CABOT OIL & GAS CORP - 10-Q Quarterly Report

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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2003

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		(I.R.S. Employer
incorporation or organization)		Identification Number)

1200 Enclave Parkway, Houston, Texas 77077

(Address of principal executive offices including Zip Code)

(281) 589-4600

(Registrant’s telephone number)

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 an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes x No ¨

As of July 28, 2003, there were 32,172,457 shares of Common Stock, Par Value $.10 Per Share, outstanding.

CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

Part I. Financial Information		Page

Item 1. Financial Statements

Condensed Consolidated Statement of Operations for the Three-Months and Six-Months Ended June 30, 2003, and 2002		3

Condensed Consolidated Balance Sheet at June 30, 2003 and December 31, 2002		4

Condensed Consolidated Statement of Cash Flows for the Three-Months and Six-Months Ended June 30, 2003 and 2002		5

Notes to the Condensed Consolidated Financial Statements		6

Report of Independent Accountant’s Review of Interim Financial Information		16

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3. Quantitative and Qualitative Disclosures about Market Risk		27

Item 4. Controls and Procedures		29

Part II. Other Information

Item 4. Submission of Matters to a Vote of Security Holders		30

Item 6. Exhibits and Reports on Form 8-K		31

Signatures		32

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

(In Thousands, Except Per Share Amounts)

	THREE MONTHS ENDED JUNE 30,						SIX MONTHS ENDED JUNE 30,
	2003			2002			2003			2002
NET OPERATING REVENUES
Natural Gas Production	$	81,113		$	55,300		$	159,286		$	101,806
Brokered Natural Gas		23,370			15,687			55,220			29,385
Crude Oil and Condensate		20,663			17,348			43,837			31,066
Change in Derivative Fair Value (Note 8)		(650	)		(564	)		(1,194	)		(1,180	)
Other		2,260			1,813			5,523			3,580

		126,756			89,584			262,672			164,657
OPERATING EXPENSES
Brokered Natural Gas Cost		21,539			14,581			49,800			26,848
Direct Operations—Field and Pipeline		13,825			11,921			24,751			24,156
Exploration		15,663			10,824			29,054			17,880
Depreciation, Depletion and Amortization		23,764			23,453			47,271			46,663
Impairment of Unproved Properties		2,337			2,337			4,674			4,674
Impairment of Long-Lived Assets (Note 11)		—			—			87,926			1,063
General and Administrative		6,172			9,572			12,767			15,311
Taxes Other Than Income		8,651			7,475			18,875			13,627

		91,951			80,163			275,118			150,222
Gain on Sale of Assets		45			429			605			411

INCOME (LOSS) FROM OPERATIONS		34,850			9,850			(11,841	)		14,846
Interest Expense and Other		5,952			6,331			11,577			12,557

Income (Loss) Before Income Taxes		28,898			3,519			(23,418	)		2,289
Income Tax Expense (Benefit)		10,994			1,398			(8,946	)		966

NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		17,904			2,121			(14,472	)		1,323
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 12)		—			—			(6,847	)		—
NET INCOME (LOSS)	$	17,904		$	2,121		$	(21,319	)	$	1,323

Basic Earnings (Loss) Per Share—Before Accounting Change	$	0.56		$	0.07		$	(0.45	)	$	0.04
Diluted Earnings (Loss) Per Share—Before Accounting Change	$	0.55		$	0.07		$	(0.45	)	$	0.04
Basic Loss Per Share—Accounting Change	$	—		$	—		$	(0.22	)	$	—
Diluted Loss Per Share—Accounting Change	$	—		$	—		$	(0.22	)	$	—
Basic Earnings (Loss) Per Share	$	0.56		$	0.07		$	(0.67	)	$	0.04
Diluted Earnings (Loss) Per Share	$	0.55		$	0.07		$	(0.67	)	$	0.04
Average Common Shares Outstanding		31,980			31,737			31,909			31,671

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, 2003			DECEMBER 31, 2002
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,262		$	2,561
Accounts Receivable		85,158			70,028
Inventories		9,960			15,252
Other		11,617			5,280

Total Current Assets		109,997			93,121
Properties and Equipment, Net (Successful Efforts Method)		890,535			971,754
Other Assets		6,799			7,013

	$	1,007,331		$	1,071,888

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	98,196		$	73,578
Accrued Liabilities		70,977			48,312

Total Current Liabilities		169,173			121,890
Long-Term Debt		304,000			365,000
Deferred Income Taxes		160,549			200,207
Other Liabilities		57,855			34,134
Stockholders’ Equity
Common Stock:
Authorized—80,000,000 Shares of $.10 Par Value Issued and Outstanding—32,473,091 Shares and 32,133,118 Shares in 2003 and 2002, Respectively		3,247			3,213
Additional Paid-in Capital		358,577			353,093
Retained Earnings (Accumulated Deficit)		(12,113	)		11,674
Accumulated Other Comprehensive Loss (Note 9)		(29,573	)		(12,939	)
Less Treasury Stock, at Cost:
302,600 Shares in 2003 and 2002		(4,384	)		(4,384	)

Total Stockholders’ Equity		315,754			350,657

	$	1,007,331		$	1,071,888

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

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

(In Thousands)

	THREE MONTHS ENDED JUNE 30,						SIX MONTHS ENDED JUNE 30,
	2003			2002			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	17,904		$	2,121		$	(21,319	)	$	1,323
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Cumulative Effect of Accounting Change		—			—			6,847			—
Depletion, Depreciation and Amortization		23,764			23,453			47,271			46,663
Impairment of Unproved Properties		2,337			2,337			4,674			4,674
Impairment of Long-Lived Assets		—			—			87,926			1,063
Deferred Income Tax Expense		1,762			422			(25,248	)		(49	)
Gain on Sale of Assets		(45	)		(429	)		(605	)		(411	)
Exploration Expense		15,663			10,824			29,054			17,880
Change in Derivative Fair Value		650			564			1,194			1,180
Other		472			1,542			333			2,907
Changes in Assets and Liabilities:
Accounts Receivable		23,312			(1,080	)		(15,130	)		(2,004	)
Inventories		(304	)		(3,086	)		5,292			2,409
Other Current Assets		(4,991	)		839			(5,612	)		(2,396	)
Other Assets		415			(115	)		214			(22	)
Accounts Payable and Accrued Liabilities		2,122			21,216			25,110			15,116
Other Liabilities		(2,804	)		(5,129	)		(197	)		(5,304	)

Net Cash Provided by Operating Activities		80,257			53,479			139,804			83,029

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(30,078	)		(30,126	)		(51,399	)		(71,188	)
Proceeds from Sale of Assets		758			3,445			2,360			3,443
Exploration Expense		(15,663	)		(10,824	)		(29,054	)		(17,880	)

Net Cash Used by Investing Activities		(44,983	)		(37,505	)		(78,093	)		(85,625	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		67,000			44,000			131,000			100,000
Decrease in Debt		(101,000	)		(59,000	)		(192,000	)		(96,000	)
Sale of Common Stock		1,960			3,031			2,458			3,136
Dividends Paid		(1,195	)		(1,271	)		(2,468	)		(2,536	)

Net Cash Provided (Used) by Financing Activities		(33,235	)		(13,240	)		(61,010	)		4,600

Net Increase in Cash and Cash Equivalents		2,039			2,734			701			2,004
Cash and Cash Equivalents, Beginning of Period		1,223			4,976			2,561			5,706

Cash and Cash Equivalents, End of Period	$	3,262		$	7,710		$	3,262		$	7,710

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 Report on Form 10-K 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 to Stockholders 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 accountants have performed a review of these condensed consolidated interim financial statements in accordance with standards established by the American Institute of Certified Public Accountants. 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.

Certain prior year amounts have been reclassified to conform to current year presentation. These reclassifications had no effect on the Company’s financial position, results of operations or cash flows.

In June 2001, the FASB approved for issuance Statement of Financial Accounting Standard (SFAS) 143, “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The adoption of SFAS 143 resulted in (1) an increase of total liabilities, because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets, because the retirement costs are added to the carrying amount of the long-lived asset, and (3) an increase in operating expense, because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003. The impact on the financial statements of adopting SFAS 143 is disclosed in Note 12, “Adoption of SFAS 143, Accounting for Asset Retirement Obligations,” to the financial statements.

In December 2002, the FASB issued SFAS 148, “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS 148 amends FASB Statement 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. The Company is evaluating the adoption of the recognition provisions of SFAS 123, as amended by SFAS 148. The adoption of the recognition provisions would impact the Company’s financial position and results of operations. See Note 13, “Stock Based Compensation,” to the financial statements.

In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities—An Interpretation of Accounting Research Bulletin (ARB) 51” (FIN 46 or Interpretation). FIN 46 is an interpretation of ARB 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time there is only one entity that could potentially be a VIE. The Company is evaluating this potential VIE, in which the Company has a one percent general partner interest and which holds an interest in the Kurten field, to determine if it is a VIE. However, pursuant to the partnership agreement, the limited partner has elected to liquidate the partnership; it is anticipated that this liquidation will be completed prior to the effective date of the Interpretation. See Note 11 for additional information related to the partnership.

2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:

	JUNE 30, 2003			DECEMBER 31, 2002
	(In Thousands)
Unproved Oil and Gas Properties	$	86,618		$	76,959
Proved Oil and Gas Properties		1,517,004			1,459,240
Gathering and Pipeline Systems		138,716			137,137
Land, Building and Improvements		4,884			4,884
Other		29,894			29,457

		1,777,116			1,707,677
Accumulated Depreciation, Depletion and Amortization		(886,581	)		(735,923	)

	$	890,535		$	971,754

Prior to the adoption of SFAS 143 on January 1, 2003, future estimated plug and abandonment costs were accrued over the productive life of certain oil and gas properties when the residual value of well equipment was not sufficient to cover the plug and abandonment liability. The accrued liability for plug and abandonment costs was included in Accumulated Depreciation, Depletion and Amortization.

Total future plug and abandonment costs of $17.1 million and $1.1 million, recorded at December 31, 2002, have been reclassified from Accumulated Depreciation, Depletion and Amortization and Other Accrued Liabilities, respectively, to Other Long-Term Liabilities due to the adoption of SFAS 143 (see Note 12). These reclassifications were made to conform to the current period presentation.

See Note 11 for information regarding the impairment on the Kurten Field.

3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

	JUNE 30, 2003			DECEMBER 31, 2002
	(In Thousands)
Accounts Receivable
Trade Accounts	$	83,816		$	65,796
Joint Interest Accounts		4,649			6,601
Current Income Tax Receivable		1,570			2,479
Other Accounts		590			619

		90,625			75,495
Allowance for Doubtful Accounts		(5,467	)		(5,467	)

	$	85,158		$	70,028

Other Current Assets
Commodity Hedging Contracts—FAS 133	$	1,359		$	634
Drilling Advances		1,975			558
Prepaid Balances		6,198			2,131
Restricted Cash and Other Accounts		2,085			1,957

	$	11,617		$	5,280

Accounts Payable
Trade Accounts	$	22,489		$	13,317
Natural Gas Purchases		10,238			6,058
Royalty and Other Owners		29,781			20,254
Capital Costs		15,816			13,900
Taxes Other Than Income		3,157			3,076
Drilling Advances		7,276			7,254
Wellhead Gas Imbalances		2,300			2,817
Other Accounts		7,139			6,902

	$	98,196		$	73,578

Accrued Liabilities
Employee Benefits	$	6,000		$	8,751
Taxes Other Than Income		12,793			9,887
Interest Payable		6,425			7,076
Commodity Hedging Contracts—FAS 133		42,530			20,680
Other Accrued		3,229			1,918

	$	70,977		$	48,312

Other Liabilities
Postretirement Benefits Other Than Pension	$	1,924		$	1,843
Accrued Pension Cost		6,865			8,486
Commodity Hedging Contracts—FAS 133		6,900			—
Accrued Plugging and Abandonment Liability		36,372			18,151
Taxes Other Than Income and Other		5,794			5,654

	$	57,855		$	34,134

4. LONG-TERM DEBT

At June 30, 2003, the Company had $34 million outstanding under its credit facility, which provides for an available credit line of $250 million. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the bank’s petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. The revolving term under this credit facility presently ends in October 2006 and is subject to renewal. At June 30, 2003, excess capacity totaled $216 million, or 86% of the total available credit facility.

In addition to the credit facility, the Company has the following debt outstanding:

•

$100 million of 12-year 7.19% Notes to be repaid in five annual installments of $20 million beginning in November 2005

•

$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 for the second quarter were based on the quarterly weighted average shares outstanding of 31,980,279 in 2003 and 31,737,292 in 2002. Basic Earnings Per Share for the first six months of the year were based on the year-to-date weighted average shares outstanding of 31,908,789 in 2003 and 31,670,874 in 2002. The Diluted Earnings Per Share amounts are based on weighted average shares outstanding plus common stock equivalents. Second quarter common stock equivalents, which include both stock awards and stock options, totaled 496,746 in 2003 and 457,720 in 2002. For the year-to-date period ended June 30, the common stock equivalents were 443,596 in 2003 and 429,007 in 2002. Stock awards and stock options excluded from the calculation of Diluted Earnings Per Share because the effect was antidilutive were 1,226,401 and 1,168,871 for the second quarter of 2003 and 2002, respectively, and 1,706,346 and 1,197,584 for the year-to-date periods ended June 30, 2003 and 2002, respectively.

6. ENVIRONMENTAL LIABILITY

The EPA notified the Company in February 2000 of its potential liability for waste material disposed of at the Casmalia Superfund Site (“Site”), located on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1992. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for disposal of approximately 4.5 billion pounds of waste would be expected to pay the clean-up costs, which are estimated by the EPA to be $271.9 million. The EPA is also pursuing the owners/operators of the Site to pay for remediation.

The Company received documents with the notification from the EPA indicating that the Company used the Site principally to dispose of salt water from two wells over a period from 1976 to 1979. There is no allegation that the Company violated any laws in the disposal of material at the Site. The EPA’s actions stem from the fact that the owners/operators of the Site do not have the financial means to implement a closure plan for the Site.

A group of potentially responsible parties, including the Company, formed a group, called the Casmalia Negotiating Committee (“CNC”). The CNC has had extensive settlement discussions with the EPA and has entered into a consent decree, which will require the CNC to pay approximately $27 million toward Site clean up in return for a release from liability. On January 30, 2002, the Company placed $1,283,283 in an escrow account, representing its volumetric share of the CNC/United States settlement. This cash settlement, once released from escrow and paid to the federal government after

the consent decree is entered by the court, will resolve all federal claims against the Company for response costs and will release the Company from all response costs related to the Site, except for future claims against the Company for natural resource damage, unknown conditions, transshipment risks and claims by third parties. Most of the CNC, including the Company, have purchased insurance designed to protect the Company from these liabilities not covered by the consent decree.

The State of California, a third party, has asserted a claim against the CNC and other companies alleged to have waste at Casmalia for costs the State incurred and will incur at the site. The CNC has presented the claim to its insurer. The ultimate disposition of this claim is unknown. However, given the size of the State’s claim and the number of parties allegedly responsible, the Company’s share of this claim is not expected to be material.

The Company has established a reserve that management believes to be adequate to provide for this environmental liability and related legal costs.

7. COMMITMENTS AND CONTINGENCIES

Wyoming Royalty Litigation

In June 2000, the Company was sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs have requested class certification under the Wyoming Rules of Civil Procedure and allege that the Company has improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claims that the Company has failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. Settlement discussions continue between the parties.

In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification.

Although management believes that a number of the Company’s defenses are supported by Wyoming case law, a recent letter decision handed down by a state district court in another case does not support certain of the defenses. The decision has not been reduced to a formal order and it is not known what effect, if any, the decision will have on the pending cases.

In the Company’s federal case, the judge recently agreed to certify two questions of state law for decision by the Wyoming State Supreme Court. The Wyoming State Supreme Court has agreed to decide both questions, and these decisions should dispose of important issues in these cases. The federal judge refused, however, to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statute on overriding royalty owner check stubs that had been decided adversely to the Company’s position in the state district court letter decision. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon the plaintiffs expert witness report filed in March 2003, the plaintiffs are now claiming $21 million in total damages which can be broken down into $15.7 million for alleged violations of the check stub reporting statute and the remainder for all other damages. In the opinion of our outside counsel, Brown, Drew & Massey, LLP the likelihood of the plaintiffs recovering the stated damages for violation of the check stub reporting statute is remote.

The Company is vigorously defending both cases. The Company has a reserve that management believes is adequate to provide for these potential liabilities based on its estimate of the probable outcome of these matters. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact our financial position.

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 under the West Virginia Rules of Civil Procedure and allege that the Company failed to pay royalty based upon the wholesale market value of the gas produced, that the Company has taken improper deductions from the royalty and have failed to properly inform the plaintiffs and other similarly situated persons of deductions taken from the royalty. The plaintiffs have also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia in the 1995 Columbia bankruptcy proceeding.

The Company had removed the lawsuit to federal court; however, in February 2003, we received an order remanding the lawsuit back to state court. Discovery and pleadings necessary to place the class certification issue before the court have been ongoing. No trial or dispositive motion dates have been set and limited factual discovery is ongoing.

The investigation into this claim continues and it is in the discovery phase. The Company is vigorously defending the case. The Company has reserves it believes are adequate to provide for these potential liabilities based on its estimate of the probable outcome of this matter. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact the Company’s financial position.

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. The plaintiffs allege that they are the rightful owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC, the Company acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and the Company subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in the surface and 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, conversion, all for unspecified actual and exemplary damages. The trial date of May 19, 2003 has been cancelled and a new trial date has not been set. The Company has not had the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since its predecessor, Cody Energy, LLC, acquired title and since the Company acquired its lease is approximately $12 million. The carrying value of this property is approximately $35 million. Co-defendants Shell Oil Company and Shell Western E&P have filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The Company intends to join in that motion, which is scheduled to be heard on August 22, 2003.

Although the investigation into this claim has just begun, the Company intends to vigorously defend the case. Management cannot currently determine the likelihood or range of any potential outcome.

8. 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. At June 30, 2003, the Company had 24 cash flow hedges open: eight natural gas price collar arrangements and 16 natural gas price swap arrangements. Additionally, the Company had three crude oil financial instruments and one natural gas

financial instrument open at June 30, 2003, that did not qualify for hedge accounting under SFAS 133. At June 30, 2003, a $45.6 million ($28.2 million net of tax) unrealized loss was recorded to Other Comprehensive Income, along with a $49.4 million derivative liability and a $1.4 million derivative receivable.

A charge related to the change in fair value of derivative instruments of $1.2 million ($1.0 for gas and $0.2 for oil) and $0.7 million ($0.6 for gas and $0.1 for oil) is reflected in Operating Income for the six-month and three-month periods ending June 30, 2003, respectively.

Assuming no change in commodity prices after June 30, 2003 the Company would reclassify to earnings, over the next 12 months, $24.2 million in after-tax losses associated with commodity derivatives out of the net $28.2 million in after-tax losses recorded in other comprehensive income at June 30, 2003.

From time to time the Company enters into natural gas and crude oil swaps arrangements that do not qualify for hedge accounting under SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At June 30, 2003, the Company had three open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss of $0.9 million and $0.5 million recognized in Operating Revenue, respectively.

9. COMPREHENSIVE INCOME

Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the six-month periods ended June 30:

	SIX MONTHS ENDED
	JUNE 30, 2003						JUNE 30, 2002
	(In Thousands)
Accumulated Other Comprehensive Income (Loss)—
Beginning of Period				$	(12,939	)				$	835
Net Income (Loss)	$	(21,319	)				$	1,323
Other Comprehensive Loss
Reclassification Adjustment for Settled Contracts		37,493						2,219
Changes in Fair Value of Hedge Positions		(64,324	)					(8,186	)
Deferred Income Tax		10,197						2,288

Total Other Comprehensive Loss	$	(16,634	)	$	(16,634	)	$	(3,679	)	$	(3,679	)

Comprehensive Loss	$	(37,953	)				$	(2,356	)

Accumulated Other Comprehensive Loss—
End of Period				$	(29,573	)				$	(2,844	)

10. RETIREMENT OF EXECUTIVE OFFICER

In May 2002, Ray Seegmiller retired as the Company’s Chairman and Chief Executive Officer. The Company recorded a charge of approximately $3.6 million in the second quarter of 2002 for expenses

related to his retirement. The costs include a lump sum cash payment of $0.9 million in recognition of Mr. Seegmiller’s employment agreement, his contributions to the Company and in lieu of a 2002 long-term incentive award. Another $1.0 million was expensed as part of his supplemental executive retirement plan benefits. Mr. Seegmiller’s previously awarded stock grants and options vested upon retirement, resulting in compensation expense of approximately $1.7 million.

11. ACQUISITION OF CODY COMPANY

In August 2001, the Company acquired the stock of Cody Company, the parent of Cody Energy LLC (“Cody acquisition”) for $231.2 million, consisting of $181.3 million cash and 1,999,993 shares of common stock valued at $49.9 million. Substantially all of the proved reserves of Cody Company are located in the onshore Gulf Coast region. The acquisition was accounted for using the purchase method of accounting. As such, the Company reflected the assets and liabilities acquired at fair value in the Company’s balance sheet effective August 1, 2001, and the results of operations of Cody Company beginning August 1, 2001. The Company recorded a purchase price of approximately $315.6 million, which was allocated to specific assets and liabilities based on certain estimates of fair values, resulting in approximately $302.4 million allocated to property and $13.2 million allocated to working capital items. The remaining $78.0 million of the recorded purchase price reflected a non-cash item pertaining to the deferred income taxes attributable to the differences between the tax basis and the fair value of the acquired oil and gas properties, and acquisition related fees and costs of $6.4 million.

As part of the Cody acquisition, the Company acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. The Company’s current interest in Kurten is approximately 25%, including a one percent interest in the partnership. Under the partnership agreement, the Company has the right to a reversionary working interest that would bring its ultimate interest to 50% upon the limited partner reaching payout. Under the partnership agreement, the limited partner has the sole option to trigger a liquidation of the partnership. Effective February 13, 2003, the Kurten partnership commenced liquidation at the limited partner’s election. In connection with the liquidation, an appraisal was obtained to allocate the interest in the partnership assets. Based on the receipt of the appraisal in February 2003, the Company would not receive the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field and the limited partners’ decision to proceed with the liquidation, the Company performed an impairment review that resulted in an after-tax charge of $54 million. This impairment charge is reflected in the first quarter of 2003 as an operating expense but does not impact the Company’s cash flows. In addition, the Company recorded a downward reserve revision of approximately 16 Bcfe as a result of the loss of the reversionary interest.

12. ADOPTION OF SFAS 143, “ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS”

Effective January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. The adoption of SFAS 143 resulted in (1) an increase of total liabilities because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived asset and (3) an increase in operating expense because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities will also be recorded for meter stations, pipelines, processing plants and compressors. At January 1, 2003, there are no assets legally restricted for purposes of settling asset retirement obligations. The Company recorded a net-of-tax cumulative effect of change in accounting principle loss in January 2003 of $6.8 million and recorded a retirement obligation of $35.2 million. There was no impact on the Company’s

cash flows as a result of adopting SFAS 143. See Note 2 for additional information on plugging and abandonment costs.

Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement liabilities, settled liabilities, and revisions of estimated cash flows. Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense for the six-month and three-month periods ended June 30, 2003 is $1.0 million and $0.5 million, respectively.

The following unaudited pro forma information has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002.

	PERIOD ENDING JUNE 30, 2002
	THREE MONTHS		SIX MONTHS
	(In Thousands)
	(Except Per Share Amounts)
Net Income	$	1,502	$	95

Per Share—Basic	$	0.05	$	0.00
Per Share—Diluted	$	0.05	$	0.00

13. STOCK BASED COMPENSATION

SFAS 123, “Accounting for Stock-Based Compensation”, as amended by SFAS 148, “Accounting for Stock-Based Compensation—Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments. The Company has opted to continue using the intrinsic value based method, as recommended by Accounting Principles Board (APB) Opinion 25, to measure compensation cost for its stock option plans. However, the Company is evaluating the adoption of the recognition provisions of SFAS 123, as amended by SFAS 148.

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 123 to stock-based employee compensation.

	THREE MONTHS ENDED JUNE 30,						SIX MONTHS ENDED JUNE 30,
(In Thousands, Except Per Share Amounts)	2003			2002			2003			2002
Net Income (Loss), as reported	$	17,904		$	2,121		$	(21,319	)	$	1,323
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax		(152	)		(198	)		(1,954	)		(1,667	)

Pro forma net loss	$	17,752		$	1,923		$	(23,273	)	$	(344	)

Earnings per share:
Basic—as reported	$	0.56		$	0.07		$	(0.67	)	$	0.04
Basic—pro forma	$	0.56		$	0.06		$	(0.67	)	$	(0.01	)
Diluted—as reported	$	0.55		$	0.07		$	(0.67	)	$	0.04
Diluted—pro forma	$	0.55		$	0.06		$	(0.67	)	$	(0.01	)

The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table.

	THREE MONTHS ENDED JUNE 30,				SIX MONTHS ENDED JUNE 30,
(In Thousands, Except Per Share Amounts)	2003	2002			2003			2002
Compensation Expense in Net Income, as reported ⁽¹⁾	$278	$	1,303		$	525		$	1,550
Weighted Average Value per Option Granted
During the Quarter ⁽²⁾	$7.03	$	8.21		$	6.77		$	6.23
Assumptions
Stock Price Volatility	34.1%		35.8	%		35.3	%		35.8	%
Risk Free Rate of Return	2.5%		4.2	%		2.5	%		3.9	%
Dividend Rate (per year)	0.16		0.16			0.16			0.16
Expected Term (in years)	4		4			4			4

(1)

Compensation expense is defined as expense related to the vesting of stock grants, net of tax.

(2)

Calculated using the Black Sholes fair value based method.

The fair value of stock options included in the pro forma results for each of the periods presented is not necessarily indicative of future effects on Net Income and Earnings Per Share.

Report of Independent Accountants

To the Board of Directors and Shareholders 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, 2003, and the related condensed consolidated statements of operations and cash flows for each of the three-month and six-month periods ended June 30, 2003 and June 30, 2002. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. 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 generally accepted auditing standards, 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 previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of December 31, 2002, and the related consolidated statements of operations, stockholders’ equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 17, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Houston, Texas

July 25, 2003

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

The following review of operations for the first six months of 2003 and 2002 should be read along 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, 2002.

Overview

In the first half of 2003, we produced 44.2 Bcfe, a decrease of 2% over the first half of 2002. Natural gas production was 35.2 Bcf, down 1.7 Bcf, or 5%, compared to the 2002 first half of the year. Oil production was 1,457 Mbbls, up 72 Mbbls, or 5% over the comparable half of last year. Natural gas production in the current period decreased slightly from the same period in 2002, which is when we experienced the highest annual production levels in our history. The decline in our natural gas production is essentially attributable to the size and timing of the Gulf Coast and West regions drilling program, along with the natural decline of existing production.

Commodity prices were unusually high during the first half of 2003, and our financial results reflected their impact. In the first half of 2003, our realized natural gas price was 64% higher and our realized crude oil price was 34% higher than in 2002. Although our hedge positions limited the upside in the first half of the year, the strong commodity price environment resulted in an increase to gas revenue of $57.5 million, or 56%, and an increase in oil revenue of $12.8 million, or 41%, for the first half of the year. Operating cash flows were similarly impacted, increasing by $56.8 million, or 68%, over last year.

We had a net loss of $20.6 million, or $0.64 per share, in the first half of the year despite the increase in commodity prices. This loss is attributable to a pre-tax non-cash impairment charge of $87.9 million related to the liquidation of a limited partnership interest in the Kurten field (see Note 11) and a $6.8 million charge from the adoption of SFAS 143 (see Note 12).

In the first half of the year, we drilled 68 gross wells (61 development and seven exploratory wells) with a success rate of 93% compared to 54 gross wells (49 development and five exploratory wells) and a 94% success rate in the first half of 2002. For the full year, we plan to drill 185 gross wells and spend approximately $172.0 million in capital and exploration expenditures compared to 108 gross wells and $126.3 million of capital and exploration expenditures in 2002. Total capital and exploration expenditures were $82.4 million for the first half of 2003, compared to $66.8 million for the comparable period in 2002.

We remain focused on our strategies of concentrating our capital spending program on projects balancing acceptable risk with the strongest economics. As in the past, we will use a portion of the cash flow from our long-lived Eastern and Mid-Continent natural gas reserves to fund our exploration and development efforts in the Gulf Coast and Rocky Mountain areas. In addition, we have begun to expand our interest in the offshore Gulf of Mexico and Canada. We believe these strategies are appropriate in the current industry environment, enabling Cabot Oil & Gas to add shareholder value over the long term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See Forward-Looking Information on page 25.

Financial Condition

Capital Resources and Liquidity

Our capital resources consist primarily of cash flows from our oil and gas properties and asset-based borrowings supported by our oil and gas reserves. The level of earnings and cash flows depend on many factors, including the price of crude oil and natural gas and our ability to control and reduce costs. Demand for crude oil and natural gas has historically been subject to seasonal influences characterized

by peak demand and higher prices in the winter heating season. However, demand and prices moved higher, strengthening from the first half of 2002 into the summer and continued to strengthen through the first half of 2003. Prices in the first half of 2003 were the result of a higher demand associated with colder than normal winter temperatures, combined with lower inventory levels in the second quarter.

Our primary source of cash during the first half of 2003 was from funds generated from operations. Cash was primarily used to fund exploration and development expenditures, reduce debt and pay dividends.

We had a net cash inflow of $0.7 million in the first half of 2003. Cash inflows from operating activities totaled $139.8 million. The $80.5 million of capital and exploration expenditures were funded with our operating cash flows.

Cash flows from operating activities in the first half of 2003 were $56.8 million higher than the corresponding period of 2002 primarily due to higher natural gas and oil prices.

	SIX MONTHS ENDED JUNE 30,
	2003			2002
	(In millions)
Cash Flows Used by Investing Activities	$	(78.1	)	$	(85.6	)

Cash flows used by investing activities in the first half of 2003 were attributable to capital and exploration expenditures of $80.5 million, partially offset by proceeds from the sale of certain oil and gas properties of $2.4 million. Cash flows used by investing activities in the first half of 2002 were entirely for capital and exploration expenditures of $89.1 million. This amount was partially offset by $3.4 million in proceeds from the sale of non-strategic assets.

	SIX MONTHS ENDED JUNE 30,
	2003			2002
	(In millions)
Cash Flows (Used) Provided by Financing Activities	$	(61.0	)	$	4.6

Cash flows used by financing activities in the first half of 2003 consist primarily of $61.0 million of borrowing repayments on the revolving credit facility and $2.5 million of dividend payments, partially offset by proceeds from the sale of common stock of $2.5 million. Cash flows provided by financing activities in the first half of 2002 consist primarily of $4.0 million in increased borrowings on the revolving credit facility and $3.1 million related to proceeds from the exercise of stock options. Our 2003 interest expense is expected to be approximately $22.0 million.

The available credit line under our revolving credit facility, currently $250 million, 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 bank’s petroleum engineer) and other assets. The revolving term of the credit facility ends in October 2006. 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 acquisitions.

Non-GAAP Financial Measures

From time to time management discloses Discretionary Cash Flow and Net Income and Earnings Per Share, excluding selected items. These non-GAAP financial measure calculations may be presented in earnings releases of the Company, furnished in Form 8-K to the Securities and Exchange Commission, along with reconciliations to the most comparable GAAP financial measure for the period.

Discretionary Cash Flow is defined as Net Income plus non-cash charges and Exploration Expense. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate cash which is used to internally fund exploration and development activities, pay dividends and service debt. Discretionary Cash Flow is presented based on management’s belief that this non-GAAP measure is helpful to investors when comparing our cash flow with the cash flow of other companies that use the Full Cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to Net Income.

Net Income excluding selected items and Earnings Per Share excluding selected items is presented based on management’s belief that these non-GAAP measures enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a beneficial comparison to similarly adjusted measurements of prior periods. Net Income and Earnings Per Share excluding selected items is not a measure of financial performance under GAAP and should not be considered as an alternative to Net Income and Earnings Per Share, as defined by GAAP.

Capitalization

Our capitalization information is as follows:

	JUNE 30, 2003			DECEMBER 31, 2002
	(In millions)
Debt	$	304.0		$	365.0
Stockholders’ Equity ⁽¹⁾		315.8			350.7

Total Capitalization	$	619.8		$	715.7

Debt to Capitalization		49	%		51	%

⁽¹⁾

Includes common stock, net of treasury stock.

During the first half of 2003, we paid dividends of $2.5 million on the 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.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations, and budget such capital expenditures while considering projected cash flows for the year.

The following table presents major components of capital and exploration expenditures:

	SIX MONTHS ENDED JUNE 30,
	2003		2002
	(In Millions)
Capital Expenditures
Drilling and Facilities	$	38.6	$	42.1
Leasehold Acquisitions		10.8		2.5
Pipeline and Gathering		2.2		1.2
Other		0.7		0.3

		52.3		46.1

Proved Property Acquisitions		1.0		2.8
Exploration Expense		29.1		17.9

Total	$	82.4	$	66.8

Total capital and exploration expenditures in the first half of 2003 increased $15.6 million compared to the same period of 2002, primarily as a result of increased exploration expense and leasehold acquisitions.

We plan to drill 185 gross wells in 2003 compared with 108 gross wells drilled in 2002. This 2003 drilling program includes approximately $172.0 million in total capital and exploration expenditures, up from $126.3 million in 2002. Forecasted spending in 2003 includes approximately $99.2 million for drilling and dry hole exposure, $15.5 million for lease acquisition and $15.2 million in geological and geophysical expenses. In addition to the drilling and exploration program, other 2003 capital expenditures are planned primarily for production equipment, workovers, and for gathering and pipeline infrastructure maintenance and construction. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.

Results of Operations

Selected Operating Data

	THREE MONTHS ENDED JUNE 30,				SIX MONTHS ENDED JUNE 30,
	2003		2002		2003		2002
Natural Gas Production (Bcf)
Gulf Coast		7.4		7.7		14.1		15.2
West		6.0		6.4		12.1		12.8
East		4.6		4.4		9.0		8.9

Total Company		18.0		18.5		35.2		36.9

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	4.96	$	3.35	$	4.92	$	2.99
West	$	3.60	$	2.40	$	3.61	$	2.27
East	$	4.92	$	3.31	$	5.13	$	3.08
Total Company	$	4.50	$	2.99	$	4.52	$	2.76

Crude Oil Production (Mbbl)
Gulf Coast		648		656		1,344		1,266
West		51		53		100		103
East		7		8		13		16

Total Company		706		717		1,457		1,385

Crude Oil Production Sales Price ($/Bbl)
Gulf Coast	$	29.30	$	24.16	$	30.10	$	22.41
West	$	28.47	$	25.23	$	30.22	$	23.17
East	$	31.83	$	21.87	$	29.05	$	19.18
Total Company	$	29.27	$	24.19	$	30.10	$	22.43

Brokered Natural Gas Margin
Volume (Bcf)		4.7		5.9		8.6		9.1
Margin ($/Mcf) ⁽¹⁾	$	0.39	$	0.19	$	0.63	$	0.28

⁽¹⁾ Amount represents brokered natural gas revenue less brokered natural gas cost, divided by brokered natural gas volumes.

Second Quarters of 2003 and 2002 Compared

Net Income and Revenues. We reported net income in the second quarter of 2003 of $17.9 million, or $0.56 per share. During the corresponding quarter of 2002, we reported net income of $2.1 million, or $0.07 per share. Net operating revenues increased by $37.2 million, or 41% and operating income increased by $25.0 million, or 254%. The increase in operating income was substantially due to an increase in our realized natural gas and crude oil prices. Our realized average natural gas price increased 51% and our realized average crude oil price increased 21% from the second quarter of 2002. Natural gas sales made up 64%, or $81.1 million, of operating revenue. Crude oil sales made up 16%, or $20.7 million, of operating revenue. Operating revenues were also impacted by a $7.7 million increase in our brokered natural gas revenues.

The average realized total company natural gas production sales price, including the impact of derivative instruments, was $4.50 per Mcf for the second quarter of 2003. Due to derivative instruments this price was reduced by $0.68 per Mcf. The average Gulf

Coast natural gas production sales price increased $1.61 per Mcf, or 48%, to $4.96, increasing operating revenues by approximately $12.7 million. In the Western region, the average natural gas production sales price increased $1.20 per Mcf, or 50%, to $3.60, increasing operating revenues by approximately $7.2 million. The average Eastern region natural gas production sales price increased $1.61 per Mcf, or 49%, to $4.92, increasing operating revenues by approximately $7.4 million. The overall weighted average natural gas production sales price increased $1.51 per Mcf, or 51%, to $4.50, increasing revenues by $27.3 million.

Natural gas production volume in the Gulf Coast region was down 0.3 Bcf, or 4%, to 7.4 Bcf primarily due to the size and timing of the Gulf Coast drilling program, along with the natural decline of existing production. Natural gas production volume in the Western region decreased 0.4 Bcf, or 6%, to 6.0 Bcf primarily due to natural declines and a smaller drilling program in 2002. Natural gas production volume in the Eastern region increased 0.2 Bcf, or 5%, over the comparable quarter of 2002. The decrease in total natural gas production of 0.5 Bcf, or 3%, resulted in a decrease to natural gas revenue of $1.5 million in the second quarter of 2003.

The average realized total company crude oil sales price, including the impact of derivative instruments, was $29.27 per Bbl for the second quarter of 2003. Due to derivative instruments this price was reduced by $0.33 per Bbl. The volume of crude oil sold in the quarter decreased by 11 Mbbls, or 2%, to 706 Mbbls, decreasing operating revenues by $0.3 million. Crude oil prices increased $5.05 per Bbl, or 21%, to $29.27, resulting in an increase to operating revenues of $3.6 million. In total, revenue from crude oil sales increased $3.3 million, or 19%, above the 2002 second quarter.

Brokered natural gas revenue increased $7.7 million, or 49%, over the second quarter of last year. The per Mcf sales price of brokered natural gas rose 88%, resulting in an increase in revenue of $10.9 million, offset by a 20% decline in volume of natural gas brokered this quarter, decreasing revenues by $3.2 million. After including the related brokered natural gas costs, we realized a net margin of $1.8 million in the second quarter of 2003 and $1.1 million in the comparable quarter of 2002.

Other operating revenues increased $0.5 million to $2.3 million. This change was a result of a $0.5 million increase in transportation revenue due to a substantial increase in volumes, offset slightly by a decrease in price.

Costs and Expenses. Total costs and expenses from operations increased $10.6 million in the second quarter of 2003 compared to the same quarter of 2002. The primary reasons for this fluctuation are as follows:

•

Brokered natural gas cost increased $7.0 million, or 48%, from the second quarter of last year. The per Mcf cost of brokered natural gas rose 86%, resulting in an increase to expense of $10.0 million. Additionally, a 20% decrease in volume of natural gas brokered this quarter decreased costs by $3.0 million.

•

Direct operating expense increased $1.9 million, or 16%. Operating costs have increased in the Gulf Coast region, and to a lesser extent in the West region. The increase in the Gulf Coast is substantially attributable to an increase in outside operated properties expense of $0.3 million in addition to an increase in activity related to well workovers of $0.2 million. The increase in the West region is due to an increase in workover and contract labor expense of $0.2 million, and to a lesser extent, timing of expenditures. Additionally, there has been an overall increase in professional fees, field transportation cost and employee related expenses for the second quarter of 2003 compared to the same period of 2002.

•

Exploration expense increased $4.8 million, or 45%, as a result of higher dry hole expense in 2003. During the second quarter of 2003, we drilled four exploratory dry holes compared to two in the corresponding period of 2002.

•

General and administrative costs decreased $3.4 million, or 36%, between the 2003 and 2002 second quarters. The 2002 second quarter reflects a $3.6 million charge related to the retirement of an executive officer (Note 10).

•

Taxes other than income increased $1.2 million, or 16%, as a result of higher commodity prices realized this quarter.

Interest expense decreased $0.4 million as a result of a lower average level of outstanding debt during the second quarter of 2003 when compared to the second quarter of 2002 and a decline in interest rates on the revolving credit facility.

Income tax expense increased from $1.4 million in 2002 to $11.0 million in 2003. The increase is due to a comparable increase in our pre-tax net income.

Six Months of 2003 and 2002 Compared

Net Income and Revenues. We reported a net loss in the first half of 2003 of $21.3 million, or $0.67 per share. Our net loss is due to the recognition of a pre-tax non-cash impairment charge of $87.9 million related to the Kurten field (Note 11) and an after-tax charge of $6.8 million related to the cumulative impact of adopting a new accounting standard (Note 12). During the corresponding period of 2002, we reported net income of $1.3 million, or $0.04 per share. Net operating revenues increased by $98.0 million, or 60% and operating income decreased by $26.7 million, or 180%. Our realized average natural gas price increased 64% and our realized average crude oil price increased 34% from the first half of 2002. Natural gas sales made up 61%, or $159.3 million, of operating revenue. Crude oil sales made up 17%, or $43.8 million, of operating revenue. Operating revenues were also impacted by a $25.8 million increase in our brokered natural gas revenues.

The average realized total company natural gas production sales price, including the impact of derivative instruments, was $4.52 per Mcf for the first half of 2003. Due to derivative instruments this price was reduced by $1.07 per Mcf. The average Gulf Coast natural gas production sales price increased $1.93 per Mcf, or 65%, to $4.92, increasing operating revenues by approximately $27.5 million. In the Western region, the average natural gas production sales price increased $1.34 per Mcf, or 59%, to $3.61, increasing operating revenues by approximately $16.2 million. The average Eastern region natural gas production sales price increased $2.05 per Mcf, or 67%, to $5.13, increasing operating revenues by approximately $18.5 million. The overall weighted average natural gas production sales price increased $1.76 per Mcf, or 64%, to $4.52, increasing revenues by $62.2 million.

Natural gas production volume in the Gulf Coast region was down 1.1 Bcf, or 7%, to 14.1 Bcf primarily due to the size and timing of the Gulf Coast drilling program, along with the natural decline of existing production. Natural gas production volume in the Western region decreased 0.7 Bcf, or 5%, to 12.1 Bcf primarily due to natural declines and a smaller drilling program in 2002. Natural gas production volume in the Eastern region was essentially the same as the comparable quarter of 2002 at 9.0 Bcf. The decrease in total natural gas production of 1.7 Bcf, or 5%, resulted in a decrease to natural gas revenue of $4.7 million in the first half of 2003.

The average realized total company crude oil sales price, including the impact of derivative instruments, was $30.10 per Bbl for the first half of 2003. Due to certain derivative instruments this price was reduced by $1.47 per Bbl. The volume of crude oil sold in the period increased by 72 Mbbls, or 5%, to 1,457 Mbbls, increasing operating revenues by $1.7 million. Crude oil prices increased $7.62 per Bbl, or 34%, to $30.10, resulting in an increase to operating revenues of $11.1 million. In total, revenue from crude oil sales increased $12.8 million, or 41%, above the first half of 2002.

Brokered natural gas revenue increased $25.8 million, or 88%, over the first half of last year. The per Mcf sales price of brokered natural gas rose 98%, resulting in an increase in revenue of $27.3 million, offset by a 5% decline in volume of natural gas brokered this period, decreasing revenues by

$1.5 million. After including the related brokered natural gas costs, we realized a net margin of $5.4 million in the first half of 2003 and $2.5 million in the comparable period of 2002.

Other operating revenues increased $1.9 million to $5.5 million. This change was substantially due to the following items:

•

$0.9 million increase in transportation revenue due to a substantial increase in volumes, offset slightly by a decrease in price.

•

$0.9 million increase in natural gas liquids due to a substantial increase in the average realized price.

Costs and Expenses. Total costs and expenses from operations increased $124.9 million in the first half of 2003 compared to the same period of 2002. The primary reasons for this fluctuation are as follows:

•

Brokered natural gas cost increased $23.0 million, or 85%, from the first half of last year. The per Mcf cost of brokered natural gas rose 95%, resulting in an increase to expense of $24.3 million. Additionally, a 5% decrease in the volume of natural gas brokered, decreased costs by $1.3 million.

•

Direct operating expense increased $0.6 million, or 2%. Operating costs have increased in the Gulf Coast, and to a lesser extent in the East region. The increase in the Gulf Coast region is attributable to timing of expenditures related to outside operated properties and well workovers. The increase in the East region is due primarily to higher salary and wage expense as well as an increase in incentive compensation. Additionally, there has been an overall increase in fringe benefit expense.

•

Exploration expense increased $11.2 million, or 62%, primarily as a result of increased spending on geological and geophysical expenses and dry hole expense in 2003. During the first half of 2003, we spent an additional $4.6 million on geological and geophysical activities and incurred an additional $5.5 million in dry hole expense.

•

Impairment of long-lived assets expense increased $86.9 million essentially due to the impairment on the Kurten field (see Note 11).

•

General and administrative costs decreased $2.5 million, or 17%. This decrease is due to the retirement of an executive officer which occurred in the comparable period of the prior year. The retirement resulted in an expenditure of $3.6 million (Note 10). This decrease was partially offset by increases in professional fees, insurance and an overall increase in employee related expenses.

•

Taxes other than income increased $5.2 million, or 39%, as a result of higher commodity prices realized this quarter.

Interest expense decreased $1.1 million as a result of a lower average level of outstanding debt during the first half of 2003 when compared to the first half of 2002 and a decline in interest rates on the revolving credit facility.

Income tax benefit increased to $8.9 million from expense of $1.0 million from the first half 2002. The increase is due to a comparable increase in our net loss.

Recently Issued Accounting Pronouncements

In June 2001, the FASB approved for issuance Statement of Financial Accounting Standard (SFAS) 143, “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The adoption of SFAS 143 resulted in (1) an increase of total liabilities, because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets, because the retirement costs are added to the carrying amount of the long-lived asset, and (3) an increase in operating expense, because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003. The impact on the financial statements of adopting SFAS 143 is disclosed in Note 12, “Adoption of SFAS 143, Accounting for Asset Retirement Obligations,” to the financial statements.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS 148 amends FASB Statement No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. We are evaluating the adoption of the recognition provisions of SFAS 123, as amended by SFAS 148. The adoption of the recognition provisions would impact our financial position and results of operations. See Note 13, “Stock Based Compensation,” to the financial statements.

In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51” (FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time we have only one entity that could potentially be a VIE. We are evaluating this potential VIE, in which we have a one percent general partner interest and that holds an interest in the Kurten field, to determine if it is a VIE. However, pursuant to the partnership agreement, the limited partner has elected to liquidate the partnership; it is anticipated that this liquidation will be completed prior to the effective date of the Interpretation. See Note 11 for additional information related to this partnership.

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.

Conclusion

Our financial results depend upon many factors, particularly the price of natural gas and oil and our ability to produce and market natural gas and oil on economically attractive terms. The average produced natural gas sales price received in the first half of 2003 was 64% higher than in 2002 and the average oil sales price was 34% higher than in the comparable period of 2002. The volatility of natural gas prices in recent years remains prevalent in 2003 with wide price swings in day-to-day trading on the NYMEX futures market. Additionally, we have natural gas price swaps and collars in place through December 2004 and crude oil range swaps in place through December 2003, which all offer some protection against price volatility. Given this continued price volatility, we cannot predict with certainty what pricing levels will be in the future. Because future cash flows are subject to these variables, we cannot assure you that our operations will provide cash sufficient to fully fund our planned capital expenditures. See Item 3A., “Quantitative and Qualitative Disclosures about Market Risk” for additional information regarding these derivative instruments.

We believe our capital resources, supplemented with external financing, if necessary, are adequate to meet our capital requirements.

The preceding paragraphs contain forward-looking information. See Forward-Looking Information above.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Swaps and Options

Our hedging policy 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 against declines in oil and gas prices. These hedging arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices. Please read the discussion below related to commodity price swaps and Note 8 of the Notes to the Interim Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

Hedges on Production—Swaps

From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. Under our Revolving Credit Agreement, the aggregate level of commodity hedging must not exceed 80% of the anticipated future equivalent production during the period covered by the hedges. During the first half of 2003, natural gas price swaps covered 16,991 Mmcf, or 48% of our gas production, fixing the sales price of this gas at an average of $4.43 per Mcf.

At June 30, 2003, we had open natural gas price swap contracts covering our 2003 and 2004 production as follows:

	Natural Gas Price Swaps
Contract Period	Volume in Mmcf	Weighted Average Contract Price		Unrealized Loss (In Thousands)
As of June 30, 2003
Natural Gas Price Swaps on Production in:
Third Quarter 2003	8,898	$	4.54
Fourth Quarter 2003	8,898		4.54

Six Months Ended December 31, 2003	17,796	$	4.54	$	23,920
First Quarter 2004	2,959	$	5.08
Second Quarter 2004	2,089		4.42
Third Quarter 2004	2,112		4.42
Fourth Quarter 2004	2,112		4.42

Full Year 2004	9,272	$	4.63	$	9,972

Hedges on Production—Options

Throughout 2002 and the first half of 2003, we believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our production through the use of natural gas and crude oil collars. Under the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index falls below the floor price, the counterparty pays us.

The 2003 and 2004 natural gas price collar hedges included several collar arrangements based on five price indexes at which we sell a portion of our production. During the first half of 2003, natural gas price collars covered 7,570 Mmcf, or 21% of our gas production, with a weighted average floor of $4.46 per Mcf and a weighted average ceiling of $5.39 per Mcf. Additionally, during the first half of 2003, we had crude oil price collars which covered 362 Mbbls, or 25% of our production, with a weighted average floor of $24.75 per bbl and a weighted average ceiling of $28.86 per bbl.

At June 30, 2003, we had open natural gas price collar contracts covering our 2003 and 2004 production as follows:

	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling / Floor		Unrealized Loss (In Thousands)
As of June 30, 2003
Natural Gas Price Collars on Production in:
Third Quarter 2003	4,283	$	5.42 / $4.46
Fourth Quarter 2003	4,283	$	5.42 / $4.46

Six Months Ended December 31, 2003	8,566	$	5.42 / $4.46	$	6,591

First Quarter 2004	2,955	$	5.78 / $4.32
Second Quarter 2004	2,955	$	5.78 / $4.32
Third Quarter 2004	2,988	$	5.78 / $4.32
Fourth Quarter 2004	2,988	$	5.78 / $4.32

Full Year 2004	11,886	$	5.78 / $4.32	$	6,152

At June 30, 2003, we have no open crude oil price collar arrangements to cover our 2003 or 2004 production.

We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and 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 on page 25.

ITEM 4. Controls and Procedures

As of the end of the current reported period, 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-14 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 issuer in the reports that it files or submits under the Exchange Act.

There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls subsequent to the date the Company carried out its evaluation.

PART II. OTHER INFORMATION

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

On April 29, 2003, the Company held its Annual Meeting of Stockholders. At this meeting, the Company’s stockholders voted on two matters:

•

the election of three directors,

•

the ratification of the appointment of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company for its 2003 fiscal year.

Of the total shares entitled to vote, 30,133,915, or 95%, were voted. There were no broker nonvotes.

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

James G. Floyd
Votes cast in favor:		29,861,154
Votes withheld:		272,764

Robert Kelley
Votes cast in favor:		29,859,720
Votes withheld:		274,195

P. Dexter Peacock
Votes cast in favor:		29,683,274
Votes withheld:		450,641

The terms of office of directors Robert F. Bailey, John G.L Cabot, Dan O. Dinges and William P. Vititoe continued beyond the meeting date. Mr. Henry O. Boswell retired from the Board of Directors immediately following the 2003 Annual Meeting of Stockholders in accordance with the board’s mandatory retirement policy.

The last item presented for a vote before the stockholders was the ratification of the appointment of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company for its 2003 fiscal year. Of the votes received, 29,765,049 were in favor of the ratification, 364,165 were against, and 4,701 abstained.

ITEM 6. Exhibits and Reports on Form 8-K

(a) Exhibits


15.1		—Awareness letter of PricewaterhouseCoopers LLP

15.2		—Consent of Brown, Drew & Massey, 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

(b) Reports on Form 8-K

None

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 30, 2003	By:	/s/ DAN O. DINGES
		Dan O. Dinges Chairman, President and Chief Executive Officer (Principal Executive Officer)




July 30, 2003	By:	/s/ SCOTT C. SCHROEDER
		Scott C. Schroeder Vice President and Chief Financial Officer (Principal Financial Officer)




July 30, 2003	By:	/s/ HENRY C. SMYTH
		Henry C. Smyth Vice President, Controller and Treasurer (Principal Accounting Officer)

SIX MONTHS ENDED JUNE 30,

(In millions)

Cash Flows Provided by Operating Activities