Edgar Filing: CABOT OIL & GAS CORP

Form 10-Q for the quarterly period ended September 30, 2005

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 September 30, 2005

¨	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)

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 Exchange Act). Yes x No ¨

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 October 24, 2005, there were 48,969,832 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 Nine Months Ended September 30, 2005 and 2004		3

Condensed Consolidated Balance Sheet at September 30, 2005 and December 31, 2004		4

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2005 and 2004		5

Notes to the Condensed Consolidated Financial Statements		6

Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information		17

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3. Quantitative and Qualitative Disclosures about Market Risk		33

Item 4. Controls and Procedures		35

Part II. Other Information

Item 1. Legal Proceedings		36

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		36

Item 5. Other Information		36

Item 6. Exhibits		37

Signatures		38

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 September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
OPERATING REVENUES
Natural Gas Production	$	121,477	$	96,111	$	337,566	$	276,518
Brokered Natural Gas		18,756		13,224		60,768		60,411
Crude Oil and Condensate		21,336		8,514		57,250		34,833
Other		188		1,574		2,131		4,007

		161,757		119,423		457,715		375,769

OPERATING EXPENSES
Brokered Natural Gas Cost		16,550		11,627		53,549		53,944
Direct Operations - Field and Pipeline		14,246		13,297		43,171		38,489
Exploration		16,665		6,979		47,396		32,691
Depreciation, Depletion and Amortization		26,578		27,734		79,346		76,585
Impairment of Unproved Properties		4,092		3,054		11,146		8,365
Impairment of Oil & Gas Properties (Note 2)		—		3,458		—		3,458
General and Administrative		9,679		9,001		27,339		25,299
Taxes Other Than Income		14,939		10,115		37,053		30,138

		102,749		85,265		299,000		268,969
Gain on Sale of Assets		15		120		74		7

INCOME FROM OPERATIONS		59,023		34,278		158,789		106,807
Interest Expense and Other		5,339		5,577		15,461		16,399

Income Before Income Taxes		53,684		28,701		143,328		90,408
Income Tax Expense		19,928		10,879		53,388		34,257

NET INCOME	$	33,756	$	17,822	$	89,940	$	56,151

Basic Earnings per Share	$	0.69	$	0.37	$	1.84	$	1.15
Diluted Earnings per Share	$	0.68	$	0.36	$	1.81	$	1.14

Average Common Shares Outstanding		48,951		48,822		48,865		48,736
Diluted Common Shares (Note 6)		49,665		49,419		49,613		49,329

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)


	September 30, 2005			December 31, 2004
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,187		$	10,026
Accounts Receivable		131,840			125,754
Inventories		35,473			24,049
Deferred Income Taxes		52,247			21,345
Other		9,433			13,505

Total Current Assets		232,180			194,679
Properties and Equipment, Net (Successful Efforts Method)		1,156,886			994,081
Deferred Income Taxes		19,601			14,855
Other Assets		7,257			7,341

	$	1,415,924		$	1,210,956

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	144,748		$	104,969
Current Portion of Long-Term Debt		20,000			20,000
Deferred Income Taxes		1,105			944
Derivative Contracts		114,571			38,368
Accrued Liabilities		29,204			32,608

Total Current Liabilities		309,628			196,889
Long-Term Debt		260,000			250,000
Deferred Income Taxes		269,410			247,376
Other Liabilities		74,629			61,029
Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common Stock:
Authorized — 80,000,000 Shares of $.10 Par Value Issued and Outstanding — 50,050,174 Shares and 49,680,915 Shares in 2005 and 2004, respectively		5,005			4,968
Additional Paid-in Capital		393,535			380,125
Retained Earnings		195,621			110,935
Accumulated Other Comprehensive Loss		(71,318	)		(20,351	)
Less Treasury Stock, at Cost:
1,081,250 and 1,061,550 Shares in 2005 and 2004		(20,586	)		(20,015	)

Total Stockholders’ Equity		502,257			455,662

	$	1,415,924		$	1,210,956

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)


	Nine Months Ended September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	89,940		$	56,151
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depletion, Depreciation and Amortization		79,346			76,585
Impairment of Unproved Properties		11,146			8,365
Impairment of Oil & Gas Properties		—			3,458
Deferred Income Tax Expense		18,225			15,449
Gain on Sale of Assets		(74	)		(7	)
Exploration Expense		47,396			32,691
Change in Derivative Fair Value		2,051			13,295
Performance Share Compensation		2,572			3,403
Other		4,582			1,863
Changes in Assets and Liabilities:
Accounts Receivable		(6,086	)		12,733
Inventories		(11,424	)		(6,825	)
Other Current Assets		1,167			(8,449	)
Other Assets		(203	)		341
Accounts Payable and Accrued Liabilities		4,808			5,175
Other Liabilities		3,665			1,701

Net Cash Provided by Operating Activities		247,111			215,929

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(241,504	)		(157,747	)
Proceeds from Sale of Assets		996			186
Exploration Expense		(47,396	)		(32,691	)

Net Cash Used by Investing Activities		(287,904	)		(190,252	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		85,000			75,000
Decrease in Debt		(75,000	)		(75,000	)
Increase in Book Overdrafts		25,691			—
Sale of Common Stock Proceeds		4,088			11,123
Purchase of Treasury Stock		(571	)		(8,732	)
Dividends Paid		(5,254	)		(3,906	)

Net Cash Provided / (Used) by Financing Activities		33,954			(1,515	)

Net (Decrease) / Increase in Cash and Cash Equivalents		(6,839	)		24,162
Cash and Cash Equivalents, Beginning of Period		10,026			724

Cash and Cash Equivalents, End of Period	$	3,187		$	24,886

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 for the year ended December 31, 2004 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, 2004 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.

On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the Common Stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s Common Stock.

Recently Issued Accounting Pronouncements

In March 2005, the Financial Accounting Standard Board (FASB) issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company does not believe that its financial position, results of operations or cash flows will be impacted by this Interpretation since the Company currently records all asset retirement obligations.

In May 2005, the FASB issued Statement SFAS No. 154, “Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting

for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS 123(R) revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS 123(R) are now effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, the Company will not adopt this SFAS until the first quarter of 2006. The Company plans to use the modified prospective application method as detailed in SFAS 123(R). The Company is currently evaluating the impact on the Company’s operating results. Future cash flows of the Company will not be impacted by the adoption of this standard. See “Stock-Based Compensation” below for further information.

In September 2005, the FASB also issued Proposed FASB Staff Position (FSP) FAS 123(R)-c which provides a simplified, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS 123(R). Under this Proposed FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS 123(R) adoption date will not be affected by this Proposed FSP and will be calculated in accordance with SFAS 123(R) which requires that only the excess tax benefit or deficiency of the tax deduction over the tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the Proposed FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS 123(R) for the calculation of the APIC pool. If finalized, the Company will adopt this Proposed FSP in conjunction with the adoption of SFAS 123(R).

In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, the Company is allowed to use the date the award is approved in accordance with its corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. The Company will adopt this FSP in conjunction with the adoption of SFAS 123(R).

Stock-Based Compensation

The Company accounts for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Under the intrinsic value based method, compensation cost is the excess, if any, of the quoted market price of the stock at the grant date over the amount an employee must pay to acquire the stock.

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 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. The Earnings per Share amounts for prior periods have been retroactively adjusted to reflect the 3-for-2 split of the Company’s Common Stock effective March 31, 2005.


	Three Months Ended September 30,						Nine Months Ended September 30,
*(In thousands, except per share amounts)*	2005			2004			2005			2004
Net Income, as reported	$	33,756		$	17,822		$	89,940		$	56,151
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		(170	)		(324	)		(649	)		(1,279	)

Pro forma Net Income	$	33,586		$	17,498		$	89,291		$	54,872

Earnings per Share:
Basic - as reported	$	0.69		$	0.37		$	1.84		$	1.15
Basic - pro forma	$	0.69		$	0.36		$	1.83		$	1.13
Diluted - as reported	$	0.68		$	0.36		$	1.81		$	1.14
Diluted - pro forma	$	0.68		$	0.35		$	1.80		$	1.11

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 September 30,				Nine Months Ended September 30,
*(In thousands, except per share amounts)*	2005		2004		2005		2004
Compensation Expense in Net Income, as reported ⁽¹⁾	$	2,629	$	1,544	$	4,217	$	3,474
Weighted Average Value per Option Granted During the Period^(2) (3)	$	—	$	—	$	—	$	11.31

Assumptions⁽³⁾
Stock Price Volatility		—		—		—		38.4	%
Risk Free Rate of Return		—		—		—		3.3	%
Dividend Rate (per year)	$	0.16	$	0.16	$	0.16	$	0.16
Expected Term (in years)		—		—		—		4

⁽¹⁾

Compensation expense is defined as expense related to the vesting of stock grants, net of tax. Compensation expense for the three months ended September 30, 2005 and 2004 also includes $1.5 million and $0.9 million, respectively, net of tax related to performance shares. Compensation expense for the nine months ended September 30, 2005 and 2004 also includes $1.6 million and $2.0 million, respectively, net of tax, related to performance shares.

⁽²⁾

Calculated using the Black-Scholes fair value based method.

⁽³⁾

There were no stock options issued in the third quarter of 2004 or in the first nine months of 2005.

On October 26, 2005, the Compensation Committee of the Board of Directors of the Company approved the acceleration, to December 15, 2005, of the vesting of 200,299 unvested stock options awarded in February 2003 under the Company’s Second Amended and Restated Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under the Company’s 2004 Incentive Plan.

The 200,299 shares awarded to employees at an exercise price of $15.32, would have vested in February 2006. The 24,500 shares, awarded to the non-employee directors at an exercise price of $23.32, would have vested 12,250 in April 2006 and April 2007, respectively. Of the 200,299 shares, 91,500 were awarded to the named executive officers.

The decision to accelerate the vesting of these unvested options, which the Company believes to be in the best interest of its shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with the Company’s adoption of Financial Accounting Standards Board Statement No. 123(R), “Share Based Payment (revised 2004).” The accelerated vesting of the options will not have a material impact on the Company’s results of operations or cash flows. The Company currently accounts for stock-based compensation using the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” under which the Company has not recognized any compensation expense for its stock option grants. SFAS 123(R) will require the Company to recognize compensation expense equal to the fair value of all equity-based compensation over the vesting period of each such award beginning on January 1, 2006. The acceleration of vesting will reduce the Company’s compensation expense related to these options by an estimated $0.2 million for the year 2006.

2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:


	September 30, 2005			December 31, 2004
	*(In thousands)*
Unproved Oil and Gas Properties	$	103,775		$	94,795
Proved Oil and Gas Properties		1,870,731			1,646,841
Gathering and Pipeline Systems		172,863			160,951
Land, Building and Improvements		4,878			4,860
Other		32,621			31,261

		2,184,868			1,938,708
Accumulated Depreciation, Depletion and Amortization		(1,027,982	)		(944,627	)

	$	1,156,886		$	994,081

As of September 30, 2005, we did not have any significant changes from year-end in our amount of capitalized well costs that have been capitalized for greater than one year after drilling was suspended.

During the third quarter of 2004, the Company recorded an impairment of approximately $3.5 million on a two-well field in south Louisiana resulting from production performance issues related to water encroachment. This impairment charge was recorded due to the capitalized cost of the fields exceeding the future undiscounted cash flows. This charge was reflected in the quarterly results and was measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related field. There were no impairments of proved oil and gas properties during the nine months ended September 30, 2005.

During the nine months ended September 30, 2005, we spent $60.4 million on producing property acquisitions. Of this amount, $59.4 million was spent in the third quarter of 2005. During the quarter, the Company closed on two large producing property acquisitions for interests in fields in the Gulf Coast. For the McCampbell field acquisition, we spent $41.2 million. The Vernon field acquisition was $18.0 million.

3. INVENTORIES

Inventories are comprised of the following:


	September 30, 2005		December 31, 2004
	*(In thousands)*
Natural Gas and Oil in Storage	$	25,210	$	17,631
Tubular Goods and Well Equipment		8,696		6,387
Pipeline Imbalances		1,567		31

	$	35,473	$	24,049

4. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:


	September 30, 2005			December 31, 2004
	*(In thousands)*
Accounts Receivable
Trade Accounts	$	109,988		$	105,378
Joint Interest Accounts		14,609			13,554
Current Income Tax Receivable		12,203			10,796
Other Accounts		394			1,312

		137,194			131,040
Allowance for Doubtful Accounts		(5,354	)		(5,286	)

	$	131,840		$	125,754

Other Current Assets
Derivative Contracts	$	—		$	2,906
Drilling Advances		3,348			6,180
Prepaid Balances		5,786			4,173
Other Accounts		299			246

	$	9,433		$	13,505

Accounts Payable
Trade Accounts	$	9,514		$	12,808
Natural Gas Purchases		10,955			8,669
Royalty and Other Owners		40,439			35,369
Capital Costs		35,296			26,203
Taxes Other Than Income		8,592			5,634
Drilling Advances		6,486			7,102
Wellhead Gas Imbalances		2,317			1,991
Book Overdrafts		25,691			—
Other Accounts		5,458			7,193

	$	144,748		$	104,969

Accrued Liabilities
Employee Benefits	$	6,559		$	10,123
Taxes Other Than Income		14,456			14,191
Interest Payable		5,383			6,569
Other Accounts		2,806			1,725

	$	29,204		$	32,608

Other Liabilities
Postretirement Benefits Other Than Pension	$	5,796		$	4,717
Accrued Pension Cost		5,791			5,089
Rabbi Trust Deferred Compensation Plan		4,776			4,199
Accrued Plugging and Abandonment Liability		42,369			40,375
Derivative Contracts		8,926			—
Other Accounts		6,971			6,649

	$	74,629		$	61,029

5. LONG-TERM DEBT

At September 30, 2005, the Company had $10 million of debt outstanding under its Revolving Credit Agreement (Credit Facility), which 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. To expand the credit line, the Company must seek prior approval from the administrative agent and the bank whose commitment is increasing. The term of the Credit Facility expires in December 2009. The Credit Facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of six months to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or pay down one-sixth of the excess during each of the six months.

In addition to the $10 million of debt outstanding on the Credit Facility, the Company has the following debt outstanding at September 30, 2005:

•

$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

6. EARNINGS PER SHARE

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

The following is a calculation of basic and diluted weighted average shares outstanding for the three months and nine months ended September 30, 2005 and 2004.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2005	2004	2005	2004
Shares - basic	48,951,439	48,821,794	48,865,202	48,736,114
Dilution effect of stock options and awards at end of period	713,848	596,885	747,805	592,461

Shares - diluted	49,665,287	49,418,679	49,613,007	49,328,575

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

7. COMMITMENTS AND CONTINGENCIES

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of our 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.

Wyoming Royalty Litigation

In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court, as reported in previous filings. The plaintiffs made claims pertaining to deductions from their overriding royalty and claims concerning penalties for improper reporting. As a result of several decisions by the Court favorable to the Company, the case was settled in September 2005 with no payment from the Company and a dismissal with prejudice of all claims by plaintiffs. The settlement included provisions for reporting and payment going forward. Management has reversed the reserve it had recorded regarding this case.

West Virginia Royalty Litigation

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

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The court entered an order on June 1, 2005 granting the motion for class certification. The parties have negotiated a modification to the order which, if entered by the court, would result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings. Trial has been set for April 17, 2006. The Company intends to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.

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

Texas Title Litigation

On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs 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, 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. 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 is approximately $15.2 million, and that the carrying value of this property is approximately $33.7 million.

Although the investigation into this claim continues, the Company intends to vigorously defend the case. Should the Company receive an adverse ruling in this case, an impairment review would be assessed to determine whether the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

Raymondville Area

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

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

Cody has signed a settlement agreement with certain of the defendants representing approximately 3% of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. In August, 2005, the trial judge entered an order granting Cody’s Motion for Summary Judgment requiring the remaining defendant to assign to Cody all of its interest in the prospect and to remove the lien filed against Cody’s interest. The defendant has filed a Motion for Reconsideration and Opposition to Proposed Order. The court is scheduled to consider these two motions in December 2005.

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 $14.9 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.

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 September 30, 2005, the Company had 20 cash flow hedges open: 11 natural gas price collar arrangements, 2 crude oil price collars and 7 natural gas price swap arrangements. Additionally, the Company had 2 crude oil financial instruments open at September 30, 2005, that did not qualify for hedge accounting. At September 30, 2005, a $114.8 million ($70.8 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $114.6 million short term derivative liability and an $8.9 million long term derivative liability, which is included in other long term 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.

Assuming no change in commodity prices, after September 30, 2005 the Company would reclassify to the Statement of Operations, over the next 12 months, $65.4 million in after-tax expenditures associated with commodity hedges. This reclassification represents the net liability associated with open positions currently not reflected in earnings at September 30, 2005 related to remaining anticipated 2005 production and a portion of anticipated 2006 production.

From time to time, the Company enters into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At September 30, 2005, the fair value of the Company’s two open crude oil swap arrangements was $7.3 million, and is reported as a component of Derivative Contracts in the liability section of the accompanying Condensed Consolidated Balance Sheet. The total loss related to these arrangements was $2.9 million and $12.2 million for the three months and nine months ended September 30, 2005, respectively, and has been reported as a component of Operating Revenues in the accompanying Condensed Consolidated Statement of Operations.

9. 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 nine month periods ended September 30, 2005 and 2004.


	Nine Months Ended September 30,
	2005						2004
	*(In thousands)*
Accumulated Other Comprehensive Loss - Beginning of Period				$	(20,351	)				$	(23,135	)
Net Income	$	89,940					$	56,151

Other Comprehensive Loss Reclassification Adjustment for Settled Contracts		41,215						30,159
Changes in Fair Value of Hedge Positions		(127,199	)					(67,143	)
Minimum Pension Liability		2,081						—
Foreign Currency Translation Adjustment		1,410						337
Deferred Income Tax		31,526						13,967

Total Other Comprehensive Loss	$	(50,967	)	$	(50,967	)	$	(22,680	)	$	(22,680	)

Comprehensive Income	$	38,973					$	33,471

Accumulated Other Comprehensive Loss - End of Period				$	(71,318	)				$	(45,815	)

Comprehensive income (loss) for the three months ended September 30, 2005 and 2004 was ($16.5) million and $13.1 million, respectively.

Deferred income tax of $31.5 million for the nine months ended September 30, 2005 represents the net deferred tax liability of ($15.8) million on the Reclassification Adjustment for Settled Contracts, $48.7 million on the Changes in Fair Value of Hedge Positions, ($0.8) million on the Minimum Pension Liability Adjustment and ($0.6) million on the Foreign Currency Translation Adjustment.

Deferred income tax of $14.0 million for the nine months ended September 30, 2004 represents the net deferred tax liability of ($11.5) million on the Reclassification Adjustment for Settled Contracts, $25.6 million on the Changes in Fair Value of Hedge Positions, and less than ($0.1) million on the Foreign Currency Translation Adjustment.

10. ASSET RETIREMENT OBLIGATIONS

The following table reflects the changes of the asset retirement obligations during the nine months ended September 30, 2005.


*(In thousands)*
Carrying amount of asset retirement obligations at December 31, 2004	$	40,375
Liabilities added during the current period		1,044
Liabilities settled during the current period		(81	)
Current period accretion expense		1,087
Revisions to estimated cash flows		(56	)

Carrying amount of asset retirement obligations at September 30, 2005	$	42,369

Accretion expense was $1.1 million and $1.4 million for the nine months ended September 30, 2005 and 2004, respectively, and is included within Depletion, Depreciation and Amortization expense on the Company’s Condensed Consolidated Statement of Operations.

11. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs for the three months and nine months ended September 30, 2005 and 2004 are as follows:


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2005			2004			2005			2004
	*(In thousands)*
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	558		$	504		$	1,674		$	1,511
Interest Accrued on Pension Obligation		495			520			1,485			1,559
Expected Return on Plan Assets		(355	)		(369	)		(1,065	)		(1,106	)
Net Amortization and Deferral		44			41			132			124
Recognized Loss		225			203			675			608

Net Periodic Benefit Costs	$	967		$	899		$	2,901		$	2,696

Postretirement Benefits Other than Pension Plans
Service Cost of Benefits Earned During the Period	$	169		$	71		$	507		$	213
Interest Cost on the Accumulated Postretirement Benefit Obligation		151			93			453			278
Plan Termination Loss		80			—			240			—
Amortization Benefit of the Unrecognized Gain		(20	)		(31	)		(60	)		(92	)
Amortization of Prior Service Cost		227			—			681			—
Amortization Benefit of the Unrecognized Transition Obligation		162			165			486			496

Total Postretirement Benefit Cost	$	769		$	298		$	2,307		$	895

The Company does not have any required minimum funding obligations for its qualified pension plan in 2005. The Company, however, has made a $2.0 million discretionary contribution in the first nine months of 2005. Management has not determined if any additional discretionary funding will be made in the fourth quarter.

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 September 30, 2005, and the related condensed consolidated statement of operations for each of the three and nine month periods ended September 30, 2005 and 2004 and the condensed consolidated statement of cash flows for the nine month periods ended September 30, 2005 and 2004. 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 previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated balance sheet as of December 31, 2004 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, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report dated March 2, 2005, 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 consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

October 28, 2005

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

The following review of operations for the three and nine month periods ended September 30, 2005 and 2004 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, 2004.

Overview

Natural gas revenues increased by $61.0 million for the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004. The increase is due to increased realized natural gas prices as well as increased production. Oil revenues increased by $22.4 million for the first nine months of 2005 as compared to the first nine months of 2004. This increase is primarily due to an increase in oil prices of 40% in the first nine months of 2005 as compared to the first nine months of 2004. Additionally, the unrealized loss on crude oil derivatives decreased by $11.4 million in the first nine months of 2005 from the comparable prior year period. Somewhat offsetting the crude oil price increase and the decrease in the unrealized loss was the decrease in crude oil production in the first nine months of 2005.

In the first nine months of 2005, natural gas prices were higher than the comparable period of the prior year and our financial results reflect their impact. Our realized natural gas price was $6.16 per Mcf, 21% higher than the $5.10 per Mcf price realized in the same period of the prior year. These realized prices are impacted by realized 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, NGLs and crude oil prices, and therefore, cannot accurately predict revenues.

For the nine months ended September 30, 2005, we produced 62.9 Bcfe compared to production of 63.5 Bcfe for the comparable period of the prior year, reflecting the deferral of approximately 1.0 Bcfe of expected production from the two hurricanes that impacted the Gulf Coast in the third quarter of 2005. Natural gas production was 54.8 Bcf and oil production was 1,346 Mbbls. Natural gas production increased slightly when compared to the comparable period of the prior year, which had production of 54.2 Bcf. We increased production in all regions except our Gulf Coast region. Our East region increased production with the success of the increased drilling program in 2004 and 2005. In the West region, we have had a successful drilling and recompletion program this year. In addition, production in Canada increased as a result of having a full nine months of production in the current year. These increases are partially offset by reduced production in our Gulf Coast region as a result of the hurricanes experienced in Louisiana during the third quarter of 2005 as well as the natural decline of gas production in south Louisiana. Oil production decreased by 186 Mbbls from 1,532 Mbbls in the first nine months of 2004 to 1,346 Mbbls produced in the first nine months of 2005. The decrease in oil production is primarily the result of the continued natural decline of the CL&F lease in south Louisiana and decreased production from properties, which are currently producing below capacity, after the impact of the hurricanes that occurred during the third quarter in Louisiana, including non-operated offshore properties that are currently shut-in.

We had net income of $89.9 million, or $1.84 per share, for the nine months ended September 30, 2005 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 $30.0 million and an increase in income tax expense of $19.1 million in the first nine months of 2005 as compared to the first nine months of 2004.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. In 2005, we expect to spend approximately $400 million in capital and exploration expenditures, which includes a layer of investment for new projects that may arise during the remainder of 2005. This figure has increased by $70 million from $330 million previously reported in order to reflect increased drilling as well as new projects. During the third quarter of 2005,

we closed on two large producing property acquisitions for interests in fields in the Gulf Coast. For the McCampbell field acquisition, we spent $41.2 million. The Vernon field acquisition was $18.0 million. For the nine months ended September 30, 2005, $299.7 million of capital and exploration expenditures have been invested in our exploration and development efforts.

During the nine months ended September 30, 2005, we drilled 229 gross wells (207 development, 18 exploratory and 4 extension wells) with a success rate of 95% compared to 205 gross wells (190 development and 15 exploratory wells) with a success rate of 97% for the comparable period of the prior year. For the full year, we plan to drill approximately 330 gross wells compared to 256 gross wells in 2004.

We remain focused on our strategies of balancing our capital investments between acceptable risk and strongest economics, along with balancing longer life investments with impact exploration opportunities. In the current year we have allocated our planned program for capital and exploration expenditures among our various operating regions. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long term.

On February 28, 2005, we announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock in the form of a stock distribution, distributed on March 31, 2005 to stockholders of record on March 18, 2005. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of our Common Stock.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See “Forward-Looking Information” on page 33.

Financial Condition

Capital Resources and Liquidity

Our primary source of cash for the nine months ended September 30, 2005 was from funds generated from operations, as well as borrowings on our revolving credit facility and proceeds from the exercise of stock options under our stock plans. We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, as described in the Annual Report on Form 10-K, have influenced prices throughout the recent years. During the third quarter, approximately 1.0 Bcfe of expected production in our Gulf Coast region was deferred due to the impacts of Hurricanes Katrina and Rita. These events in Louisiana did not have a material adverse impact on our capital resources or liquidity. Working capital is 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, pay dividends and purchase treasury stock. During the nine months ended September 30, 2005 we purchased 19,700 shares of Cabot stock at a weighted average purchase price of $28.99. See below for additional discussion and analysis of cash flow.


	Nine Months Ended September 30,
*(In thousands)*	2005			2004
Cash Flows Provided by Operating Activities	$	247,111		$	215,929
Cash Flows Used by Investing Activities		(287,904	)		(190,252	)
Cash Flows Provided by Financing Activities		33,954			(1,515	)

Net (Decrease) / Increase in Cash and Cash Equivalents	$	(6,839	)	$	24,162

Operating Activities. Net cash provided by operating activities in the first nine months of 2005 increased $31.2 million over the comparable period in 2004. 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 21% over the 2004 period, while crude oil realized prices

increased 40% over the same period. Production volumes decreased slightly with a 1% decline in equivalent production in the first nine months of 2005 compared to the comparable period in 2004. 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 key components of cash used by investing activities are capital spending and exploration expense. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices our budget may be periodically adjusted during any given year. Cash flows used in investing activities increased by $97.7 million for the nine months ended September 30, 2005, compared to the same period in 2004. The increase from 2004 to 2005 is primarily due to proved property acquisitions in the third quarter and, to a lesser extent, an increase in drilling activity as a result of higher commodity prices.

Financing Activities. Cash flows provided by financing activities were $34.0 million for the nine months ended September 30, 2005. Cash flows used by financing activities were $1.5 million for the nine months ended September 30, 2004. Cash flows provided by financing activities in the first nine months of 2005 were the result of an increase in book overdrafts, borrowings under the Credit Facility and proceeds from the exercise of stock options, partially offset by dividend payments and the purchases of treasury stock.

At September 30, 2005, we had $10 million of debt outstanding under our Credit Facility, which 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. It 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.

On August 13, 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. Subsequent to this announcement, there was a 3-for-2 split of the Company’s Common Stock. As a result of this stock split, this figure has been adjusted to three million shares. During the first nine months of 2005, we repurchased 19,700 shares of our Common Stock. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. The approximate number of shares that may yet be purchased under the plan is 1,918,750. See “Issuer Purchases of Equity Securities” in Item 2 “Unregistered Sales of Equity Securities and Use of Proceeds” for additional information.

Capitalization

Our capitalization information is as follows:


	September 30, 2005			December 31, 2004
	*(In millions)*
Debt⁽¹⁾	$	280.0		$	270.0
Stockholders’ Equity^(2) (3)		502.3			455.7

Total Capitalization	$	782.3		$	725.7

Debt to Capitalization ⁽³⁾		36	%		37	%

Cash and Cash Equivalents	$	3.2		$	10.0

⁽¹⁾

Includes $20.0 million of current portion of long-term debt.

⁽²⁾

Includes common stock, net of treasury stock.

⁽³⁾

Includes the impact of the Accumulated Other Comprehensive Loss at September 30, 2005 and December 31, 2004 of $71.3 million and $20.4 million, respectively.

During the nine months ended September 30, 2005, we paid dividends of $5.3 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. We expect to pay additional incremental dividends of approximately $2.0 million in 2005 as a result of the 3-for-2 stock split.

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, 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:


	Nine Months Ended September 30,
	2005		2004
	*(In millions)*
Capital Expenditures
Drilling and Facilities	$	163.2	$	136.3
Leasehold Acquisitions		15.6		12.0
Pipeline and Gathering		12.0		10.1
Other		1.1		1.0

		191.9		159.4

Proved Property Acquisitions		60.4		1.8
Exploration Expense		47.4		32.7

Total	$	299.7	$	193.9

We plan to drill approximately 330 gross wells in 2005. This drilling program includes approximately $400 million in total capital and exploration expenditures. See the “Overview” discussion for additional information regarding the current year drilling program. We will continue to assess the natural gas 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. There have been no changes to our critical accounting policies from those described in the 2004 Form 10-K. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, for further discussion.

Results of Operations

Third Quarters of 2005 and 2004 Compared

We reported Net Income in the third quarter of 2005 of $33.8 million, or $0.69 per share. During the corresponding quarter of 2004, we reported Net Income of $17.8 million, or $0.37 per share. Operating Income increased $24.7 million compared to the prior year, from $34.3 million in the third quarter of 2004 to $59.0 million in the third quarter of 2005. 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. Net Income increased in the current quarter by $15.9 million due to an increase in Operating Income partially offset by an increase of $9.0 million in Income Tax Expense.

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 September 30, 2005 compared to $5.07 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $1.26 per Mcf in 2005 and $0.59 per Mcf in 2004. The following table excludes the unrealized loss from the change in derivative fair value of $0.4 million and the unrealized gain of $0.3 million for the three months ended September 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.


	Three Months Ended September 30,					Variance
	2005			2004		Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		6,333			8,350		(2,017	)	(24	)%
West		5,961			5,498		463		8	%
East		5,453			5,004		449		9	%
Canada		264			37		227		614	%

Total Company		18,011			18,889		(878	)	(5	)%

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	6.67		$	5.26	$	1.41		27	%
West	$	5.91		$	4.68	$	1.23		26	%
East	$	7.75		$	5.19	$	2.56		49	%
Canada	$	8.04		$	4.39	$	3.65		83	%
Total Company	$	6.77		$	5.07	$	1.70		34	%

Natural Gas Production Revenue (in thousands)
Gulf Coast	$	42,253		$	43,902	$	(1,649	)	(4	)%
West		35,229			25,725		9,504		37	%
East		42,280			25,975		16,305		63	%
Canada		2,123			160		1,963		1227	%

Total Company	$	121,885		$	95,762	$	26,123		27	%

(in thousands)
Price Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	8,954
West		7,340
East		13,973
Canada		965

Total Company	$	31,232

(in thousands)
Volume Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	(10,603	)
West		2,164
East		2,332
Canada		998

Total Company	$	(5,109	)

The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. Partially offsetting this increase was the decrease in production due to decreases in the Gulf Coast region as a result of the hurricanes in the third quarter as discussed above and natural production declines. The increase in the realized natural gas price partially offset by the decrease in production resulted in a net revenue increase of $26.1 million, excluding the unrealized impact of derivative instruments.

Brokered Natural Gas Revenue and Cost


	Three Months Ended September 30,					Variance
	2005			2004		Amount			Percent
Sales Price ($/Mcf)	$	9.41		$	6.38	$	3.03		47	%
Volume Brokered (Mmcf)		1,994			2,079		(85	)	(4	)%

Brokered Natural Gas Revenues (in thousands)	$	18,756		$	13,224

Purchase Price ($/Mcf)	$	8.30		$	5.59	$	2.71		48	%
Volume Brokered (Mmcf)		1,994			2,079		(85	)	(4	)%

Brokered Natural Gas Cost (in thousands)	$	16,550		$	11,627

Brokered Natural Gas Margin (in thousands)	$	2,206		$	1,597	$	609		38	%

(in thousands)
Sales Price Variance Impact on Revenue	$	6,042
Volume Variance Impact on Revenue		(542	)

	$	5,500

(in thousands)
Purchase Price Variance Impact on Purchases	$	(5,366	)
Volume Variance Impact on Purchases		475

	$	(4,891	)

The increased brokered natural gas margin of $0.6 million was driven by higher volume combined with an increased sales price that outpaced the increase in purchase cost.

Crude Oil and Condensate Revenues

Our average total company realized Crude Oil Sales Price, including the realized impact of derivative instruments, was $46.05 per Bbl for the third quarter of 2005 and $32.03 per Bbl for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $14.59 per Bbl in 2005 and $10.87 per Bbl in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $2.0 million and the unrealized loss of $7.4 million for the three months ended September 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.


	Three Months Ended September 30,					Variance
	2005			2004		Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		364			450		(86	)	(19	)%
West		43			37		6		16	%
East		7			7		—		—
Canada		5			1		4		400	%

Total Company		419			495		(76	)	(15	)%

Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	43.93		$	31.01	$	12.92		42	%
West	$	60.77		$	42.85	$	17.92		42	%
East	$	59.22		$	39.64	$	19.58		49	%
Canada	$	52.94		$	36.63	$	16.31		45	%
Total Company	$	46.05		$	32.03	$	14.02		44	%

Crude Oil Revenue (in thousands)
Gulf Coast	$	15,970		$	13,961	$	2,009		14	%
West		2,642			1,604		1,038		65	%
East		440			269		171		64	%
Canada		246			52		194		373	%

Total Company	$	19,298		$	15,886	$	3,412		21	%

(in thousands)
Price Variance Impact on Crude Oil Revenue
Gulf Coast	$	4,666
West		779
East		171
Canada		47

Total Company	$	5,663

(in thousands)
Volume Variance Impact on Crude Oil Revenue
Gulf Coast	$	(2,657	)
West		259
East		—
Canada		147

Total Company	$	(2,251	)

The decrease in oil production is primarily the result of the decreased Gulf Coast production. This is a result of continued natural decline of the CL&F lease in south Louisiana, as well as the impact of hurricanes which includes the shutting in and deferring of production at the Breton Sound offshore lease. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $3.4 million, excluding the unrealized impact of derivative instruments.

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 September 30,
	2005						2004
	Realized			Unrealized			Realized			Unrealized
	*(In thousands)*
Operating Revenues - Increase/(Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	(22,723	)	$	(408	)	$	(11,080	)	$	349
Crude Oil		(1,165	)		(24	)		—			—

Total Cash Flow Hedges		(23,888	)		(432	)		(11,080	)		349
Other Derivative Financial Instruments
Crude Oil		(4,948	)		2,062			(5,393	)		(7,372	)

Total Cash Flow and Non-Qualifying Hedges	$	(28,836	)	$	1,630		$	(16,473	)	$	(7,023	)

Other Operating Revenues

Other operating revenues decreased by $1.4 million between the third quarter of 2005 and the third quarter of 2004 primarily due to a decrease in cash received for net profits interest. This variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year third quarter period.

Operating Expenses

Total costs and expenses from operations increased $17.5 million in the third quarter of 2005 compared to the same quarter of 2004. The primary reasons for this fluctuation are as follows:

•

Exploration expense increased by $9.7 million in the third quarter of 2005, primarily as a result of increased dry hole expense as well as an increase in other land expenses partially offset by decreased spending for geological and geophysical costs. During the third quarter of 2005, we incurred $8.9 million more dry hole expense, mainly as a result of an increase in the Gulf Coast and to a lesser extent in the West region, compared to the third quarter of 2004.

•

Brokered natural gas costs increased by $4.9 million from the third quarter of 2004 to the third quarter of 2005. See the preceding table labeled Brokered Natural Gas Revenue and Cost for further analysis.

•

Taxes Other Than Income increased by $4.8 million, or 48%, from the third quarter of 2004 compared to the third quarter of 2005, primarily due to increased production taxes as a result of increased commodity prices.

•

Impairment of Oil and Gas Properties decreased by $3.5 million as we incurred no impairment expense during the current quarter. The costs incurred in the third quarter of 2004 related to a field in south Louisiana. Further analysis of this impairment is discussed in Footnote 2 “Properties & Equipment” to the financial statements.

•

Depreciation, Depletion and Amortization decreased by $1.2 million in the third quarter of 2005. This is primarily due to decreased production for the quarter partially offset by an increase in the DD&A rate associated with the commencement of offshore production in late 2004.

•

Impairment of Unproved Properties increased by $1.0 million over the comparable three months of 2004. This is due to increased amortization related to unproved property additions both offshore and onshore, including an increase in our Canadian additions.

•

Direct Operations expense increased by $0.9 million over the third quarter of 2004. This is primarily the result of an increase over the prior year quarter in expenses for outside operated properties, increased workover costs and an increase in employee related expenses.

•

General and Administrative expense increased by $0.7 million in the third quarter of 2005. This increase is primarily due to increased stock compensation costs of $1.8 million, mainly related to the accrual associated with the 2004 and 2005 performance share awards. Partially offsetting these increases was a decrease in miscellaneous expenses, primarily the reversal of the reserve attributable to litigation that was settled in the quarter.

Interest Expense, net

Interest expense, net decreased $0.2 million in the third quarter of 2005. This decrease is the result of increased interest income on our short term investments. Interest expense related to borrowings under the Credit Facility was higher in the current quarter due to higher average borrowings. Average borrowings based on month end balances for the third quarter of 2005 were approximately $52 million compared to approximately $31 million in the third quarter of 2004.

Income Tax Expense

Income tax expense increased by $9.0 million due to a comparable increase in our pre-tax income.

Nine Months of 2005 and 2004 Compared

We reported Net Income in the first nine months of 2005 of $89.9 million, or $1.84 per share. During the corresponding period of 2004, we reported Net Income of $56.2 million, or $1.15 per share. Operating Income increased by $52.0 million in the first nine months of 2005 compared to the prior year. 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. Net Income increased in the first nine months of 2005 by $33.7 million due to an increase in Operating Income partially offset by an increase of $19.1 million in Income Tax Expense.

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $6.16 per Mcf for the nine months ended September 30, 2005 compared to $5.10 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.73 per Mcf in 2005 and $0.57 per Mcf in 2004. The following table excludes the unrealized loss from the change in derivative fair value of $0.2 million and $0.1 million for the nine months ended September 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.


	Nine Months Ended September 30,					Variance
	2005			2004		Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		21,007			23,626		(2,619	)	(11	)%
West		17,337			16,280		1,057		6	%
East		15,669			14,283		1,386		10	%
Canada		818			37		781		2111	%

Total Company		54,831			54,226		605		1	%

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	6.26		$	5.17	$	1.09		21	%
West	$	5.38		$	4.72	$	0.66		14	%
East	$	6.90		$	5.41	$	1.49		28	%
Canada	$	5.95		$	4.39	$	1.56		36	%
Total Company	$	6.16		$	5.10	$	1.06		21	%

Natural Gas Production Revenue (in thousands)
Gulf Coast	$	131,548		$	122,257	$	9,291		8	%
West		93,229			76,846		16,383		21	%
East		108,109			77,323		30,786		40	%
Canada		4,866			161		4,705		2922	%

Total Company	$	337,752		$	276,587	$	61,165		22	%

(in thousands)
Price Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	22,843
West		11,396
East		23,284
Canada		1,277

Total Company	$	58,800

(in thousands)
Volume Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	(13,552	)
West		4,987
East		7,502
Canada		3,428

Total Company	$	2,365

The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. In addition, the increase in production was due to the successful drilling programs in the West and East as well as the commencement of Canada natural gas production late in 2004. Partially offsetting this was the decrease in the Gulf Coast production. The increase in the realized natural gas price combined with the increase in production resulted in a net revenue increase of $61.2 million, excluding the unrealized impact of derivative instruments.

Brokered Natural Gas Revenue and Cost


	Nine Months Ended September 30,					Variance
	2005			2004		Amount			Percent
Sales Price ($/Mcf)	$	7.82		$	6.24	$	1.58		25	%
Volume Brokered (Mmcf)		7,773			9,683		(1,910	)	(20	)%

Brokered Natural Gas Revenues (in thousands)	$	60,768		$	60,411

Purchase Price ($/Mcf)	$	6.89		$	5.57	$	1.32		24	%
Volume Brokered (Mmcf)		7,773			9,683		(1,910	)	(20	)%

Brokered Natural Gas Cost (in thousands)	$	53,549		$	53,944

Brokered Natural Gas Margin (in thousands)	$	7,219		$	6,467	$	752		12	%

(in thousands)
Sales Price Variance Impact on Revenue	$	12,291
Volume Variance Impact on Revenue		(11,918	)

	$	373

(in thousands)
Purchase Price Variance Impact on Purchases	$	(10,260	)
Volume Variance Impact on Purchases		10,639

	$	379

The increased brokered natural gas margin of $0.8 million was driven by an increased sales price that outpaced the increase in purchase cost, offset in part by a decrease in volume.

Crude Oil and Condensate Revenues

Our average total company realized Crude Oil Sales Price, including the realized impact of derivative instruments, was $43.92 per Bbl for the first nine months of 2005 and $31.36 per Bbl for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $8.93 per Bbl in 2005 and $7.11 per Bbl in 2004. The following table excludes the unrealized loss from the change in derivative fair value of $1.9 million and $13.2 million for the nine months ended September 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.


	Nine Months Ended September 30,					Variance
	2005			2004		Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		1,189			1,391		(202	)	(15	)%
West		123			120		3		3	%
East		20			20		—		—
Canada		14			1		13		1300	%

Total Company		1,346			1,532		(186	)	(12	)%

Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	42.72		$	30.71	$	12.01		39	%
West	$	54.21		$	38.06	$	16.15		42	%
East	$	52.98		$	35.99	$	16.99		47	%
Canada	$	42.23		$	36.63	$	5.60		15	%
Total Company	$	43.92		$	31.36	$	12.56		40	%

Crude Oil Revenue (in thousands)
Gulf Coast	$	50,804		$	42,705	$	8,099		19	%
West		6,651			4,568		2,083		46	%
East		1,074			733		341		47	%
Canada		586			52		534		1027	%

Total Company	$	59,115		$	48,058	$	11,057		23	%

(in thousands)
Price Variance Impact on Crude Oil Revenue
Gulf Coast	$	14,316
West		1,981
East		341
Canada		45

Total Company	$	16,683

(in thousands)
Volume Variance Impact on Crude Oil Revenue
Gulf Coast	$	(6,217	)
West		102
East		—
Canada	$	489

Total Company	$	(5,626	)

The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $11.1 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is primarily the result of the decrease in the Gulf Coast region production due to the continued natural decline of the CL&F lease in south Louisiana, as well as the impact of hurricanes which included the shutting in and deferring of production at the Breton Sound offshore lease.

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:


	Nine Months Ended September 30,
	2005						2004
	Realized			Unrealized			Realized			Unrealized
	*(In thousands)*
Operating Revenues - Increase/(Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	(40,211	)	$	(186	)	$	(31,009	)	$	(69	)
Crude Oil		(1,552	)		(103	)		—			—

Total Cash Flow Hedges	$	(41,763	)	$	(289	)	$	(31,009	)	$	(69	)
Other Derivative Financial Instruments
Crude Oil		(10,470	)		(1,762	)		(10,889	)		(13,225	)

Total Cash Flow and Non-Qualifying Hedges	$	(52,233	)	$	(2,051	)	$	(41,898	)	$	(13,294	)

Other Operating Revenues

Other operating revenues decreased $1.9 million from the first nine months of 2004 to the first nine months of 2005. This change was primarily a result of an increase in our payout liability, associated with the reduction of our interest due to reversionary interest owned by others, which correspondingly decreased other operating revenues. This variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous nine month period.

Operating Expenses

Total costs and expenses from operations increased $30.0 million in the first nine months of 2005 compared to the comparable period of 2004. The primary reasons for this fluctuation are as follows:

•

Exploration expense increased $14.7 million in 2005, primarily as a result of increased dry hole expenses partially offset by decreased spending on geological and geophysical expenses. During the first nine months of 2005, we spent $6.8 million less on geological and geophysical activities and incurred an additional $20.0 million in dry hole expense. The increase in dry hole expense is mainly due to expenses incurred in Canada as well as in the Gulf Coast.

•

Taxes Other Than Income increased by $6.9 million from the first nine months of 2004 compared to the first nine months of 2005, primarily due to increased production taxes as a result of increased commodity prices.

•

Direct Operations expense increased by $4.7 million over the first nine months of 2004. This is primarily the result of increased expenses for outside operated properties and workovers. In addition, there was an increase over the prior year in employee related expenses.

•

Impairment of Oil and Gas Properties decreased by $3.5 million as we incurred no impairment expense in the current year. The costs incurred in the third quarter of 2004 related to a field in south Louisiana. Further analysis of this impairment is discussed in Footnote 2 “Properties & Equipment” to the financial statements.

•

Depreciation, Depletion and Amortization increased by $2.8 million in the first nine months of 2005. This is primarily due to an increase in offshore DD&A rates associated with the commencement of offshore production in late 2004 and increased production during the first half of 2005.

•

Impairment of Unproved Properties increased $2.8 million over the comparable quarter of 2004. This is due to increased amortization related to unproved property additions both offshore and onshore, including an increase in our Canadian additions.

•

General and Administrative expense increased by $2.0 million in the first nine months of 2005. This increase is primarily due to increased legal expenses in the first nine months of 2005 over the first nine months of 2004 as well as increased stock compensation expense relating to performance share awards and higher employee related expenses. Partially offsetting these increases was a decrease in miscellaneous expenses, primarily the reversal of the reserve attributable to litigation that was settled in the 2005 period.

Interest Expense, net

Interest expense, net decreased $1.1 million in the first nine months of 2005. This variance is mainly a result of increased income on our short term investments.

Income Tax Expense

Income tax expense increased $19.1 million due to a comparable increase in our pre-tax income.

Recently Issued Accounting Pronouncements

In March 2005, the Financial Accounting Standard Board (FASB) issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation, since we currently record all asset retirement obligations.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS 123(R) revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS 123(R) are now effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this SFAS until the first quarter of 2006. We plan to use the modified prospective application method as detailed in SFAS 123(R). We are currently evaluating the impact on our operating results. Our future cash flows will not be impacted by the adoption of this standard. See “Stock-Based Compensation” below for further information.

Additionally, in September 2005, the FASB issued Proposed FASB Staff Position (FSP) FAS 123(R)-c which provides a simpler, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS 123(R). Under this Proposed FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS 123(R) adoption date will not be affected by this Proposed FSP and will be calculated in accordance with SFAS 123(R) which requires that only the excess tax benefit or deficiency of the tax deduction over the

tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the Proposed FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS 123(R) for the calculation of the APIC pool. If finalized, we will adopt this Proposed FSP in conjunction with the adoption of SFAS 123(R).

In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, we are allowed to use the date the award is approved in accordance with its corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. We will adopt this FSP in conjunction with the adoption of SFAS 123(R).

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 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, which had borrowings of $10 million outstanding at September 30, 2005, 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. During the first nine months of 2005, natural gas price swaps covered 15,375 Mmcf, or 28%, of our gas production, fixing the sales price of this gas at an average of $5.14 per Mcf.

At September 30, 2005, we had open natural gas price swap contracts covering our 2005 production as follows:


	Natural Gas Price Swaps
Contract Period	Volume in Mmcf	Weighted Average Contract Price		Unrealized Loss *(In thousands)*
As of September 30, 2005
*Natural Gas Price Swaps on Production in:*
Fourth Quarter 2005	5,181	$	5.14

Three Months Ended December 31, 2005	5,181	$	5.14	$	(47,164	)

From time to time, we enter into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At September 30, 2005, the fair value of our two open crude oil swap arrangements was $7.3 million, and is reported as a component of Derivative Contracts in the liability section of the accompanying Condensed Consolidated Balance Sheet. The total loss related to these arrangements was an increase of $2.1 million and a decrease of $1.8 million for the three months and nine months ended September 30, 2005, respectively, and has been reported as a component of Operating Revenues in the accompanying Condensed Consolidated Statement of Operations.

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 falls below the floor price, the counterparty pays us. During the first nine months of 2005, natural gas price collars covered 11,753 Mmcf, or 21%, of our 2005 gas production, with a weighted average floor of $5.67 per Mcf and a weighted average ceiling of $8.68 per Mcf.

At September 30, 2005, we had open natural gas price collar contracts covering our 2005 and 2006 production as follows:


	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling / Floor		Unrealized Loss *(In thousands)*
As of September 30, 2005
Fourth Quarter 2005	3,404	$	8.38 / $5.30

Three Months Ended December 31, 2005	3,404	$	8.38 /$5.30	$	(22,380	)

First Quarter 2006	5,860	$	12.31 / $7.98
Second Quarter 2006	5,926		12.31 / 7.98
Third Quarter 2006	5,990		12.31 / 7.98
Fourth Quarter 2006	5,990		12.31 / 7.98

Full Year 2006	23,766	$	12.31 / $7.98	$	(43,751	)

During the first nine months of 2005, crude oil price collars covered 273 Mbbl, or 20%, of our 2005 oil production, with a weighted average floor of $40.00 per Bbl and a weighted average ceiling of $50.50 per Bbl. At September 30, 2005, we had two open crude oil price collar contracts covering our 2005 and 2006 production as follows:


	Crude Oil Price Collars
Contract Period	Volume in Mbbl	Weighted Average Ceiling / Floor		Unrealized Loss *(In thousands)*
As of September 30, 2005
Fourth Quarter 2005	92	$	50.50 / $40.00

Three Months Ended December 31, 2005	92	$	50.50 / $40.00	$	(1,914	)

First Quarter 2006	90	$	76.00 / $50.00
Second Quarter 2006	91		76.00 / 50.00
Third Quarter 2006	92		76.00 / 50.00
Fourth Quarter 2006	92		76.00 / 50.00

Full Year 2006	365	$	76.00 / $50.00	$	(1,006	)

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 33.

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 “Wyoming Royalty Litigation” and “Raymondville Area” in Note 7 of the Notes to Unaudited 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 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	Approximate Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 2005	—	$	—	—	1,918,750
August 2005	—	$	—	—	1,918,750
September 2005	—	$	—	—	1,918,750

Total	—	$	—

On August 13, 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. Subsequent to this announcement, on February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock. As a result of this stock split, this figure has been adjusted to three million shares. All purchases executed have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s Common Stock.

ITEM 5. Other Information

ITEM 6. Exhibits

15.1- Awareness letter of PricewaterhouseCoopers LLP

31.1- 302 Certification - Chairman, President and Chief Executive Officer

31.2- 302 Certification - Vice President and Chief Financial Officer

32.1- 906 Certification

SIGNATURES

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


	CABOT OIL & GAS CORPORATION
	(Registrant)

October 28, 2005	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

October 28, 2005	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

October 28, 2005	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)

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