments with impact exploration opportunities. 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.

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 source of cash for the three months ended March 31, 2006 was from funds generated from operations. We generate cash from the sale of natural gas and crude oil. 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 subject to 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 the Annual Report on Form 10-K, have 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 exploration and development expenditures, repay debt under our revolving credit facility and pay dividends. See below for additional discussion and analysis of cash flow.


	Three Months Ended March 31,
*(In thousands)*	2006			2005
Cash Flows Provided by Operating Activities	$	155,009		$	108,017
Cash Flows Used by Investing Activities		(114,189	)		(59,851	)
Cash Flows (Used) / Provided by Financing Activities		(42,932	)		1,392

Net (Decrease) / Increase in Cash and Cash Equivalents	$	(2,112	)	$	49,558

Operating Activities. Net cash provided by operating activities in the first three months of 2006 increased $47.0 million over the comparable period in 2005. This increase is primarily due to higher commodity prices. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 44% over the 2005 period, while crude oil realized prices increased 45% over the same period. Production volumes increased slightly with approximately a 1% increase in equivalent production in the first quarter of 2006 compared to the comparable period in 2005. While we believe 2006 commodity production may exceed 2005 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 by 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 increased by $54.3 million for the quarter ended March 31, 2006, compared to the same period in 2005. The increase from 2005 to 2006 is primarily due to an increase in drilling activity as a result of higher commodity prices.

Financing Activities. Cash flows used by financing activities were $42.9 million for the three months ended March 31, 2006 primarily due to payments made to reduce outstanding borrowings on our revolving credit facility by $45 million as well as dividend payments. Partially offsetting these cash uses were inflows from the exercise of stock options and the tax benefit received from stock-based compensation. Cash flows provided by financing activities were $1.4 million for the three months ended March 31, 2005. Cash flows provided by financing activities in the first three months of 2005 were the result of proceeds from the exercise of stock options, partially offset by dividend payments.

At March 31, 2006, we had $45 million of debt 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 has been adjusted to three million shares. During the first three months of 2006, 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, 2006 is 1,486,150.

Capitalization

Our capitalization information is as follows:


*(In millions)*	March 31, 2006			December 31, 2005
Debt ⁽¹⁾	$	295.0		$	340.0
Stockholders’ Equity		675.7			600.2

Total Capitalization	$	970.7		$	940.2

Debt to Capitalization		30	%		36	%

Cash and Cash Equivalents	$	8.5		$	10.6

⁽¹⁾

Includes $20.0 million of current portion of long-term debt at both March 31, 2006 and December 31, 2005. Includes $45 million and $90 million of borrowings under our revolving credit facility at March 31, 2006 and December 31, 2005, respectively.

During the three months ended March 31, 2006, we paid dividends of $1.9 million on our common stock. A regular dividend of $0.04 per share of common stock, or $0.027 per share for dividends prior to the 3-for-2 stock split as adjusted for the split, has been declared for each quarter since we became a public company in 1990.

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 quarters ended March 31, 2006 and 2005.


	Three Months Ended March 31,
	2006		2005
	*(In millions)*
Capital Expenditures
Drilling and Facilities	$	89.2	$	40.7
Leasehold Acquisitions		14.7		2.7
Pipeline and Gathering		3.1		3.2
Other		0.7		0.3

		107.7		46.9

Proved Property Acquisitions		0.2		0.8
Exploration Expense		11.6		19.4

Total	$	119.5	$	67.1

We plan to drill approximately 377 gross wells in 2006. This drilling program includes approximately $435 million in total capital and exploration expenditures. See the “Overview” discussion for additional information regarding the current year drilling program. The increase in our leasehold acquisitions expense from March 31, 2005 to March 31, 2006 is the result of several new exploratory resource areas in the Gulf Coast, Canada and, to a lesser extent, the East. We will continue to assess the natural gas and crude oil price environment and may increase or decrease the capital and exploration expenditures accordingly.

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, 2005, for further discussion of our critical accounting policies.

Effective January 1, 2006, we adopted the accounting policies described in SFAS No. 123(R), “Share Based Payment (revised 2004).” We chose to use the modified prospective method of transition. Under this method, no prior year amounts have been restated. Prior to January 1, 2006, we accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” In addition, SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments.

One primary difference in our method of accounting after the adoption of SFAS No. 123(R) is that unvested stock options will now be expensed as a component of Stock-Based Compensation cost in the General and Administrative Expense line item of the Condensed Consolidated Statement of Operations. This expense will be based on the fair value of the award at the original grant date and will be recognized over the remaining vesting period. Prior to the adoption of SFAS No. 123(R), we included this amount as a pro-forma disclosure in the Notes to the Condensed Consolidated Financial Statements. The expense resulting from the expensing of stock options is $0.1 million for the quarter ended March 31, 2006. Another change relates to the accounting for our performance share awards. Certain of these awards are now accounted for by bifurcating

the equity and liability components. A Monte Carlo model is used to value the liability component, rather than accounting for the award using the average closing stock price at the end of each reporting period. All other awards are accounted for in substantially the same way as they were or would have been in prior periods, with the exception of the differences noted below.

Other differences in the way we account for stock-based compensation after January 1, 2006, result from the application of a forfeiture rate to all grants rather than recording actual forfeitures as they occur. We are now required to estimate forfeitures on all equity-based compensation and adjust periodic expense. Upon adoption, we did not record a cumulative effect adjustment for these forfeitures as the amount was immaterial. In addition, this change in accounting for forfeitures results in an immaterial change in overall compensation cost for the quarter ended March 31, 2006. Furthermore, we are required to immediately expense certain awards to retirement-eligible employees depending on the structure of each individual plan. The retirement-eligibility provision only applies to new grants that were awarded after January 1, 2006. The total expense that we immediately recognized related to restricted stock awards granted to retirement-eligible employees in the first quarter of 2006 is $0.5 million.

We issued stock appreciation rights to executive employees for the first time during the first quarter of 2006. The grant date fair value of these awards is measured using a Black-Scholes model and compensation cost is expensed over the three year graded-vesting service period. Expense related to these awards was $0.1 million, before the effect of taxes, for the 2006 quarter. In addition, a new type of performance share was issued to employees. These awards measure our performance based on three internal metrics rather than a peer group’s stock performance used for our other performance share awards. These awards cliff vest at the end of the three year service period. Compensation cost related to these new internal-metric based performance share awards granted to employees was $0.3 million, before the effect of taxes, for the 2006 quarter. In addition, we incurred a $0.4 million, net of tax, cumulative effect charge as a result of changes made in our accounting for performance shares. For further information on the accounting for these and our other stock-based compensation awards, please refer to Notes 1 and 11 to the Notes to the Condensed Consolidated Financial Statements.

Our Compensation Committee of our Board of Directors did make one modification to our stock option awards in 2005. They approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under our Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under our 2004 Incentive Plan.

The 198,799 shares awarded to employees under the 1994 plan at an exercise price of $15.32 would have vested in February 2006. The 24,500 shares awarded to non-employee directors under the 2004 plan at an exercise price of $23.32 would have vested 12,250 shares in each of April 2006 and April 2007. The decision to accelerate the vesting of these unvested options, which we believed to be in the best interest of our shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with our adoption of SFAS No. 123(R). The accelerated vesting of the options did not have an impact on our results of operations or cash flows for 2005. The acceleration of vesting is expected to reduce our compensation expense related to these options by approximately $0.2 million for 2006.

Results of Operations

First Quarters of 2006 and 2005 Compared

We reported net income in the first quarter of 2006 of $53.2 million, or $1.09 per share. During the corresponding quarter of 2005, we reported net income of $20.8 million, or $0.43 per share. Net income increased in the current quarter by $32.4 million due to an increase in operating income partially offset by an increase of $19.6 million in income tax expense. Operating income increased $53.6 million compared to the prior year, from $38.0 million in the first quarter of 2005 to $91.6 million in the first quarter of 2006. The increase in current year operating income was substantially due to an increase in natural gas and oil production revenues partially offset by an increase in total operating expenses.

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $8.22 per Mcf for the three months ended March 31, 2006 compared to $5.71 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which increased the price by $0.08 per Mcf in 2006 and decreased the price by $0.34 per Mcf in 2005. The following table excludes the unrealized loss from the change in derivative fair value of $0.6 million for the three months ended March 31, 2005. There was no unrealized impact from the change in derivative fair value for the three months ended March 31, 2006. The unrealized change in fair value has been included in Natural Gas Production Revenues in the Statement of Operations.


	Three Months Ended March 31,					Variance Amount			Percent
	2006			2005		Variance Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		7,248			7,321		(73	)	(1	)%
West		5,390			5,685		(295	)	(5	)%
East		5,765			5,133		632		12	%
Canada		477			222		255		115	%

Total Company		18,880			18,361		519		3	%

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	8.21		$	6.03	$	2.18		36	%
West	$	7.08		$	4.73	$	2.35		50	%
East	$	9.31		$	6.35	$	2.96		47	%
Canada	$	8.12		$	5.57	$	2.55		46	%
Total Company	$	8.22		$	5.71	$	2.51		44	%

Natural Gas Production Revenue (in thousands)
Gulf Coast	$	59,475		$	44,117	$	15,358		35	%
West		38,157			26,892		11,265		42	%
East		53,666			32,588		21,078		65	%
Canada		3,869			1,235		2,634		213	%

Total Company	$	155,167		$	104,832	$	50,335		48	%

Price Variance Impact on Natural Gas Production Revenue
(in thousands)
Gulf Coast	$	15,798
West		12,666
East		17,064
Canada		1,207

Total Company	$	46,735

Volume Variance Impact on Natural Gas Production Revenue
(in thousands)
Gulf Coast	$	(440	)
West		(1,395	)
East		4,014
Canada		1,421

Total Company	$	3,600

The increase in Natural Gas Production Revenue is primarily due to the increase in natural gas sales prices and, to a lesser extent, the increase in natural gas production. Prices were higher in all regions and production increased in the East and Canada. Decreased production in the Gulf Coast and West was due to natural declines. The increase in the realized natural gas price and production resulted in a net revenue increase of $50.3 million, excluding the unrealized impact of derivative instruments.

Brokered Natural Gas Revenue and Cost


	Three Months Ended March 31,					Variance Amount			Percent
	2006			2005		Variance Amount			Percent
Sales Price ($/Mcf)	$	9.20		$	7.09	$	2.11		30	%
Volume Brokered (Mmcf)		3,566			3,738		(172	)	(5	)%

Brokered Natural Gas Revenues (in thousands)	$	32,819		$	26,492

Purchase Price ($/Mcf)	$	8.20		$	6.23	$	1.97		32	%
Volume Brokered (Mmcf)		3,566			3,738		(172	)	(5	)%

Brokered Natural Gas Cost (in thousands)	$	29,245		$	23,298

Brokered Natural Gas Margin (in thousands)	$	3,574		$	3,194	$	380		12	%

(in thousands)
Sales Price Variance Impact on Revenue	$	7,524
Volume Variance Impact on Revenue		(1,197	)

	$	6,327

(in thousands)
Purchase Price Variance Impact on Purchases	$	(7,025	)
Volume Variance Impact on Purchases		1,078

	$	(5,947	)

The increased brokered natural gas margin of $0.4 million was driven by an increased sales price that outpaced the increase in purchase cost, offset in part by a decrease in volume.

Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price 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. Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $42.11 per Bbl for the first quarter of 2005. The 2005 price includes the realized impact of derivative instruments which reduced the price by $5.74 per Bbl. The following table excludes the unrealized loss from the change in derivative fair value of $7.0 million for the three months ended March 31, 2005. There was no unrealized impact from the change in derivative fair value for the three months ended March 31, 2006. The unrealized change in fair value has been included in Crude Oil and Condensate Revenues in the Statement of Operations.


	Three Months Ended March 31,					Variance Amount			Percent
	2006			2005		Variance Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		331			405		(74	)	(18	)%
West		54			36		18		50	%
East		7			5		2		40	%
Canada		4			4		—		—

Total Company		396			450		(54	)	(12	)%

Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	61.36		$	41.50	$	19.86		48	%
West	$	60.64		$	48.57	$	12.07		25	%
East	$	59.15		$	48.06	$	11.09		23	%
Canada	$	48.67		$	38.64	$	10.03		26	%
Total Company	$	61.11		$	42.11	$	19.00		45	%

Crude Oil Revenue (in thousands)
Gulf Coast	$	20,284		$	16,788	$	3,496		21	%
West		3,303			1,726		1,577		91	%
East		412			261		151		58	%
Canada		181			155		26		17	%

Total Company	$	24,180		$	18,930	$	5,250		28	%

Price Variance Impact on Crude Oil Revenue
(in thousands)
Gulf Coast	$	6,563
West		698
East		77
Canada		37

Total Company	$	7,375

Volume Variance Impact on Crude Oil Revenue
(in thousands)
Gulf Coast	$	(3,071	)
West		872
East		74
Canada		—

Total Company	$	(2,125	)

The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $5.3 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is the result of decreased Gulf Coast production from the continued natural decline of the CL&F lease in south Louisiana.

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,
	2006				2005
	Realized		Unrealized		Realized			Unrealized
	*(In thousands)*
Operating Revenues - Increase/(Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	1,437	$	—	$	(6,222	)	$	(560	)
Crude Oil		—		—		(128	)		(103	)

Total Cash Flow Hedges		1,437		—		(6,350	)		(663	)
Other Derivative Financial Instruments
Crude Oil		—		—		(2,453	)		(6,849	)

Total Other Derivative Financial Instruments		—		—		(2,453	)		(6,849	)

	$	1,437	$	—	$	(8,803	)	$	(7,512	)

We are exposed to market risk 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 increased by $1.3 million between the first quarter of 2006 and the first quarter of 2005 primarily due to a decrease in our payout liability associated with a favorable legal ruling. This variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year first quarter period.

Operating Expenses

Total costs and expenses from operations increased $17.3 million in the first three months of 2006 compared to the same period of 2005. The primary reasons for this fluctuation are as follows:

•

Exploration expense decreased by $7.8 million in the first quarter of 2006, primarily as a result of decreased dry hole expense partially offset by increased geological and geophysical costs. During the first quarter of 2006, we incurred $10.1 million less dry hole expense, mainly as a result of a decrease in the Gulf Coast attributable to a more successful drilling program in the first quarter of 2006 and, to a lesser extent, in Canada and the West region, compared to the first quarter of 2005. Geological and geophysical costs increased by $1.7 million over the prior year period primarily due to increased expenses in the Gulf Coast.

•

Brokered Natural Gas Cost increased by $5.9 million from the first quarter of 2005 to the first quarter of 2006. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.

•

Taxes Other Than Income increased by $5.8 million, or 59%, compared to the first quarter of 2005, primarily due to increased production taxes as a result of increased commodity prices as well as an increase in ad valorem taxes.

•

Depreciation, Depletion and Amortization increased by $5.3 million in the first quarter of 2006. This is primarily due to increased production for the quarter as well as an increase in the DD&A rate associated with the commencement of offshore production in late 2005.

•

General and Administrative expense increased by $4.9 million in the first quarter of 2006. This increase is primarily due to increased stock compensation costs of $3.5 million. This compensation increase results from expense related to performance share awards as well as increased amortization related to stock grants outstanding in 2006 that were not outstanding in 2005. Also, the accounting for certain stock-based compensation has changed in the current quarter due to the adoption of SFAS No. 123(R). In addition, there was an increase in incentive compensation related to employee bonuses and an increase in pension expense over the prior year first quarter.

•

Direct Operations expense increased by $3.0 million over the first quarter of 2005. This is primarily the result of an increase over the prior year quarter in outside operated properties expense and expenses for incentive compensation and employee related expenses. The increase in outside operated properties expense resulted from increases in the Gulf Coast region, largely from accruals related to repairs on a plant damaged by the hurricanes that occurred in 2005 and also, to a lesser extent, in the West region.

Interest Expense, Net

Interest expense, net increased $1.1 million in the first three months of 2006. Interest expense related to borrowings under the credit facility was higher in the current quarter due to higher average borrowings. Weighted average borrowings based on daily balances were approximately $70 million during the first quarter of 2006. There were no borrowings outstanding during the first quarter of 2005.

Income Tax Expense

Income tax expense increased by $19.6 million due to a comparable increase in our pre-tax income. The effective tax rate for the quarters ended March 31, 2006 and 2005 was 37.3% and 37.2%, respectively.

Recently Issued Accounting Pronouncements

In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for in a similar fashion, regardless of the instrument’s form. We do not believe that our financial position, results of operations or cash flows will be impacted by SFAS No. 155 as we do not currently hold any hybrid financial instruments.

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 – Swaps

From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During the first three months of 2006, we did not have any natural gas price or crude oil swaps.

From time to time, we enter into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS No. 133. These financial instruments are recorded at fair value at the balance sheet date. At March 31, 2006, we did not have any of these types of 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 2006, natural gas price collars covered 6,702 Mmcf, or 35%, of our 2006 gas production, with a weighted average floor of $8.25 per Mcf and a weighted average ceiling of $12.74 per Mcf.

At March 31, 2006, we had open natural gas price collar contracts covering our 2006 and 2007 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, 2006
Second Quarter 2006	6,776	$	12.74 / $8.25
Third Quarter 2006	6,850		12.74 / 8.25
Fourth Quarter 2006	6,851		12.74 / 8.25

Nine Months Ended December 31, 2006	20,477	$	12.74 / $8.25	$	11,552

First Quarter 2007	1,687	$	12.87 / $8.80
Second Quarter 2007	1,706		12.87 / 8.80
Third Quarter 2007	1,724		12.87 / 8.80
Fourth Quarter 2007	1,724		12.87 / 8.80

Full Year 2007	6,841	$	12.87 / $8.80	$	(1,313	)

During the first three months of 2006, crude oil price collars covered 90 Mbbls, or 23%, of our 2006 oil production, with a weighted average floor of $50.00 per Bbl and a weighted average ceiling of $76.00 per Bbl.

At March 31, 2006, we had one open crude oil price collar contract covering our 2006 production as follows:


	Crude Oil Price Collar
Contract Period	Volume in Mbbl	Weighted Average Ceiling / Floor *(per Bbl)*		Net Unrealized Loss *(In thousands)*
As of March 31, 2006
Second Quarter 2006	91	$	76.00 / $50.00
Third Quarter 2006	92		76.00 / 50.00
Fourth Quarter 2006	92		76.00 / 50.00

Nine Months Ended December 31, 2006	275	$	76.00 / $50.00	$	(508	)

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 captions “West Virginia Royalty Litigation,” “Texas Title Litigation” and “Raymondville Area” 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

There have been no material changes to the risk factors previously disclosed in Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.

ITEM 6. Exhibits

10.21 - 2006 Form of Stock Appreciation Rights Award Agreement

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 8, 2006	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and
		Chief Executive Officer
		(Principal Executive Officer)

May 8, 2006	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

May 8, 2006	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)

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