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 June 30, 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 July 21, 2006, there were 48,261,684 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 and Six Months Ended June 30, 2006 and 2005		3

Condensed Consolidated Balance Sheet at June 30, 2006 and December 31, 2005		4

Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 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		23

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3. Quantitative and Qualitative Disclosures about Market Risk		40

Item 4. Controls and Procedures		41

Part II. Other Information		41

Item 1. Legal Proceedings		41

Item 1A. Risk Factors		41

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		42

Item 4. Submission of Matters to a Vote of Security Holders		43

Item 6. Exhibits		44

Signatures		45

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
*(In thousands, except per share amounts)*	2006		2005		2006			2005
OPERATING REVENUES
Natural Gas Production	$	141,503	$	111,817	$	296,670		$	216,089
Brokered Natural Gas		17,495		15,520		50,314			42,012
Crude Oil and Condensate		29,668		23,936		53,848			35,914
Other		2,128		611		4,730			1,943

		190,794		151,884		405,562			295,958

OPERATING EXPENSES
Brokered Natural Gas Cost		15,397		13,701		44,642			36,999
Direct Operations - Field and Pipeline		17,955		14,307		35,585			28,925
Exploration		14,797		11,362		26,411			30,731
Depreciation, Depletion and Amortization		32,792		26,112		64,727			52,768
Impairment of Unproved Properties		3,883		3,643		7,463			7,054
General and Administrative		13,515		8,700		27,364			17,660
Taxes Other Than Income		14,578		12,396		30,073			22,114

		112,917		90,221		236,265			196,251
Gain on Sale of Assets		4		59		211			59

INCOME FROM OPERATIONS		77,881		61,722		169,508			99,766
Interest Expense and Other		6,023		5,134		12,173			10,122

Income Before Income Taxes and Cumulative Effect of Accounting Change		71,858		56,588		157,335			89,644
Income Tax Expense		24,994		21,166		56,903			33,460

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		46,864		35,422		100,432			56,184
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX (Note 11)		—		—		(403	)		—

NET INCOME	$	46,864	$	35,422	$	100,029		$	56,184

Basic Earnings Per Share - Before Accounting Change	$	0.96	$	0.72	$	2.06		$	1.15
Diluted Earnings Per Share - Before Accounting Change	$	0.94	$	0.71	$	2.02		$	1.13
Basic Loss Per Share - Accounting Change	$	—	$	—	$	(0.01	)	$	—
Diluted Loss Per Share - Accounting Change	$	—	$	—	$	(0.01	)	$	—
Basic Earnings Per Share	$	0.96	$	0.72	$	2.05		$	1.15
Diluted Earnings Per Share	$	0.94	$	0.71	$	2.01		$	1.13

Weighted Average Common Shares Outstanding		48,741		48,917		48,711			48,821
Diluted Common Shares (Note 5)		49,600		49,578		49,639			49,515

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)*	June 30, 2006			December 31, 2005
ASSETS
Current Assets
Cash and Cash Equivalents	$	16,059		$	10,626
Accounts Receivable		99,552			168,248
Inventories		25,956			24,616
Deferred Income Taxes		7,846			15,674
Derivative Contracts		23,111			1,736
Other		15,067			9,412

Total Current Assets		187,591			230,312
Properties and Equipment, Net (Successful Efforts Method)		1,400,110			1,238,055
Deferred Income Taxes		26,573			19,587
Derivative Contracts		5,836			164
Other Assets		7,895			7,252

	$	1,628,005		$	1,495,370

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	122,801		$	140,006
Current Portion of Long-Term Debt		20,000			20,000
Deferred Income Taxes		9,388			941
Derivative Contracts		1,254			22,478
Accrued Liabilities		36,500			35,159

Total Current Liabilities		189,943			218,584
Long-Term Debt		330,000			320,000
Deferred Income Taxes		320,245			289,381
Other Liabilities		75,733			67,194
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common Stock:
Authorized — 120,000,000 and 80,000,000 Shares of $.10 Par Value 2006 and 2005, respectively Issued — 50,440,916 Shares and 50,081,983 Shares in 2006 and 2005, respectively		5,044			5,008
Additional Paid-in Capital		409,801			397,349
Retained Earnings		348,294			252,167
Accumulated Other Comprehensive Income / (Loss)		15,330			(15,115	)
Less Treasury Stock, at Cost:
2,180,050 and 1,513,850 Shares in 2006 and 2005, respectively		(66,385	)		(39,198	)

Total Stockholders’ Equity		712,084			600,211

	$	1,628,005		$	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)


	Six Months Ended June 30,
*(In thousands)*	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	100,029		$	56,184
Adjustments to Reconcile Net Income to Cash
Provided by Operating Activities:
Cumulative Effect of Accounting Change		403			—
Depreciation, Depletion and Amortization		64,727			52,768
Impairment of Unproved Properties		7,463			7,054
Deferred Income Tax Expense		22,032			9,078
Gain on Sale of Assets		(211	)		(59	)
Exploration Expense		26,411			30,731
Unrealized Loss on Derivatives		—			3,681
Stock-Based Compensation Expense and Other		8,632			2,847
Changes in Assets and Liabilities:
Accounts Receivable		68,696			32,338
Inventories		(1,340	)		224
Other Current Assets		(5,655	)		(2,858	)
Other Assets		(479	)		(134	)
Accounts Payable and Accrued Liabilities		(21,022	)		(4,844	)
Other Liabilities		4,571			1,066
Stock-Based Compensation Tax Benefit		(4,897	)		—

Net Cash Provided by Operating Activities		269,360			188,076

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(224,463	)		(115,848	)
Proceeds from Sale of Assets		575			710
Exploration Expense		(26,411	)		(30,731	)

Net Cash Used in Investing Activities		(250,299	)		(145,869	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		145,000			—
Decrease in Debt		(135,000	)		—
Sale of Common Stock Proceeds		2,564			3,580
Stock-Based Compensation Tax Benefit		4,897			—
Purchase of Treasury Stock		(27,187	)		(571	)
Dividends Paid		(3,902	)		(3,296	)

Net Cash Used in Financing Activities		(13,628	)		(287	)

Net Increase in Cash and Cash Equivalents		5,433			41,920
Cash and Cash Equivalents, Beginning of Period		10,626			10,026

Cash and Cash Equivalents, End of Period	$	16,059		$	51,946

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 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 Condensed Consolidated Statement of Operations for the first quarter of 2006. Adoption of SFAS No. 123(R) decreased income from operations and income before income taxes by approximately $0.1 million and decreased net income by less than $0.1 million for the six months ended June 30, 2006. 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.

In July 2006, the FASB issued FASB Interpretation (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 threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company does not expect that this Interpretation will have a material impact on its financial position, results of operations or cash flows.

2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:


*(In thousands)*	June 30, 2006			December 31, 2005
Unproved Oil and Gas Properties	$	132,508		$	107,787
Proved Oil and Gas Properties		2,163,900			1,970,407
Gathering and Pipeline Systems		189,628			178,876
Land, Building and Improvements		4,926			4,892
Other		33,909			33,077

		2,524,871			2,295,039
Accumulated Depreciation, Depletion and Amortization		(1,124,761	)		(1,056,984	)

	$	1,400,110		$	1,238,055

At both June 30, 2006 and December 31, 2005, the Company did not have any 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)*	June 30, 2006			December 31, 2005
Accounts Receivable
Trade Accounts	$	88,887		$	147,016
Joint Interest Accounts		13,618			14,319
Current Income Tax Receivable		2,210			12,239
Other Accounts		210			315

		104,925			173,889
Allowance for Doubtful Accounts		(5,373	)		(5,641	)

	$	99,552		$	168,248

Inventories
Natural Gas and Oil in Storage	$	16,686		$	18,279
Tubular Goods and Well Equipment		8,383			7,161
Pipeline Imbalances		887			(824	)

	$	25,956		$	24,616

Other Current Assets
Drilling Advances	$	2,556		$	2,169
Prepaid Balances		12,207			6,939
Other Accounts		304			304

	$	15,067		$	9,412

Accounts Payable
Trade Accounts	$	18,767		$	18,227
Natural Gas Purchases		13,265			12,208
Royalty and Other Owners		30,650			49,312
Capital Costs		44,297			37,489
Taxes Other Than Income		5,885			10,329
Drilling Advances		4,786			5,760
Wellhead Gas Imbalances		2,171			2,175
Other Accounts		2,980			4,506

	$	122,801		$	140,006

Accrued Liabilities
Employee Benefits	$	6,925		$	9,020
Taxes Other Than Income		21,054			16,188
Interest Payable		6,614			6,818
Income Taxes Payable		32			41
Other Accounts		1,875			3,092

	$	36,500		$	35,159

Other Liabilities
Postretirement Benefits Other Than Pension	$	8,020		$	6,517
Accrued Pension Cost		5,929			5,904
Rabbi Trust Deferred Compensation Plan		5,586			4,883
Accrued Plugging and Abandonment Liability		45,077			42,991
Other Accounts		11,121			6,899

	$	75,733		$	67,194

4. LONG-TERM DEBT

At June 30, 2006, the Company had $100 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 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.

In addition to the $100 million of debt outstanding under the credit facility, the Company has the following debt outstanding at June 30, 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 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 and six months ended June 30, 2006 and 2005.


	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006	2005
Shares - basic	48,740,815	48,917,430	48,710,531	48,821,369
Dilution effect of stock options and awards at end of period	859,595	660,958	928,796	693,713

Shares - diluted	49,600,410	49,578,388	49,639,327	49,515,082

Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	30,000	—	30,000	—

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 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 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 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 Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.

The West Virginia Supreme Court of Appeals issued its decision in a case involving an unrelated party on June 15, 2006, which became final on July 15, 2006. The decision may negatively impact some of the defenses raised on behalf of the Company in its litigation with respect to the issue of deductibility of post-production expenses under certain leases, but the Company believes that in a significant number of leases it has lease language, factual distinctions and defenses that are not implicated by the ruling. The case against the Company has not yet been re-activated to the docket, and the Company is investigating how this recent ruling may impact its defense of the case.

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 at that time, the order dismissing the Company was not then final. A motion to finalize the proceedings in the trial court via severance of the dismissed defendants was filed April 25, 2006, and the remaining defendants moved to join the motions that led to the dismissal of the Company. At a hearing on June 23, 2006, the Court dismissed the remaining defendants, and effectively denied the plaintiffs’ attempt to modify the prior dismissal order, which is now final. Plaintiffs filed a Notice of Appeal on July 17, 2006.

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 filed a Motion for Reconsideration and Opposition to Proposed Order. The Court, on March 24, 2006, denied the Motion.

On July 12, 2006, Cody entered into a Purchase and Sale Agreement with the remaining defendant to acquire all of that defendant’s interest in the Raymondville Field. The agreement would make the summary judgment ruling by the trial judge a final order and dismiss, with prejudice, all pending counter claims filed by such defendant. Cody expects to complete the purchase in the third quarter of 2006.

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 $8.5 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.

Rig Commitments

During the second quarter of 2006, the Company entered into a long-term contract for the use of an additional land drilling rig in the Gulf Coast with an existing contracted rig provider. The Company is obligated to pay $8.0 million over the one year contract starting on the delivery date, which is estimated to occur in September 2006. Additionally, commitments on two existing rigs disclosed in the Annual Report on Form 10-K for the year ended December 31, 2005 have been renewed for an additional $1.7 million to be paid in 2008.

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 June 30, 2006, the Company had 23 cash flow hedges open: 21 natural gas price collar arrangements and two crude oil collar arrangements. At June 30, 2006, a $26.9 million ($16.7 million net of tax) unrealized gain was recorded in Accumulated Other Comprehensive Income, along with a $23.1 million short-term derivative receivable, a $1.3 million short-term derivative liability, a $5.8 million long-term derivative receivable, and a $0.8 million long-term derivative liability, which is shown in Other Liabilities 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 June 30, 2006 the Company would expect to reclassify to the Statement of Operations, over the next 12 months, $13.6 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 June 30, 2006 related to anticipated 2006 and a portion of anticipated 2007 production.

During the first half of 2006, the Company entered into one new oil collar contract and 13 new natural gas collar contracts covering a portion of its 2007 production. As of June 30, 2006, natural gas price collars for 2007 cover 30.3 Mmcf of production at a weighted average floor of $8.83 and a weighted average ceiling of $12.16. The oil price collar for 2007 covers 365 Mbbl of production at a weighted average floor of $60.00 and a weighted average ceiling of $80.00.

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 and six month periods ended June 30, 2006 and 2005.


	Three Months Ended June 30,											Six Months Ended June 30,
*(In thousands)*	2006					2005						2006						2005
Accumulated Other Comprehensive Income / (Loss) - Beginning of Period				$	3,559				$	(38,147	)				$	(15,115	)				$	(20,351	)
Net Income	$	46,864				$	35,422					$	100,029					$	56,184
Other Comprehensive Income / (Loss)
Reclassification Adjustment for Settled Contracts, net of taxes of $2,734, ($4,278), $3,281 and ($6,635), respectively		(4,463	)				6,937						(5,353	)					10,760
Changes in Fair Value of Hedge Positions, net of taxes of ($9,253), ($6,371), ($21,379) and $7,544, respectively		15,097					10,335						34,881						(12,541	)
Minimum Pension Liability, net of taxes of $ -, $ -, $- and ($794), respectively		—					—						—						1,287
Foreign Currency Translation Adjustment, net of taxes of ($698), $122, ($ 563) and $141, respectively		1,137					(199	)					917						(229	)

Total Other Comprehensive Income / (Loss)		11,771			11,771		17,073			17,073			30,445			30,445			(723	)		(723	)

Comprehensive Income	$	58,635				$	52,495					$	130,474					$	55,461

Accumulated Other Comprehensive Income / (Loss) - End of Period				$	15,330				$	(21,074	)				$	15,330					$	(21,074	)

Changes in the components of accumulated other comprehensive income, net of taxes, for the six months ended June 30, 2006 are as follows:


Accumulated Other Comprehensive Income Review
*(in thousands)*	Net Gains / (Losses) on Cash Flow Hedges			Minimum Pension Liability			Foreign Currency Translation Adjustment		Total
Balance at December 31, 2005	$	(12,860	)	$	(3,170	)	$	915	$	(15,115	)
Net change in unrealized gains / (losses) on cash flow hedges, net of taxes of $18,097		29,528			—					29,528
Change in foreign currency translation adjustment, net of taxes of $562		—			—			917		917

Balance at June 30, 2006	$	16,668		$	(3,170	)	$	1,832	$	15,330

9. ASSET RETIREMENT OBLIGATIONS

The following table reflects the changes in the asset retirement obligations during the six months ended June 30, 2006.


*(In thousands)*
Carrying amount of asset retirement obligations at December 31, 2005	$	42,991
Liabilities added during the current period		1,372
Liabilities settled during the current period		(14	)
Current period accretion expense		728

Carrying amount of asset retirement obligations at June 30, 2006	$	45,077

Accretion expense was $0.7 million and $0.7 million for the six months ended June 30, 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 and six months ended June 30, 2006 and 2005 are as follows:


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
*(In thousands)*	2006			2005			2006			2005
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	680		$	558		$	1,360		$	1,116
Interest Cost		583			495			1,166			990
Expected Return on Plan Assets		(476	)		(355	)		(952	)		(710	)
Amortization of Prior Service Cost		44			44			88			88
Amortization of Net Loss		303			225			606			450

Net Periodic Benefit Cost	$	1,134		$	967		$	2,268		$	1,934

Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	197		$	169		$	394		$	338
Interest Cost		219			151			438			302
Plan Termination (Gain) / Loss		(21	)		80			(42	)		160
Recognized Net Actuarial Loss / (Gain)		8			(20	)		16			(40	)
Amortization of Prior Service Cost		238			227			476			454
Amortization of Net Obligation at Transition		158			162			316			324

Total Postretirement Benefit Cost	$	799		$	769		$	1,598		$	1,538

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. The Company made a $2.0 million contribution to the qualified pension plan during the second quarter of 2006. Management has not determined if any additional discretionary funding will be made to the qualified pension plan during the second half of 2006.

11. STOCK-BASED COMPENSATION

Incentive Plans

Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, 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 second quarter of 2006 and 2005 is $4.2 million and $1.5 million, pre-tax, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations. For the first half of 2006 and 2005, stock-based compensation expense was $8.7 million and $2.6 million, respectively. In the first half of 2006, compensation expense includes amortization on restricted stock grants, stock options, SARs and performance shares at fair value. Compensation expense in the first half of 2005 only includes amortization on restricted stock grants and compensation expense related to performance shares.

Prior to the adoption of SFAS No. 123(R), the Company presented tax benefits resulting from tax deductions related to stock-based compensation as an operating cash flow. Under SFAS No. 123(R), the tax benefits resulting from tax deductions in excess of expense is reported as an operating cash outflow and a financing cash inflow. For the first half of 2006, $4.9 million is reported in these two separate line items in the Condensed Consolidated Statement of Cash Flows.

The cumulative effect of adoption that was recorded in the first quarter of 2006 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 and six months ended June 30, 2005:


*(In thousands, except per share amounts)*	Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
Net Income, as reported	$	35,422		$	56,184
Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported		948			1,588
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		(1,135	)		(2,067	)

Pro forma Net Income	$	35,235		$	55,705

Earnings per Share:
Basic - as reported	$	0.72		$	1.15
Basic - pro forma	$	0.72		$	1.14
Diluted - as reported	$	0.71		$	1.13
Diluted - pro forma	$	0.71		$	1.13

Share Count		48,917			48,821
Diluted Share Count		49,578			49,515

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 half of 2006. All of these awards were granted in the first quarter of 2006. 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 six months of 2006 and 2005 is $3.7 million and $2.5 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 June 30, 2006 for all outstanding restricted stock awards is $6.8 million.

The following table is a summary of activity of restricted stock awards as of June 30, 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	229,118		21.68
Forfeited	200		30.43

Non-vested shares outstanding at June 30, 2006	405,997	$	31.91	1.9	$	19,894

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. Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table below.

The following table is a summary of activity of restricted stock units as of June 30, 2006:


Restricted Stock Units	Shares	Weighted- Average Grant Date Fair Value per share		Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2005	30,100	$	31.30
Granted and fully vested	17,220		50.82
Issued	8,600		31.30
Forfeited	—		—

Outstanding at June 30, 2006	38,720	$	39.98	$	1,897

As shown in the table above, 17,220 restricted stock units were granted during the first half of 2006. The compensation cost, which reflects the total fair value of these units, recorded in the second quarter of 2006 is $0.9 million.

Stock Options

During the first six months of 2006, 30,000 stock options were granted to two incoming non-employee directors of the Company. All of these stock options were granted in the first quarter of 2006. 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 granted in the first six months of 2005.

Compensation expense recorded during the first half of 2006 for these stock options is $0.1 million. Since the Company had not yet adopted SFAS No. 123(R) in the first half of 2005, stock options were not expensed through the income statement during 2005 and no compensation expense was recorded. Unamortized expense as of June 30, 2006 for all outstanding stock options is $0.3 million. The weighted average period over which this compensation will be recognized is approximately 2.7 years.

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


	Three and Six Months Ended June 30,2006
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 six months ended June 30, 2006:


Stock Options	Shares	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands) ⁽¹⁾
Outstanding at December 31, 2005	913,348	$	15.32
Granted	30,000		47.60
Exercised	168,198		15.13
Forfeited or Expired	900		18.20

Outstanding at June 30, 2006	774,250	$	16.61	1.4	$	25,076

Options Exercisable at June 30, 2006	744,250	$	15.36	1.3	$	25,034

⁽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 June 30, 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		166,875
Weighted Average Exercise Price	$	12.84
Weighted Average Contractual Term (in years)		0.6

Options Exercisable
Number of Options		166,875
Weighted Average Exercise Price	$	12.84
Weighted Average Contractual Term (in years)		0.6

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


Options Outstanding
Number of Options		577,375
Weighted Average Exercise Price	$	16.09
Weighted Average Contractual Term (in years)		1.5

Options Exercisable
Number of Options		577,375
Weighted Average Exercise Price	$	16.09
Weighted Average Contractual Term (in years)		1.5

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)		4.7

None of the options with exercise prices between $30.01 and $47.60 are exercisable as of June 30, 2006.

Stock Appreciation Rights

On February 23, 2006, the Company granted 132,800 stock appreciation rights (SARs) to employees. These awards allow the employee to receive any intrinsic value over the $47.60 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 of June 30, 2006, there are 132,800 SARs outstanding. The aggregate intrinsic value of these awards is $0.2 million at June 30, 2006. 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 and Six Months Ended June 30,2006
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 six months of 2006 for these SARs is $0.4 million. As no SARs were outstanding in the first half of 2005, no compensation expense was recorded for this type of award. In addition, all SARs were unvested at June 30, 2006. Unamortized expense as of June 30, 2006 for all outstanding SARs is $1.5 million which will be recognized over the next 2.7 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% 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 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 June 30, 2006 for the Monte Carlo model to value the liability components of the peer group measured performance share awards. The equity portion of the award granted in 2006 has already been valued on the date of grant using the Monte Carlo model and this portion is not marked to market.


	As of June 30, 2006
Risk Free Rate of Return	5.2	%
Stock Price Volatility	32.9	%
Correlation in stock price movement	90	%

The Monte Carlo value per share for the liability for performance share awards at June 30, 2006 ranged from $1.50 to $23.69. The long-term liability, included in Other Liabilities in the Condensed Consolidated Balance Sheet, and short-term liability, included in Accrued Liabilities in the Condensed Consolidated Balance Sheet, for performance share awards at June 30, 2006 is $1.1 million and $0.3 million, respectively.

The following table is a summary of activity of performance share awards as of June 30, 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 June 30, 2006	473,150	$	30.05	1.4	$	23,184

⁽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 June 30, 2006 is $7.1 million and will be recognized over the next 1.4 years. Total compensation cost recognized for performance shares during the six months ended June 30, 2006 was $3.6 million.

12. CAPITAL STOCK

Increase in Authorized Shares

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. The Company correspondingly increased the number of shares of Series A Junior Participating Preferred Stock reserved for issuance from 800,000 to 1,200,000. The shares of Series A Junior Participating Preferred Stock are issuable pursuant to the Rights Agreement between the Company and The Bank of New York, as Rights Agent.

Treasury Stock

In August 1998, the Company announced that its Board of Directors authorized the repurchase of two million shares of the Company’s 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. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company.

During the six months ended June 30, 2006, the Company repurchased 666,200 shares with a weighted average price per share of $40.81 for a total cost of approximately $27.2 million. All of the repurchases occurred during the second quarter. The repurchased shares are held as treasury stock. Since the authorization date, the Company has repurchased 2,180,050 shares, or 73% of the total shares authorized for repurchase, for a total cost of approximately $66.4 million.

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 June 30, 2006, and the related condensed consolidated statement of operations for each of the three and six month periods ended June 30, 2006 and 2005 and the condensed consolidated statement of cash flows for the six month periods ended June 30, 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 information 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

July 26, 2006

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

The following review of operations for the three and six month periods ended June 30, 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 $80.6 million, or 37%, for the six months ended June 30, 2006 as compared to the six months ended June 30, 2005. The increase is due to higher realized natural gas prices as well as increased production in the Gulf Coast, East and Canada. Oil revenues increased by $17.9 million, or 50%, for the first half of 2006 as compared to the first half of 2005. This increase is primarily due to an increase in oil prices in the first six months of 2006 as compared to the first six months of 2005. Additionally, crude oil revenues for the first half of 2005 included an unrealized loss on crude oil derivatives of $3.9 million, and there was no unrealized impact in the first half 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 10% in the first six months of 2006.

In the first six 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 $7.46 per Mcf, 27% higher than the $5.86 per Mcf price realized in the same period of the prior year. Our realized crude oil price was $64.88 per Bbl, 51% higher than the $42.96 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 six months ended June 30, 2006, we produced 44.8 Bcfe compared to production of 42.4 Bcfe for the comparable period of the prior year. Natural gas production was 39.8 Bcf and oil production was 830 Mbbls. Natural gas production increased by approximately 8% when compared to the comparable period of the prior year, which had production of 36.8 Bcf. Our East region improved natural gas production with the success of our drilling program. The Gulf Coast region also had increased production from the prior year period due to a successful 2006 drilling program as well as an offshore well that commenced production in the second quarter of 2006. 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 West region as a result of pipeline and compression curtailments and natural production declines. Oil production decreased by 97 Mbbls from 927 Mbbls in the first six months of 2005 to 830 Mbbls produced in the first six months of 2006. Oil production increased in the West, remained flat in the East and decreased in the Gulf Coast and Canada. The primary reason for the production decrease is from a decrease in Gulf Coast production due to the continued natural decline of the CL&F lease in south Louisiana.

We had net income of $100.0 million, or $2.05 per share, for the six months ended June 30, 2006 compared to net income of $56.2 million, or $1.15 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 $40.0 million and an increase in income tax expense of $23.4 million in the first half of 2006 as compared to the first half of 2005. In addition, current year expense includes a $0.4 million, net of tax, charge 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. For the second half of 2006, we expect to spend approximately $176 million in capital and exploration expenditures. Our annual capital budget of

$435 million was increased by $39 million from the $396 million figure previously reported in our Form 10-K in order to reflect increased drilling costs as well as new projects. For the six months ended June 30, 2006, approximately $259 million of capital and exploration expenditures have been invested in our exploration and development efforts.

During the six months ended June 30, 2006, we drilled 191 gross wells (176 development, 12 exploratory and 3 extension wells) with a success rate of 97% compared to 141 gross wells (123 development, 15 exploratory and 3 extension wells) with a success rate of 94% 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 substitution of horizontal drilling for traditional vertical wells in the East.

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.

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 six months ended June 30, 2006 was from funds generated from operations. We generate cash 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 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, purchase treasury stock and pay dividends. See below for additional discussion and analysis of cash flow.


	Six Months Ended June 30,
*(In thousands)*	2006			2005
Cash Flows Provided by Operating Activities	$	269,360		$	188,076
Cash Flows Used in Investing Activities		(250,299	)		(145,869	)
Cash Flows Used in Financing Activities		(13,628	)		(287	)

Net Increase in Cash and Cash Equivalents	$	5,433		$	41,920

Operating Activities. Net cash provided by operating activities in the first six months of 2006 increased $81.3 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 27% over the 2005 period, while crude oil realized prices increased 51% over the same period. Production volumes increased with approximately a 6% increase in equivalent production in the first half of 2006 compared to the comparable period in 2005. While we believe 2006 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 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 increased by $104.4 million for the six months ended June 30, 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 in financing activities were $13.6 million for the six months ended June 30, 2006 primarily due to payments made to purchase treasury stock and for dividend payments. Partially offsetting these cash uses were inflows from net increase in borrowings under our revolving credit facility, the exercise of stock options and the tax benefit received from stock-based compensation. Cash flows used in financing activities were $0.3 million for the six months ended June 30, 2005. Cash flows used in financing activities in the first six months of 2005 were the result of dividend payments and purchases of treasury stock, partially offset by proceeds from the exercise of stock options.

At June 30, 2006, we had $100 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 six months of 2006, we repurchased 666,200 shares of our common stock at a weighted average price of $40.81. All of the repurchases occurred during the second quarter. 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 June 30, 2006 is 819,950. See “Unregistered Sales of Equity Securities – Issuer Purchases of Equity Securities” in Item 2 of Part II of this quarterly report.

Capitalization

Our capitalization information is as follows:


*(In millions)*	June 30, 2006			December 31, 2005
Debt⁽¹⁾	$	350.0		$	340.0
Stockholders’ Equity		712.1			600.2

Total Capitalization	$	1,062.1		$	940.2

Debt to Capitalization		33	%		36	%
Cash and Cash Equivalents	$	16.1		$	10.6

⁽¹⁾

Includes $20.0 million of current portion of long-term debt at both June 30, 2006 and December 31, 2005. Includes $100 million and $90 million of borrowings under our revolving credit facility at June 30, 2006 and December 31, 2005, respectively.

During the six months ended June 30, 2006, we paid dividends of $3.9 million on our common stock. A regular dividend of $0.04 per share of common stock has been declared for each quarter since we became a public company in 1990.

Increase in Authorized Shares

On May 4, 2006, our stockholders approved an increase in the authorized number of shares of our common stock from 80 million to 120 million shares. We correspondingly increased the number of shares of Series A Junior Participating Preferred Stock reserved for issuance from 800,000 to 1,200,000. The shares of Series A Junior Participating Preferred Stock are issuable pursuant to our Rights Agreement with The Bank of New York, as Rights Agent.

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 six months ended June 30, 2006 and 2005.


	Six Months Ended June 30,
*(In millions)*	2006		2005
Capital Expenditures
Drilling and Facilities	$	192.0	$	99.4
Leasehold Acquisitions		29.1		8.0
Pipeline and Gathering		10.3		7.3
Other		1.0		0.7

		232.4		115.4

Proved Property Acquisitions		0.3		0.9
Exploration Expense		26.4		30.7

Total	$	259.1	$	147.0

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 June 30, 2005 to June 30, 2006 is the result of several new exploratory resource areas in all regions. 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 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 six months ended June 30, 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 six months ended June 30, 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 half 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 $0.4 million, before the effect of taxes, for the first half of 2006. 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 $0.4 million, before the effect of taxes, for the first half of 2006. In addition, we incurred a $0.4 million, net of tax, cumulative effect charge in the first quarter of 2006 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 made one modification to our stock option awards in 2005. It 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 reduced our compensation expense related to these options by approximately $0.2 million for 2006.

Results of Operations

Second Quarters of 2006 and 2005 Compared

We reported net income in the second quarter of 2006 of $46.9 million, or $0.96 per share. During the corresponding quarter of 2005, we reported net income of $35.4 million, or $0.72 per share. Net income increased in the current quarter by $11.4 million due to an increase in operating income partially offset by an increase of $3.9 million in income tax expense. Operating income increased $16.2 million compared to the prior year, from $61.7 million in the second quarter of 2005 to $77.9 million in the second 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 $6.77 per Mcf for the three months ended June 30, 2006 compared to $6.02 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 $0.34 per Mcf in 2006 and reduced the price by $0.61 per Mcf in 2005. The following table excludes the unrealized gain from the change in derivative fair value of $0.8 million for the three months ended June 30, 2005. There was no unrealized impact from the change in derivative fair value for the three months ended June 30, 2006. The unrealized change in fair value has been included in Natural Gas Production Revenues in the Statement of Operations.


	Three Months Ended June 30,				Variance
	2006		2005		Amount		Percent
Natural Gas Production (Mmcf)
Gulf Coast		8,604		7,353		1,251	17	%
West		5,759		5,690		69	1	%
East		5,885		5,083		802	16	%
Canada		649		332		317	95	%

Total Company		20,897		18,458		2,439	13	%

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	7.00	$	6.14	$	0.86	14	%
West	$	5.73	$	5.47	$	0.26	5	%
East	$	7.58	$	6.54	$	1.04	16	%
Canada	$	5.63	$	4.53	$	1.10	24	%
Total Company	$	6.77	$	6.02	$	0.75	12	%

Natural Gas Production Revenue (in thousands)
Gulf Coast	$	60,198	$	45,178	$	15,020	33	%
West		33,026		31,108		1,918	6	%
East		44,623		33,241		11,382	34	%
Canada		3,656		1,508		2,148	142	%

Total Company	$	141,503	$	111,035	$	30,468	27	%

Price Variance Impact on Natural Gas Production Revenue
(in thousands)
Gulf Coast	$	7,414
West		1,559
East		6,270
Canada		746

Total Company	$	15,989

Volume Variance Impact on Natural Gas Production Revenue
(in thousands)
Gulf Coast	$	7,606
West		241
East		5,224
Canada		1,408

Total Company	$	14,479

The increase in Natural Gas Production Revenue is primarily due to the increase in natural gas sales prices and the increase in natural gas production. Prices and production were higher in all regions in the second quarter of 2006 compared to the second quarter of 2005. Increased production is primarily the result of increased successful drilling activity in the second quarter of 2006 compared to the comparable prior year period. The increase in the realized natural gas price and production resulted in a net revenue increase of $30.5 million, excluding the unrealized impact of derivative instruments.

Brokered Natural Gas Revenue and Cost


	Three Months Ended June 30,					Variance
	2006			2005		Amount		Percent
Sales Price ($/Mcf)	$	7.70		$	7.60	$	0.10	1	%
Volume Brokered (Mmcf)		2,273			2,041		232	11	%

Brokered Natural Gas Revenues (in thousands)	$	17,495		$	15,520

Purchase Price ($/Mcf)	$	6.77		$	6.71	$	0.06	1	%
Volume Brokered (Mmcf)		2,273			2,041		232	11	%

Brokered Natural Gas Cost (in thousands)	$	15,397		$	13,701

Brokered Natural Gas Margin (in thousands)	$	2,098		$	1,819	$	279	15	%

(in thousands)
Sales Price Variance Impact on Revenue	$	369
Volume Variance Impact on Revenue		1,633

	$	2,002

(in thousands)
Purchase Price Variance Impact on Purchases	$	(261	)
Volume Variance Impact on Purchases		(1,462	)

	$	(1,723	)

The increased brokered natural gas margin of $0.3 million was driven by an increased sales price that outpaced the increase in purchase cost as well as an increase in brokered volumes.

Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price was $68.32 per Bbl for the second quarter of 2006. There was no realized impact of derivative instruments in the second quarter of 2006. Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $43.76 per Bbl for the second quarter of 2005. The 2005 price includes the realized impact of derivative instrument settlements which reduced the price by $6.98 per Bbl. The following table excludes the unrealized gain from the change in derivative fair value of $3.0 million for the second quarter of 2005. There was no unrealized impact from the change in derivative fair value for the second quarter of 2006. The unrealized change in fair value has been included in Crude Oil and Condensate Revenues in the Statement of Operations.


	Three Months Ended June 30,					Variance
	2006			2005		Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		369			421		(52	)	(12	)%
West		56			43		13		30	%
East		6			8		(2	)	(25	)%
Canada		3			5		(2	)	(40	)%

Total Company		434			477		(43	)	(9	)%

Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	68.58		$	42.86	$	25.72		60	%
West	$	65.92		$	52.27	$	13.65		26	%
East	$	66.51		$	50.32	$	16.19		32	%
Canada	$	84.24		$	35.43	$	48.81		138	%
Total Company	$	68.32		$	43.76	$	24.56		56	%

Crude Oil Revenue (in thousands)
Gulf Coast	$	25,293		$	18,045	$	7,248		40	%
West		3,677			2,284		1,393		61	%
East		429			373		56		15	%
Canada		269			185		84		45	%

Total Company	$	29,668		$	20,887	$	8,781		42	%

Price Variance Impact on Crude Oil Revenue
(in thousands)
Gulf Coast	$	9,552
West		703
East		102
Canada		159

Total Company	$	10,516

Volume Variance Impact on Crude Oil Revenue
(in thousands)
Gulf Coast	$	(2,253	)
West		698
East		(95	)
Canada		(85	)

Total Company	$	(1,735	)

The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $8.8 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is mainly 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 June 30,
	2006				2005
	Realized		Unrealized		Realized			Unrealized
	*(In thousands)*
Operating Revenues - Increase/(Decrease) to Revenue Cash Flow Hedges
Natural Gas Production	$	7,197	$	—	$	(11,266	)	$	782
Crude Oil		—		—		(259	)		25

Total Cash Flow Hedges		7,197		—		(11,525	)		807
Other Derivative Financial Instruments
Crude Oil		—		—		(3,069	)		3,024

Total Other Derivative Financial Instruments		—		—		(3,069	)		3,024

	$	7,197	$	—	$	(14,594	)	$	3,831

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 increased by $1.5 million between the second quarter of 2006 and the second quarter of 2005 primarily due to an increase in net profits interest that originated in 2006.

Operating Expenses

Total costs and expenses from operations increased $22.7 million in the second quarter of 2006 compared to the same period of 2005. The primary reasons for this fluctuation are as follows:

•

Depreciation, Depletion and Amortization increased by $6.7 million in the second 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 $4.8 million in the second quarter of 2006. This increase is primarily due to increased stock compensation costs of $2.6 million. During the second quarter of 2006, performance share and restricted stock amortization expense increased by $0.4 million and $1.9 million, respectively, primarily due to new grants issued in 2006. Expense related to SARs, which were granted for the first time in 2006, and stock options, which are being expensed in 2006 due to the adoption of SFAS No. 123(R), increased by $0.3 million in total. In addition, there was an increase of $2.2 million in litigation expenses in the current quarter.

•

Direct Operations expense increased by $3.6 million over the second quarter of 2005. This is primarily the result of an increase over the prior year quarter in compressor expenses, lease equipment and maintenance, workover, disposal costs and treating costs. These increases were primarily seen in the Gulf Coast region due to additional usage, rates and production in addition to timing. In addition, we incurred higher insurance expenses due to premium increases as well as higher expenses for incentive compensation and employee related expenses.

•

Exploration expense increased by $3.4 million in the second quarter of 2006, primarily as a result of increased dry hole expense in the Gulf Coast region and, to a lesser extent, Canada.

•

Taxes Other Than Income increased by $2.2 million compared to the second 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.

•

Brokered Natural Gas Cost increased by $1.7 million from the second quarter of 2005 to the second quarter of 2006. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.

Interest Expense, Net

Interest expense, net increased $1.0 million in the second quarter of 2006 due to higher credit facility borrowings as well as an increasing interest rate environment. Weighted average borrowings based on daily balances were approximately $59.8 million during the second quarter of 2006. There were no borrowings outstanding under the facility during the second quarter of 2005.

Income Tax Expense

Income tax expense increased by $3.9 million due to a comparable increase in our pre-tax income. The effective tax rate for the second quarter of 2006 and 2005 was 34.8% and 37.4%, 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.

Six Months of 2006 and 2005 Compared

We reported net income in the first half of 2006 of $100.0 million, or $2.05 per share. During the corresponding period of 2005, we reported net income of $56.2 million, or $1.15 per share. Net income increased in the current period by $43.8 million due to an increase in operating income partially offset by an increase of $23.4 million in income tax expense. Operating income increased $69.7 million compared to the prior year, from $99.8 million in the first six months of 2005 to $169.5 million in the first six months 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 $7.46 per Mcf for the six months ended June 30, 2006 compared to $5.86 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 $0.22 per Mcf in 2006 and reduced the price by $0.47 per Mcf in 2005. The following table excludes the unrealized gain from the change in derivative fair value of $0.2 million for the six months ended June 30, 2005. There was no unrealized impact from the change in derivative fair value for the six months ended June 30, 2006. The unrealized change in fair value has been included in Natural Gas Production Revenues in the Statement of Operations.


	Six Months Ended June 30,					Variance
	2006			2005		Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		15,852			14,674		1,178		8	%
West		11,149			11,375		(226	)	(2	)%
East		11,650			10,216		1,434		14	%
Canada		1,126			554		572		103	%

Total Company		39,777			36,819		2,958		8	%

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	7.55		$	6.09	$	1.46		24	%
West	$	6.38		$	5.10	$	1.28		25	%
East	$	8.44		$	6.44	$	2.00		31	%
Canada	$	6.68		$	4.95	$	1.73		35	%
Total Company	$	7.46		$	5.86	$	1.60		27	%

Natural Gas Production Revenue (in thousands)
Gulf Coast	$	119,673		$	89,295	$	30,378		34	%
West		71,183			58,000		13,183		23	%
East		98,289			65,829		32,460		49	%
Canada		7,525			2,743		4,782		174	%

Total Company	$	296,670		$	215,867	$	80,803		37	%

Price Variance Impact on Natural Gas Production Revenue
(in thousands)
Gulf Coast	$	23,212
West		14,225
East		23,334
Canada		1,953

Total Company	$	62,724

Volume Variance Impact on Natural Gas Production Revenue
(in thousands)
Gulf Coast	$	7,166
West		(1,154	)
East		9,238
Canada		2,829

Total Company	$	18,079

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 Gulf Coast, East and Canada. Decreased production in the West was due to natural declines as well as lower production on a small number of non-operated wells. The increase in the total realized natural gas price and production resulted in a net revenue increase of $80.8 million, excluding the unrealized impact of derivative instruments.

Brokered Natural Gas Revenue and Cost


	Six Months Ended June 30,					Variance
	2006			2005		Amount		Percent
Sales Price ($/Mcf)	$	8.62		$	7.27	$	1.35	19	%
Volume Brokered (Mmcf)		5,839			5,779		60	1	%

Brokered Natural Gas Revenues (in thousands)	$	50,314		$	42,012

Purchase Price ($/Mcf)	$	7.65		$	6.40	$	1.25	20	%
Volume Brokered (Mmcf)		5,839			5,779		60	1	%

Brokered Natural Gas Cost (in thousands)	$	44,642		$	36,999

Brokered Natural Gas Margin (in thousands)	$	5,672		$	5,013	$	659	13	%

(in thousands)
Sales Price Variance Impact on Revenue	$	7,893
Volume Variance Impact on Revenue		436

	$	8,329

(in thousands)
Purchase Price Variance Impact on Purchases	$	(7,286	)
Volume Variance Impact on Purchases		(384	)

	$	(7,670	)

The increased brokered natural gas margin of $0.7 million was driven by an increased sales price that outpaced the increase in purchase cost and the increase in brokered volumes.

Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price was $64.88 per Bbl for the first half of 2006. There was no realized impact of derivative instruments in the first six months of 2006. Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $42.96 per Bbl for the first half of 2005. The 2005 price includes the realized impact of derivative instrument settlements which reduced the price by $6.37 per Bbl. The following table excludes the unrealized loss from the change in derivative fair value of $3.9 million for the first six months of 2005. There was no unrealized impact from the change in derivative fair value for the first six months of 2006. The unrealized change in fair value has been included in Crude Oil and Condensate Revenues in the Statement of Operations.


	Six Months Ended June 30,					Variance
	2006			2005		Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		700			826		(126	)	(15	)%
West		110			79		31		39	%
East		13			13		—		—
Canada		7			9		(2	)	(22	)%

Total Company		830			927		(97	)	(10	)%

Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	65.17		$	42.19	$	22.98		54	%
West	$	63.31		$	50.61	$	12.70		25	%
East	$	62.68		$	49.37	$	13.31		27	%
Canada	$	65.15		$	36.83	$	28.32		77	%
Total Company	$	64.88		$	42.96	$	21.92		51	%

Crude Oil Revenue (in thousands)
Gulf Coast	$	45,577		$	34,833	$	10,744		31	%
West		6,980			4,010		2,970		74	%
East		841			634		207		33	%
Canada		450			340		110		32	%

Total Company	$	53,848		$	39,817	$	14,031		35	%

Price Variance Impact on Crude Oil Revenue
(in thousands)
Gulf Coast	$	16,115
West		1,401
East		179
Canada		196

Total Company	$	17,891

Volume Variance Impact on Crude Oil Revenue
(in thousands)
Gulf Coast	$	(5,324	)
West		1,570
East		(21	)
Canada		(85	)

Total Company	$	(3,860	)

The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $14.0 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is primarily 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:


	Six Months Ended June 30,
	2006				2005
	Realized		Unrealized		Realized			Unrealized
	*(In thousands)*
Operating Revenues - Increase/(Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	8,634	$	—	$	(17,488	)	$	222
Crude Oil		—		—		(387	)		(78	)

Total Cash Flow Hedges		8,634		—		(17,875	)		144
Other Derivative Financial Instruments
Crude Oil		—		—		(5,522	)		(3,825	)

Total Other Derivative Financial Instruments		—		—		(5,522	)		(3,825	)

	$	8,634	$	—	$	(23,397	)	$	(3,681	)

Other Operating Revenues

Other operating revenues increased by $2.8 million between the first six months of 2006 and the first six months of 2005 primarily due to an increase in our net profits interest in the second quarter as well as a decrease in our payout liability associated with a favorable legal ruling in the first quarter. This variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year period.

Operating Expenses

Total costs and expenses from operations increased $40.0 million in the first half of 2006 compared to the same period of 2005. The primary reasons for this fluctuation are as follows:

•

Depreciation, Depletion and Amortization increased by $12.0 million in the first six months of 2006. This is primarily due to increased production in the current year 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 $9.7 million in the first half of 2006. This increase is primarily due to increased stock compensation costs of $6.1 million. During the first half of 2006, performance share and restricted stock amortization expense increased by $3.5 million and $2.1 million, respectively, primarily due to new grants issued in 2006. For the first half of the year, expense related to SARs, which were granted for the first time in 2006, and stock options, which are being expensed in 2006 due to the adoption of SFAS No. 123(R), increased by $0.5 million in total. In addition, there was an increase in litigation expense, incentive compensation related to employee bonuses and insurance expense over the first half of the prior year.

•

Taxes Other Than Income increased by $8.0 million compared to the first six months of 2005, primarily due to increased production taxes as a result of increased commodity prices as well as an increase in ad valorem taxes.

•

Brokered Natural Gas Cost increased by $7.6 million from the first half of 2005 to the second quarter of 2006. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.

•

Direct Operations expense increased by $6.7 million over the first half of 2005. This is primarily the result of an increase over the prior year period in outside operated properties expense, compressor expense, expenses for incentive compensation and employee related charges. 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. The increase in compressor expense is also primarily due to an increase in the Gulf Coast and East regions.

•

Exploration expense decreased by $4.3 million in the first six months of 2006, primarily as a result of decreased dry hole expense partially offset by increased geological and geophysical costs. During the first six months of 2006, we incurred $7.0 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 half of 2006 compared to the first half of 2005 and, to a lesser extent, better success in Canada and the West region, compared to the first half of 2005. Geological and geophysical costs increased by $1.2 million over the prior year period primarily due to increased expenses in the Gulf Coast. Additionally, employee expenses for salaries and benefits in this group increased by $0.7 million, and expenses for delay rentals and various other lease and land charges increased by $0.5 million from the first half of 2005.

Interest Expense, Net

Interest expense, net increased $2.1 million in the first half of 2006 due to higher credit facility borrowings as well as an increasing interest rate environment. Weighted average borrowings based on daily balances were approximately $64.4 million during the first six months of 2006. There were no borrowings outstanding under the facility during the first six months of 2005.

Income Tax Expense

Income tax expense increased by $23.4 million due to a comparable increase in our pre-tax income. The effective tax rate for the first six months of 2006 and 2005 was 36.2% and 37.3%, 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.

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.

In July 2006, the FASB issued FASB Interpretation (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 threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect that this Interpretation will have a material impact on our financial position, results of operations or cash flows.

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 six months of 2006, natural gas price collars covered 13,478 Mmcf, or 34%, 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 June 30, 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 *(In thousands)*
As of June 30, 2006
Third Quarter 2006	6,850	$	12.74 / $8.25
Fourth Quarter 2006	6,851		12.74 / 8.25

Six Months Ended December 31, 2006	13,701	$	12.74 / $8.25	$	17,286

First Quarter 2007	7,462	$	12.16 / $8.83
Second Quarter 2007	7,545		12.16 / 8.83
Third Quarter 2007	7,628		12.16 / 8.83
Fourth Quarter 2007	7,628		12.16 / 8.83

Full Year 2007	30,263	$	12.16 / $8.83	$	11,481

During the first six months of 2006, crude oil price collars covered 181 Mbbls, or 22%, 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 June 30, 2006, we had open crude oil price collar contracts covering our 2006 and 2007 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 June 30, 2006
Third Quarter 2006	92	$	76.00 / $50.00
Fourth Quarter 2006	92		76.00 / 50.00

Six Months Ended December 31, 2006	184	$	76.00 / $50.00	$	(637	)

First Quarter 2007	90	$	80.00 / $60.00
Second Quarter 2007	91		80.00 / 60.00
Third Quarter 2007	92		80.00 / 60.00
Fourth Quarter 2007	92		80.00 / 60.00

Full Year 2007	365	$	80.00 / $60.00	$	(1,246	)

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 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 2006	—	$	—	—	1,486,150
May 2006	84,100	$	42.16	84,100	1,402,050
June 2006	582,100	$	40.61	582,100	819,950

Total	666,200	$	40.81

ITEM 4. Submission of Matters to a Vote of Security Holders

On May 4, 2006, the Company held its Annual Meeting of Stockholders. At this meeting, the Company’s stockholders voted on the following three matters:

•

the election of three directors,

•

the amendment to the Company’s Certificate of Incorporation to increase the authorized Common Stock of the Company from 80,000,000 shares to 120,000,000 shares, and

•

the ratification of the appointment of PricewaterhouseCoopers LLP, as the independent registered public accounting firm for the Company for its 2006 fiscal year.

Of the 48,773,307 shares entitled to vote, 45,587,597 were present at the meeting in person or represented by proxy. Below are the results of the voting.

Shareholders voted to re-elect three directors by the following vote:


James G. Floyd
For:		45,390,568
Withheld:		197,029

Robert Kelley
For:		44,731,317
Withheld:		856,280

P. Dexter Peacock
For:		45,391,024
Withheld:		196,571

The terms of office of directors John G.L. Cabot, David M. Carmichael, Dan O. Dinges, Robert R. Keiser and William P. Vititoe continued beyond the meeting date.

Shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to increase the authorized Common Stock of the Company from 80,000,000 shares to 120,000,000 shares by the following vote:


For		44,007,610
Against		1,561,403
Abstain		18,584
Broker Non-votes		0

Shareholders voted to ratify the appointment of PricewaterhouseCoopers LLP, as the independent registered public accounting firm for the Company for its 2006 fiscal year by the following vote:


For		45,352,128
Against		216,982
Abstain		18,487
Broker Non-votes		0

ITEM 6. Exhibits


* 3.1		Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1, Registration No. 33-32553).

*3.2		Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated July 1, 2002).

*3.3		Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated July 1, 2002).

*3.4		Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated June 1, 2006).

*3.5		Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated June 1, 2006).

*10.1		Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-8, Registration No. 333-135365).

*10.2		Form of Conveyance of Mineral and/or Royalty Interest (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-8, Registration No. 333-135365).

*10.3		Form of Conveyance of Overriding Royalty Interest (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-8, Registration No. 333-135365).

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

*	Incorporated by reference as indicated

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)

July 26, 2006	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and
		Chief Executive Officer
		(Principal Executive Officer)

July 26, 2006	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

July 26, 2006	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)