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Cabot Oil & Gas 10-Q 2010
Form 10-Q for the Quarterly Period Ended September 30, 2010
Table of Contents

 

 

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, 2010

 

¨ 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)

Three Memorial City Plaza

840 Gessner Road, Suite 1400, Houston, Texas 77024

(Address of principal executive offices including ZIP code)

(281) 589-4600

(Registrant’s telephone number, including area code)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer    x   Accelerated filer    ¨   Non-accelerated filer    ¨   Smaller reporting company    ¨

(Do not check if a smaller reporting company)

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 26, 2010, there were 103,973,084 shares of Common Stock, Par Value $.10 Per Share, outstanding.

 

 

 


Table of Contents

 

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, 2010 and 2009

     3   

Condensed Consolidated Balance Sheet at September 30, 2010 and December 31, 2009

     4   

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2010 and 2009

     5   

Notes to the Condensed Consolidated Financial Statements

     6   

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

     20   

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

     21   

Item 3.      Quantitative and Qualitative Disclosures about Market Risk

     30   

Item 4.      Controls and Procedures

     32   

Part II. Other Information

  

Item 1.      Legal Proceedings

     32   

Item 1A.   Risk Factors

     32   

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

     32   

Item 5.      Other Information

     32   

Item 6.      Exhibits

     33   

Signatures

     34   

 

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Table of Contents

 

PART I. FINANCIAL INFORMATION

 

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 

(In thousands, except per share amounts)

   2010      2009      2010      2009  

OPERATING REVENUES

           

Natural Gas Production

   $ 187,094       $ 177,807       $ 512,936       $ 538,542   

Brokered Natural Gas

     11,675         9,032         49,896         54,117   

Crude Oil and Condensate

     19,234         19,574         60,427         50,026   

Other

     1,127         608         3,901         3,099   
                                   
     219,130         207,021         627,160         645,784   

OPERATING EXPENSES

           

Brokered Natural Gas Cost

     10,281         7,786         43,342         48,219   

Direct Operations - Field and Pipeline

     26,466         23,012         73,796         71,564   

Taxes Other Than Income

     8,489         10,719         31,135         34,531   

Exploration

     9,665         14,395         28,324         31,258   

Impairment of Oil & Gas Properties

     35,789         0         35,789         0   

Depreciation, Depletion and Amortization

     85,355         62,037         235,579         188,967   

General and Administrative

     21,077         14,921         49,675         49,103   
                                   
     197,122         132,870         497,640         423,642   

Gain / (Loss) on Sale of Assets

     265         572         5,411         (3,283
                                   

INCOME FROM OPERATIONS

     22,273         74,723         134,931         218,859   

Interest Expense and Other

     16,758         14,857         47,439         44,129   
                                   

Income Before Income Taxes

     5,515         59,866         87,492         174,730   

Income Tax Expense

     1,617         20,969         33,215         62,751   
                                   

NET INCOME

   $ 3,898       $ 38,897       $ 54,277       $ 111,979   
                                   

Earnings Per Share

           

Basic

   $ 0.04       $ 0.38       $ 0.52       $ 1.08   

Diluted

   $ 0.04       $ 0.37       $ 0.52       $ 1.07   

Weighted-Average Shares Outstanding

           

Basic

     103,955         103,647         103,889         103,603   

Diluted

     105,225         104,917         105,144         104,583   

Dividends per Common Share

   $ 0.03       $ 0.03       $ 0.09       $ 0.09   

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

 

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Table of Contents

 

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

 

(In thousands, except share amounts)

   September 30,
2010
    December 31,
2009
 

ASSETS

    

Current Assets

    

Cash and Cash Equivalents

   $ 37,588      $ 40,158   

Accounts Receivable, Net

     75,520        80,362   

Income Taxes Receivable

     3,913        8,909   

Inventories

     32,342        27,990   

Derivative Instruments

     65,294        114,686   

Other Current Assets

     6,328        9,397   
                

Total Current Assets

     220,985        281,502   

Properties and Equipment, Net (Successful Efforts Method)

     3,663,186        3,358,199   

Derivative Instruments

     4,245        0   

Other Assets

     58,294        43,700   
                
   $ 3,946,710      $ 3,683,401   
                

LIABILITIES AND STOCKHOLDERS’ EQUITY

    

Current Liabilities

    

Accounts Payable

   $ 168,042      $ 215,588   

Current Portion of Long-Term Debt

     75,000        0   

Deferred Income Taxes

     21,864        35,104   

Accrued Liabilities

     39,633        58,049   
                

Total Current Liabilities

     304,539        308,741   

Pension and Postretirement Benefits

     43,438        54,835   

Long-Term Debt

     1,020,000        805,000   

Deferred Income Taxes

     676,106        644,801   

Other Liabilities

     59,289        57,510   
                

Total Liabilities

     2,103,372        1,870,887   
                

Commitments and Contingencies (Note 6)

    

Stockholders’ Equity

    

Common Stock:

    

Authorized — 240,000,000 Shares of $0.10 Par Value in 2010 and 2009 Issued — 104,166,272 Shares and 103,856,447 Shares in 2010 and 2009, respectively

     10,417        10,386   

Additional Paid-in Capital

     714,172        705,569   

Retained Earnings

     1,102,401        1,057,472   

Accumulated Other Comprehensive Income

     19,697        42,436   

Less Treasury Stock, at Cost:

    

202,200 Shares in 2010 and 2009, respectively

     (3,349     (3,349
                

Total Stockholders’ Equity

     1,843,338        1,812,514   
                
   $ 3,946,710      $ 3,683,401   
                

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

 

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

 

    

Nine Months Ended

September 30,

 

(In thousands)

   2010     2009  

CASH FLOWS FROM OPERATING ACTIVITIES

    

Net Income

   $ 54,277      $ 111,979   

Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:

    

Depreciation, Depletion and Amortization

     235,579        188,967   

Impairment of Oil & Gas Properties

     35,789        0   

Deferred Income Tax Expense

     30,465        74,773   

(Gain) / Loss on Sale of Assets

     (5,411     3,283   

Exploration Expense

     10,473        31,258   

Unrealized Loss / (Gain) on Derivative Instruments

     (162     418   

Stock-Based Compensation Expense and Other

     13,182        19,894   

Changes in Assets and Liabilities:

    

Accounts Receivable, Net

     4,842        56,474   

Income Taxes

     4,937        (17,834

Inventories

     (4,353     8,908   

Other Current Assets

     3,070        2,435   

Accounts Payable and Accrued Liabilities

     (14,252     (49,097

Other Assets and Liabilities

     (836     (1,243

Stock-Based Compensation Tax Benefit

     (108     (13,085
                

Net Cash Provided by Operating Activities

     367,492        417,130   
                

CASH FLOWS FROM INVESTING ACTIVITIES

    

Capital Expenditures

     (658,123     (426,177

Proceeds from Sale of Assets

     21,033        80,180   
                

Net Cash Used in Investing Activities

     (637,090     (345,997
                

CASH FLOWS FROM FINANCING ACTIVITIES

    

Borrowings from Debt

     300,000        90,000   

Repayments of Debt

     (10,000     (147,000

Stock-Based Compensation Tax Benefit

     108        13,085   

Dividends Paid

     (9,348     (9,323

Capitalized Debt Issuance Costs

     (13,696     (10,409

Other

     (36     83   
                

Net Cash Provided by / (Used in) Financing Activities

     267,028        (63,564
                

Net (Decrease) / Increase in Cash and Cash Equivalents

     (2,570     7,569   

Cash and Cash Equivalents, Beginning of Period

     40,158        28,101   
                

Cash and Cash Equivalents, End of Period

   $ 37,588      $ 35,670   
                

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

 

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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 on Form 10-K for the year ended December 31, 2009 (Form 10-K) filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Certain reclassifications have been made to prior year statements to conform to the current year presentation. These reclassifications have no impact on net income.

In 2009, the Company reorganized its operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with its Texas and Louisiana areas to form the South region. Certain prior year amounts have been reclassified to reflect this reorganization. Additionally, the Company exited Canada through the sale of its properties. Prior to the third quarter of 2009, the Company presented the geographic areas as East, Gulf Coast, West and Canada.

With respect to the unaudited financial information of the Company as of September 30, 2010 and for the three and nine months ended September 30, 2010 and 2009, PricewaterhouseCoopers LLP reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated October 29, 2010 appearing herein states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

Recently Adopted Accounting Standards

In February 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-09, “Subsequent Events,” which amends Accounting Standards Codification (ASC) 855 to eliminate the requirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and its adoption had no impact on the Company’s financial position, results of operations or cash flows.

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, the Company will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on the Company’s financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please refer to Note 8.

 

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Table of Contents

CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

 

2. PROPERTIES AND EQUIPMENT, NET

Properties and equipment, net are comprised of the following:

 

(In thousands)

   September 30,
2010
    December 31,
2009
 

Unproved Oil and Gas Properties

   $ 476,996      $ 423,373   

Proved Oil and Gas Properties

     4,544,204        4,118,005   

Gathering and Pipeline Systems

     317,027        294,755   

Land, Building and Other Equipment

     83,797        77,474   
                
     5,422,024        4,913,607   

Accumulated Depreciation, Depletion and Amortization

     (1,758,838     (1,555,408
                
   $ 3,663,186      $ 3,358,199   
                

At September 30, 2010, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

The Company recorded a $35.8 million impairment of oil and gas properties in the third quarter 2010 due to continued price declines and limited activity in two south Texas fields. These fields were reduced to fair value of approximately $15.4 million using discounted future cash flows. The fair value of these fields was based on significant inputs that were not observable in the market and are considered to be level 3 inputs as defined in ASC 820. Refer to Note 8 for more information and a description of fair value hierarchy. Key assumptions include (1) oil and natural gas prices (adjusted to quality and basis differentials), (2) projections of estimated quantities of oil and gas reserves and production, (3) estimates of future development and production costs and (4) risk adjusted discount rates (14% at September 30, 2010).

Divestitures

In April 2009, the Company sold substantially all of its Canadian properties to a private Canadian company. Total consideration received from the sale was $84.4 million, consisting of $64.3 million in cash and $20.1 million in common stock of a privately held Canadian company (included in Other Assets in the Condensed Consolidated Balance Sheet at September 30, 2010 and December 31, 2009). The common stock investment is being accounted for using the cost method. The total net book value of the Canadian properties sold was $95.0 million.

The Company recognized a $3.3 million aggregate loss on sale of assets in the first nine months of 2009. The Company recorded a $16.0 million loss on sale of assets during the second quarter of 2009, primarily due to the sale of the Canadian properties described above. The Company recognized a $12.7 million gain on sale of assets in the first quarter of 2009 primarily related to the sale of the Thornwood properties in the North region. Cash proceeds of $11.4 million were received from the sale of the Thornwood properties.

In June 2010, the Company sold its Woodford shale prospect located in Oklahoma to Continental Resources, Inc. The Company received approximately $15.9 million in cash proceeds and recognized a $10.3 million gain on sale of assets.

In July 2010, the Company sold certain oil and gas properties located in Colorado to Patera Oil & Gas LLC for approximately $3.0 million. During the second quarter of 2010, the Company recognized an impairment loss of approximately $5.8 million associated with the proposed sale of these properties. The impairment charge is included in Gain / (Loss) on Sale of Assets in the Condensed Consolidated Statement of Operations. Fair value of the impaired properties was determined using a market approach which considered the execution of a purchase and sale agreement the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of assets held for sale were considered level 2 in the fair value hierarchy.

In September 2010, the Company signed a purchase and sale agreement with a private company to sell certain oil and gas properties in the Texas panhandle for $11.5 million. The transaction is expected to close in the fourth quarter of 2010. The net book value of these properties as of September 30, 2010 was $0.1 million.

 

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

 

3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

 

(In thousands)

   September 30,
2010
    December 31,
2009
 

ACCOUNTS RECEIVABLE, NET

    

Trade Accounts

   $ 71,501      $ 78,656   

Joint Interest Accounts

     6,334        3,564   

Other Accounts

     1,731        1,756   
                
     79,566        83,976   

Allowance for Doubtful Accounts

     (4,046     (3,614
                
   $ 75,520      $ 80,362   
                

INVENTORIES

    

Natural Gas in Storage

   $ 18,571      $ 14,434   

Tubular Goods and Well Equipment

     13,072        14,420   

Pipeline Imbalances

     699        (864
                
   $ 32,342      $ 27,990   
                

OTHER CURRENT ASSETS

    

Drilling Advances

   $ 1,922      $ 3,417   

Prepaid Balances

     4,406        5,980   
                
   $ 6,328      $ 9,397   
                

OTHER ASSETS

    

Investment in Equity Securities

   $ 20,636      $ 20,636   

Rabbi Trust Deferred Compensation Plan

     14,250        10,031   

Deferred Charges for Credit Agreements

     21,994        11,621   

Other Accounts

     1,414        1,412   
                
   $ 58,294      $ 43,700   
                

ACCOUNTS PAYABLE

    

Trade Accounts

   $ 23,556      $ 17,434   

Natural Gas Purchases

     5,001        3,558   

Royalty and Other Owners

     36,947        40,080   

Capital Costs

     87,265        141,122   

Taxes Other Than Income

     2,415        4,267   

Drilling Advances

     534        864   

Wellhead Gas Imbalances

     5,072        4,140   

Other Accounts

     7,252        4,123   
                
   $ 168,042      $ 215,588   
                

ACCRUED LIABILITIES

    

Employee Benefits

   $ 6,986      $ 11,222   

Pension and Postretirement Benefits

     1,469        1,469   

Taxes Other Than Income

     18,844        22,780   

Interest Payable

     11,010        20,205   

Derivative Instruments

     0        425   

Other Accounts

     1,324        1,948   
                
   $ 39,633      $ 58,049   
                

OTHER LIABILITIES

    

Rabbi Trust Deferred Compensation Plan

   $ 20,263      $ 19,087   

Asset Retirement Obligation

     30,797        29,676   

Derivative Instruments

     1,792        1,954   

Other Accounts

     6,437        6,793   
                
   $ 59,289      $ 57,510   
                

 

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

 

4. LONG-TERM DEBT

The Company’s debt consisted of the following:

 

(In thousands)

   September 30,
2010
    December 31,
2009
 

Long-Term Debt

    

7.33% Weighted-Average Fixed Rate Notes

   $ 170,000      $ 170,000   

6.51% Weighted-Average Fixed Rate Notes

     425,000        425,000   

9.78% Notes

     67,000        67,000   

Credit Facility

     433,000        143,000   

Current Maturities

    

7.33% Weighted-Average Fixed Rate Notes

     (75,000     0   
                

Long-Term Debt, excluding Current Maturities

   $ 1,020,000      $ 805,000   
                

In September 2010, the Company amended and restated its revolving credit facility. The credit facility provides for an available credit line of $900 million and contains an accordion feature allowing the Company to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. The credit facility also provides for the issuance of letters of credit, which would reduce the Company’s borrowing capacity. The amended facility provides for a $1.5 billion borrowing base and matures in September 2015.

All other terms and conditions of the amended credit facility are consistent with the terms and conditions of the April 2009 credit agreement, as amended in June 2010. The Company had previously amended the credit facility in June 2010 to provide that the Company’s asset coverage ratio under the credit facility be calculated in accordance with the agreements governing the senior notes, which are further discussed below.

In conjunction with entering into the September 2010 amended credit facility, the Company incurred $11.7 million of debt issuance costs, which were capitalized and will be amortized over the term of the amended credit facility. Approximately $6.3 million in unamortized costs associated with the original credit facility, as amended in June 2010, will be amortized over the term of the amended credit facility in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

In June 2010, the Company amended the agreements governing its senior notes to amend the required asset coverage ratio (the present value of the Company’s proved reserves plus working capital to debt) contained in the agreements. The amendments revised the calculation of present value of proved reserves to reflect specified pricing assumptions based on quoted futures prices in lieu of historical realized prices, reduced the limit on proved undeveloped reserves included in the calculation from 35% to 30%, and increased the required ratio to 1.75:1 from 1.50:1. The amendments also provided that for so long as a borrowing base calculation is required under the Company’s credit facility, the calculated indebtedness may not exceed 115% of such borrowing base for this ratio. If such a borrowing base calculation is not required under the credit facility, the Company would no longer be subject to the asset coverage ratio under the agreements, but would instead be required to maintain a ratio of debt to consolidated EBITDAX (as defined) not to exceed 3.0 to 1.0. In conjunction with the amendments, the Company incurred $2.0 million of debt issuance costs which were capitalized and are being amortized over the term of the respective amended agreements in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

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

At September 30, 2010, the Company had $433.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.78% and $466.7 million available for future borrowings. In addition, the Company had letters of credit outstanding at September 30, 2010 of $0.3 million.

 

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

 

5. EARNINGS PER COMMON SHARE

Basic 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 except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock options and stock appreciation rights were exercised and stock awards were vested at the end of the applicable period.

The following is a calculation of basic and diluted weighted-average shares outstanding for the three and nine months ended September 30, 2010 and 2009:

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2010      2009      2010      2009  

Weighted-Average Shares—Basic

     103,955         103,647         103,889         103,603   

Dilution Effect of Stock Options, Stock Appreciation Rights and Stock Awards at End of Period

     1,270         1,270         1,255         980   
                                   

Weighted-Average Shares—Diluted

     105,225         104,917         105,144         104,583   
                                   

Weighted-Average Stock Awards and Shares

           

Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect

     0         213         220         233   
                                   

6. COMMITMENTS AND CONTINGENCIES

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of business. When deemed necessary, the Company establishes reserves for certain legal proceedings. All known liabilities are accrued based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s condensed consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

While management believes established reserves are adequate, it is reasonably possible that the Company could incur approximately $1.0 million of additional loss with respect to those matters in which reserves have been established. Future changes in facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

Environmental Matters

On November 4, 2009, the Company and the Pennsylvania Department of Environmental Protection (PaDEP) entered into a single settlement agreement (Consent Order) covering a number of separate, unrelated environmental issues occurring in 2008 and 2009, including releases of drilling mud and other substances, record keeping violations at various wells and alleged natural gas contamination of 13 water wells in Susquehanna County, Pennsylvania. The Company paid an aggregate $120,000 civil penalty with respect to all the matters covered by the Consent Order, which were consolidated at the request of the PaDEP.

On April 15, 2010, the Company and PaDEP reached agreement on modifications to the Consent Order (First Modified Consent Order). In the First Modified Consent Order, PaDEP and the Company agreed that the Company will provide a permanent source of potable water to 14 households, most of which the Company has already been supplying with water. The Company agreed to plug and abandon three vertical wells in close proximity to two of the households and to bring into compliance a fourth well in the nine square mile area of concern in Susquehanna County. The Company agreed to complete these actions prior to any new well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern. The Company also agreed to postpone drilling of new wells in the area of concern until all obligations under the consent orders are fulfilled. In addition, the Company agreed to take certain other actions if requested by PaDEP, which could include the plugging and abandonment of up to 10 additional wells. In the event the PaDEP requires the Company to plug and abandon all 10 additional wells in the area of concern, the decrease in production would have a minimal impact on the Company’s overall production. Under the First Modified Consent Order, the Company paid a $240,000 civil penalty and agreed to pay an additional $30,000 per month until all obligations under the First Modified Consent Order are satisfied.

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

On July 19, 2010, the Company and the PaDEP entered a Second Modification to Consent Order (Second Modified Consent Order) under which the Company and the PaDEP agreed that the Company has satisfactorily plugged and abandoned the three vertical wells and brought the fourth well into compliance. As a result, the Company and the PaDEP agreed that the PaDEP will commence the processing and issuance of new well drilling permits outside the area of concern so long as the Company continues to provide temporary potable water and offers to provide gas/water separators to the 14 households. No penalties were assessed under the Second Modified Consent Order.

As required by the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to the 14 households. As required by the First Modified Consent Order, on August 5, 2010 the Company filed with the PaDEP its report, prepared by its experts, finding that the Company’s well drilling and development activities are not the source of methane gas reported to be in the groundwater and water wells in the area of concern.

Despite the Company’s vigorous efforts to comply with the various consent orders, in a September 14, 2010 letter to the Company, the PaDEP rejected the Company’s expert report and determined that the Company’s drilling activities continue to cause the unpermitted discharge of natural gas into the groundwater and continue to affect residential water supplies in the area of concern. The PaDEP directed the Company, in accordance with the First Modified Consent Order, to plug or take other remedial actions at the remaining 10 wells and to contact the PaDEP to discuss connecting the impacted water supplies into a community public water system to permanently eliminate the continuing adverse affect to those water supplies. If the Company were ultimately required to take these actions, the estimated cost would be less than $18.0 million.

The Company believes that it is in full compliance with the various consent orders. In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP’s rejection of the Company’s expert report, disagreed that the remaining 10 wells continue to impact groundwater and affect residential water supplies and disagreed that a community public water system is necessary or feasible. It is the Company’s position that offering installation of a whole-house water treatment system to the 14 households constitutes compliance with the Company’s obligations under these consent orders.

As of September 30, 2010, the Company has paid $510,000 and has agreed to pay an additional $30,000 per month until all obligations under the various consent orders are satisfied. The Company continues to have technical discussions with the staff of the PaDEP. There are no assurances that the PaDEP will not require additional actions.

Firm Gas Transportation Agreements

The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. These agreements provide firm transportation capacity rights on pipeline systems primarily in the North region. The remaining terms on these agreements range from less than one year to approximately 17 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability. The agreements that the Company previously had in place on pipeline systems in Canada were transferred in April 2009 to the buyer in connection with the sale of the Company’s Canadian properties (discussed in Note 2).

During the first nine months of 2010, the Company entered into new firm gas transportation arrangements with third party pipelines to transport approximately 296 Mmcf/day in the North region. One of the new agreements commenced in the second quarter of 2010 and the remaining new agreements are expected to commence in the third and fourth quarters of 2011. These new agreements have terms of five to twelve years from the respective commencement dates. As of September 30, 2010, future obligations under firm gas transportation agreements, including the new agreements, were $243.5 million. As previously disclosed in the Form 10-K, obligations under firm gas transportation agreements in effect at December 31, 2009 were $80.4 million. For further information on these future obligations, please refer to Note 7 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Drilling Rig Commitments

In the Form 10-K, the Company disclosed that it had total commitments during 2010 of $6.4 million on two drilling rigs in the South region that are under contracts with initial terms of greater than one year. One of these contracts ended in the second quarter of 2010 and the second ended in the third quarter of 2010. As of September 30, 2010, the Company does not have any outstanding drilling commitments with initial terms greater than one year.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and not subjecting the Company to material speculative risks. All of the Company’s derivatives are used for risk

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

management purposes and are not held for trading purposes. As of September 30, 2010, the Company had 23 derivative contracts open: 15 natural gas price swap arrangements, six natural gas basis swaps and two crude oil price swap arrangements. During the first nine months of 2010, the Company entered into five new derivative contracts covering anticipated crude oil production for 2010 and natural gas production for 2011.

As of September 30, 2010, the Company had the following outstanding commodity derivatives:

 

Commodity and Derivative Type

   Weighted-Average
Contract Price
     Volume     

Contract Period

Derivatives Designated as Hedging Instruments

             

Natural Gas Swaps

   $ 9.30        per Mcf         9,038         Mmcf       October -December 2010

Natural Gas Swaps

   $ 6.24        per Mcf         12,909         Mmcf       January -December 2011

Crude Oil Swaps

   $ 104.25        per Bbl         184         Mbbl       October -December 2010

Derivatives Not Designated as Hedging Instruments

             

Natural Gas Basis Swaps

   $ (0.27     per Mcf         16,123         Mmcf       January -December 2012

The change in fair value of derivatives designated as hedges that is effective is recorded to Accumulated Other Comprehensive Income in Stockholders’ Equity in the Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges, and the change in fair value of derivatives not designated as hedges, are recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue.

The following schedules reflect the fair value of derivative instruments on the Company’s condensed consolidated financial statements:

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet

 

          Fair Value Asset (Liability)  

(In thousands)

  

Balance Sheet Location

   September 30,
2010
    December 31,
2009
 

Derivatives Designated as Hedging Instruments

       

Natural Gas Commodity Contracts

   Derivative Contracts (current assets)    $ 61,052      $ 99,151   

Natural Gas Commodity Contracts

   Accrued Liabilities      0      $ (425

Natural Gas Commodity Contracts

   Derivative Contracts (long-term assets)      4,245        0   

Crude Oil Commodity Contracts

   Derivative Contracts (current assets)      4,242        15,535   
                   
      $ 69,539      $ 114,261   

Derivatives Not Designated as Hedging Instruments

       

Natural Gas Commodity Contracts

   Other Liabilities    $ (1,792   $ (1,954
                   
      $ 67,747      $ 112,307   
                   

At September 30, 2010 and December 31, 2009, unrealized gains of $69.5 million ($43.1 million, net of tax) and $114.3 million ($71.9 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income. Based upon estimates at September 30, 2010, the Company expects to reclassify $40.5 million in after-tax income associated with its commodity hedges from Accumulated Other Comprehensive Income to the Condensed Consolidated Statement of Operations over the next 12 months.

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

 

    Amount of Gain (Loss) Recognized
in OCI on Derivative (Effective Portion)
   

Location of Gain (Loss)
Reclassified from
Accumulated OCI

into Income

  Amount of Gain (Loss) Reclassified from
Accumulated OCI into

Income (Effective Portion)
 

Derivatives Designated as
Hedging Instruments

(In thousands)

  Three Months Ended
September 30,
    Nine Months Ended
September 30,
      Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
  2010     2009     2010     2009       2010     2009     2010     2009  

Natural Gas Commodity Contracts

  $ 25,364      $ 1,296      $ 76,302      $ 142,990     

Natural Gas Production Revenues

  $ 39,461      $ 102,787      $ 109,714      $ 285,453   

Crude Oil Contracts

    (606     956        3,212        (3,345  

Crude Oil and Condensate Revenues

    5,160        5,241        14,522        18,597   
                                                                 
  $ 24,758      $ 2,252      $ 79,514      $ 139,645        $ 44,621      $ 108,028      $ 124,236      $ 304,050   
                                                                 

For the three and nine months ended September 30, 2010 and 2009, respectively, there was no ineffectiveness recorded in our condensed consolidated statement of operations related to our derivative instruments.

 

Derivatives Not Designated as Hedging

Instruments

(In thousands)

  

Location of Gain (Loss)

Recognized in Income on

Derivative

   Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
      2010     2009     2010      2009  

Natural Gas Commodity Contracts

   Natural Gas Production Revenues    $ (193 )    $ (1,233   $ 162       $ (418

Additional Disclosures about Derivative Instruments and Hedging Activities

The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligation under the agreement. The Company enters into derivative contracts with multiple counterparties in order to limit its exposure to individual counterparties. The Company also has netting arrangements with all of its counterparties that allow it to offset payables against receivables from separate derivative contracts with that counterparty.

The counterparties to the Company’s derivative instruments are also lenders under its credit facility. The Company’s credit facility and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of its derivative liability in certain situations.

8. FAIR VALUE MEASUREMENTS

Effective January 1, 2009, the Company applied the authoritative guidance that applies to non-financial assets and liabilities required to be measured and recorded at fair value. The Company previously adopted the guidance as it relates to financial assets and liabilities that are measured at fair value on a recurring basis effective January 1, 2008.

This guidance established a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by generally accepted accounting principles (GAAP) to be measured at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. A formal fair value hierarchy was established based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to level 3 measurements, and accordingly, Level 1 measurements should be used whenever possible.

The Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values. For further information regarding the fair value hierarchy, refer to Note 11 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as asset retirement obligations and impairments of long-lived assets, at fair value on a nonrecurring basis. During the nine months ended September 30, 2010, the Company recorded impairment charges related to certain oil and gas properties. Refer to Note 2 for additional disclosures related to fair value associated with the impaired properties. As none of the Company’s other non-financial assets and liabilities were impaired as of September 30, 2010 and 2009 and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided.

 

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Financial Assets and Liabilities

Our financial assets and liabilities are measured at fair value on a recurring basis. The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2010:

 

(In thousands)

   Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
     Significant
Other
Observable
Inputs

(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
    Balance as of
September 30,
2010
 

Assets

          

Rabbi Trust Deferred Compensation Plan

   $ 14,250       $ 0       $ 0      $ 14,250   

Derivative Contracts

     0         0         69,539        69,539   
                                  

Total Assets

   $ 14,250       $ 0       $ 69,539      $ 83,789   
                                  

Liabilities

          

Rabbi Trust Deferred Compensation Plan

   $ 20,263       $ 0       $ 0      $ 20,263   

Derivative Contracts

     0         0         (1,792     (1,792
                                  

Total Liabilities

   $ 20,263       $ 0       $ (1,792   $ 18,471   
                                  

The Company’s investments associated with its Rabbi Trust Deferred Compensation Plan consist of mutual funds and deferred shares of the Company’s common stock that are publicly traded and for which market prices are readily available. The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The Company measured the nonperformance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions. The resulting reduction to the net receivable derivative contract position was $0.1 million. In times where the Company has net derivative contract liabilities, the nonperformance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

The following table sets forth a reconciliation of changes for the three and nine month periods ended September 30, 2010 and 2009 in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 

(In thousands)

   2010     2009     2010     2009  

Balance at beginning of period

   $ 87,803      $ 297,388      $ 112,307      $ 355,202   

Total Gains or (Losses) (Realized or Unrealized):

        

Included in Earnings (1)

     44,428        106,795        124,398        303,632   

Included in Other Comprehensive Income

     (19,863     (105,776     (44,722     (164,405

Purchases, Issuances and Settlements

     (44,621     (108,028     (124,236     (304,050

Transfers In and/or Out of Level 3

     0        0        0        0   
                                

Balance at end of period

   $ 67,747      $ 190,379      $ 67,747      $ 190,379   
                                

 

(1)

A loss of $0.2 million and a gain of $0.2 million for the three and nine months ended September 30, 2010, respectively, and a loss of $1.2 million and $0.4 million for the three and nine months ended September 30, 2009, respectively, was unrealized and included in Natural Gas Production Revenues in the Statement of Operations.

There were no transfers between Level 1 and Level 2 measurements for the three and nine months ended September 30, 2010.

Fair Value of Other Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments.

 

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The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the notes and credit facility is based on interest rates currently available to the Company.

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:

 

     September 30, 2010     December 31, 2009  

(In thousands)

   Carrying
Amount
    Estimated
Fair Value
    Carrying
Amount
     Estimated
Fair Value
 

Long-Term Debt

   $ 1,095,000      $ 1,258,007      $ 805,000       $ 863,559   

Current Maturities

     (75,000     (78,760     0         0   
                                 

Long-Term Debt, excluding Current Maturities

   $ 1,020,000      $ 1,179,247      $ 805,000       $ 863,559   
                                 

9. COMPREHENSIVE INCOME / (LOSS)

Comprehensive Income / (Loss) includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income. The following tables illustrate the calculation of Comprehensive Income for the three and nine months ended September 30, 2010 and 2009:

 

     Three Months Ended
September 30,
 

(In thousands)

   2010     2009  

Net Income

      $ 3,898         $ 38,897   

Other Comprehensive Income / (Loss), net of taxes:

          

Reclassification Adjustment for Settled Contracts, net of taxes of $17,158 and $40,185, respectively

        (27,463        (67,843

Changes in Fair Value of Hedge Positions, net of taxes of $(9,608) and $(837), respectively

        15,150           1,415   

Defined Benefit Pension and Postretirement Plans:

          

Effect of Plan Termination and Amendment, net of taxes of $(752) and $0, respectively

   $ 1,242         $ 0      

Settlement, net of taxes of $(785) and $0, respectively

     1,280           0      

Amortization of Net Obligation at Transition, net of taxes of $(60) and $(59), respectively

     98           99      

Amortization of Prior Service Cost, net of taxes of $(82) and $(66), respectively

     131           113      

Amortization of Net Loss, net of taxes of $(1,248) and $(358), respectively

     2,038         4,789        605         817   
                      

Foreign Currency Translation Adjustment, net of taxes of $6 and $43, respectively

        (42        (73
                      

Total Other Comprehensive Income / (Loss)

        (7,566        (65,684
                      

Comprehensive Income / (Loss)

      $ (3,668      $ (26,787
                      

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

     Nine Months Ended
September 30,
 

(In thousands)

   2010     2009  

Net Income

      $ 54,277         $ 111,979   

Other Comprehensive Income / (Loss), net of taxes:

          

Reclassification Adjustment for Settled Contracts, net of taxes of $46,695 and $113,598, respectively

        (77,541        (190,452

Changes in Fair Value of Hedge Positions, net of taxes of $(30,730) and $(52,441), respectively

        48,784           87,204   

Defined Benefit Pension and Postretirement Plans:

          

Effect of Plan Termination and Amendment, net of taxes of $(752) and $0, respectively

   $ 1,242         $ 0      

Settlement, net of taxes of $(785) and $0, respectively

     1,280           0      

Amortization of Net Obligation at Transition, net of taxes of $(180) and $(177), respectively

     294           297      

Amortization of Prior Service Cost, net of taxes of $(97) and $(200), respectively

     158           338      

Amortization of Net Loss, net of taxes of $(1,818) and $(1,075), respectively

     2,966         5,940        1,815         2,450   
                      

Foreign Currency Translation Adjustment, net of taxes of $(47) and $(4,124), respectively

        78           6,961   
                      

Total Other Comprehensive Income / (Loss)

        (22,739        (93,837
                      

Comprehensive Income / (Loss)

      $ 31,538         $ 18,142   
                      

Changes in the components of Accumulated Other Comprehensive Income, net of taxes, for the nine months ended September 30, 2010 were as follows:

 

Accumulated Other Comprehensive Income / (Loss), net of taxes (In thousands)

   Net Gains /
(Losses) on
Cash Flow
Hedges
    Defined Benefit
Pension and
Postretirement
Plans
    Foreign
Currency
Translation
Adjustment
    Total  

Balance at December 31, 2009

   $ 71,872      $ (29,349   $ (87   $ 42,436   

Net change in unrealized gain on cash flow hedges, net of taxes of $15,965

   $ (28,757       $ (28,757

Net change in defined benefit pension and postretirement plans, net of taxes of $(3,632)

       5,940        $ 5,940   

Change in foreign currency translation adjustment, net of taxes of $(47)

         78      $ 78   
                                

Balance at September 30, 2010

   $ 43,115      $ (23,409   $ (9   $ 19,697   
                                

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

10. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs for the three and nine months ended September 30, 2010 and 2009 were as follows:

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 

(In thousands)

   2010     2009     2010     2009  

Qualified and Non-Qualified Pension Plans

        

Current Period Service Cost

   $ 571      $ 861      $ 2,365      $ 2,583   

Interest Cost

     885        928        2,870        2,784   

Expected Return on Plan Assets

     (1,091     (671     (3,171     (2,013

Amortization of Prior Service Cost

     213        13        255        39   

Amortization of Net Loss

     3,128        794        4,310        2,382   

Curtailment Loss

     424        0        424        0   

Settlement

     2,065        0        2,065        0   
                                

Net Periodic Pension Cost

   $ 6,195      $ 1,925      $ 9,118      $ 5,775   
                                

Postretirement Benefits Other than Pension Plans

        

Current Period Service Cost

   $ 316      $ 320      $ 949      $ 960   

Interest Cost

     424        398        1,271        1,195   

Amortization of Prior Service Cost

     0        167        0        500   

Amortization of Net Loss

     158        169        474        507   

Amortization of Net Obligation at Transition

     158        158        474        474   
                                

Total Postretirement Benefit Cost

   $ 1,056      $ 1,212      $ 3,168      $ 3,636   
                                

Employer Contributions

The funding levels of the pension and postretirement plans are in compliance with standards set by applicable law or regulation. The Company does not have any required minimum funding obligations for its qualified pension plan in 2010. The Company previously disclosed in its financial statements for the year ended December 31, 2009 that it expected to contribute $0.5 million to its non-qualified pension plan and $1.0 million to the postretirement benefit plan during 2010. During the nine months ended September 30, 2010, the Company contributed $10 million to its qualified pension plan and $3.9 million to its non-qualified pension plan. Additional contributions may be made prior to December 31, 2010.

Termination and Amendment of Qualified and Non-Qualified Pension Plans

On July 28, 2010, the Company notified its employees of its plan to terminate its tax qualified defined benefit pension plan (qualified plan), with the plan and its related trust to be liquidated following appropriate filings with the Pension Benefit Guaranty Corporation and Internal Revenue Service, effective September 30, 2010. Because no further benefits will be accrued under this pension plan after September 30, 2010, the Company’s related supplemental nonqualified pension arrangements (non-qualified plan) that provide benefits by reference to the tax qualified plan will effectively be frozen and no additional benefits will be accrued under those arrangements after September 30, 2010. In conjunction with the termination of the qualified and nonqualified pension arrangements, the Company also amended the plans to allow for an age 55 early retirement enhancement to be available to all active participants as of September 30, 2010 regardless of their age and service as of that date.

Freezing the above plans resulted in a remeasurement of the pension obligations and plan assets as of July 28, 2010. The remeasurement, termination, and amendment of the plans resulted in a decrease in plan obligations of approximately $1.8 million, a decrease in plan assets of approximately $1.1 million and a decrease in Accumulated Other Comprehensive Income of approximately $1.2 million. In calculating the remeasurement, management used a discount rate of 5.25% for the qualified plan and 4.5% for the non-qualified plan, which was consistent with the Company’s methodology of determining the discount rate for these plans. The discount rate was based on a yield curve based on high-quality corporate bonds that could be purchased to settle the pension obligation. Management determined the discount rate by matching this yield curve with the timing and amounts of the expected benefit payments for the Company’s plans.

As a result of the freezing and termination of the Company’s qualified and non-qualified pension plans, the Company revised its amortization period for prior service costs and actuarial losses, which are now amortized over 17 months to reflect the expected amortization period until final distribution of assets from each plan. Prior service costs established in each plan prior to freeze were fully recognized in the third quarter of 2010 as a result of the plan freeze. Actuarial losses in the qualified pension plan were previously amortized over 10.6 years and actuarial losses in the non-qualified pension plan were previously amortized over 6 years.

 

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

 

For the third quarter 2010, these actions increased pension cost by approximately $5.2 million, which included $0.4 million of one-time pension curtailment losses.

Amendment of Savings Investment Plan and Deferred Compensation Plan

In July 2010, the Company amended the Savings Investment Plan to provide for discretionary profit sharing contributions. The Company is presently contributing to this plan an amount equal to 9% of an eligible plan participant’s salary and bonus. The Company also amended the Deferred Compensation Plan to broaden the group of eligible employees that participate in the plan.

11. STOCK-BASED COMPENSATION

Stock-based compensation expense (including the supplemental employee incentive plan) during the first nine months of 2010 and 2009 was $9.4 million and $16.6 million, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations. Stock-based compensation expense in the third quarter of 2010 and 2009 was $3.8 million and $5.3 million, respectively.

Due to the Company’s net operating loss carryforward position, no income tax benefit related to stock-based compensation has been recognized for 2010. During the third quarter of 2009, the Company realized a $13.1 million tax benefit related primarily to the federal tax deduction in excess of book compensation cost for employee stock-based compensation for 2008 and, to a lesser extent, book compensation cost exceeding federal tax deduction for 2009 and state tax deductions for 2007. For regular federal income tax purposes, the Company was in a net operating loss position in 2008. In accordance with ASC 718, the Company is able to recognize this tax benefit only to the extent it reduces the Company’s income taxes payable. As the Company carried back net operating losses concurrent with its 2008 tax return filing, the income tax benefit related to stock-based compensation was recorded in 2009. For further information regarding Stock-Based Compensation or the Company’s Incentive Plans, please refer to Note 10 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Restricted Stock Awards

During the first nine months of 2010, 23,800 restricted stock awards were granted with a weighted-average grant date per share value of $34.87. The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The Company used an annual forfeiture rate ranging from 0% to 7.0%.

Restricted Stock Units

During the first nine months of 2010, 26,961 restricted stock units were granted to non-employee directors of the Company with a grant date per share value of $40.07. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and will be issued when the director ceases to be a director of the Company.

Stock Appreciation Rights

During the first nine months of 2010, 79,550 stock appreciation rights (SARs) were granted to employees. These awards allow the employee to receive common stock of the Company equal to the intrinsic value over the $40.53 strike price during the contractual term of seven years. The Company calculates the fair value using a Black-Scholes model. The assumptions used in the Black-Scholes fair value calculation on the date of grant for SARs are as follows:

 

Value per Share

   $ 18.96   

Assumptions

  

Stock Price Volatility

     52.9

Risk Free Rate of Return

     2.4

Expected Dividend Yield

     0.3

Expected Term (in years)

     5.0   

Performance Share Awards

During the first nine months of 2010, three types of performance share awards were granted to employees for a total of 347,170 performance shares, which included 84,470 market-based performance share awards and 262,700 performance-based awards based on internal performance metrics. Of the 262,700 performance-based awards, 82,520 of the shares have a three-year graded performance period. For these shares, one-third of the shares are issued on each anniversary date following the date of grant, provided that the Company has $100 million or more of operating cash flow for the year preceding the performance period. If the Company does not meet this metric for the applicable period, then the portion of the performance shares that would have been issued on that date will be forfeited. For the remaining 180,180 performance-based awards, the actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three performance criteria set by the Company’s Compensation Committee. Refer to Note 10 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of performance share awards.

 

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

 

 

The performance period for the two awards based on internal performance metrics commenced on January 1, 2010 and ends on December 31, 2012 and the grant date per share value for these awards was $40.53, which is based on the average of the high and low stock price on the grant date. The actual number of shares issued on each anniversary date following the grant date or at the end of the performance period, as applicable, will be determined based on the Company’s performance against the performance criteria set by the Company’s Compensation Committee. Based on the Company’s probability assessment at September 30, 2010, it is considered probable that the criteria for the performance-based awards will be met. The Company used an annual forfeiture rate ranging from 0% to 7% for all performance share awards.

The following assumptions were used for the market-based performance shares using a Monte Carlo model to value the liability and equity components of the awards. The equity portion of the 2010 awards was valued on the grant date and was not marked to market. The liability portion of the awards was valued as of September 30, 2010 on a mark to market basis.

 

      Grant Date     September 30, 2010  

Value per Share

   $  13.00        $1.83 - $4.83   

Assumptions

    

Stock Price Volatility

     61.8     41.08% - 64.05%   

Risk Free Rate of Return

     1.4     0.16% - 0.48%   

Expected Dividend Yield

     0.3     0.4%   

12. ASSET RETIREMENT OBLIGATION

The following table provides a rollforward of the asset retirement obligation. Liabilities settled include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Liabilities incurred include additions to obligations as well as obligations that were assumed by the Company related to acquired properties. Activity related to the Company’s asset retirement obligation during the nine months ended September 30, 2010 is as follows:

 

(In thousands)

      

Carrying amount of asset retirement obligations at December 31, 2009

   $ 29,676   

Liabilities added during the current period

     399   

Liabilities settled and divested during the current period

     (300

Current period accretion expense

     1,022   
        

Carrying amount of asset retirement obligations at September 30, 2010

   $ 30,797   
        

 

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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, 2010, and the related condensed consolidated statements of operations for the three-month and nine-month periods ended September 30, 2010 and 2009 and the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2010 and 2009. 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 (United States), 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, 2009, and the related consolidated statements of operations, of cash flows, of stockholders’ equity and of comprehensive income for the year then ended (not presented herein), and in our report dated February 26, 2010, which included an explanatory paragraph related to changes in the manner of accounting for fair value measurements, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet information as of December 31, 2009, 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 29, 2010

 

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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, 2010 and 2009 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 Corporation Annual Report on Form 10-K for the year ended December 31, 2009 (Form 10-K).

In 2009, we reorganized our operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with its Texas and Louisiana areas to form the South region. Certain prior year amounts have been reclassified to reflect this reorganization. Additionally, we exited Canada through the sale of our properties. Prior to the third quarter of 2009, we presented the geographic areas as East, Gulf Coast, West and Canada.

Overview

On an equivalent basis, our production for the nine months ended September 30, 2010 increased by 21% compared to the nine months ended September 30, 2009. For the nine months ended September 30, 2010, we produced 93.2 Bcfe compared to production of 76.7 Bcfe for the nine months ended September 30, 2009. Natural gas production was 89.2 Bcf and oil production was 620 Mbbls for the first nine months of 2010. Natural gas production increased by 22% when compared to the first nine months of 2009, which had production of 73.0 Bcf. This increase was primarily a result of increased production in the North region associated with the drilling program and the start up of our Lathrop compressor station at the end of the second quarter of 2010 in Susquehanna County, Pennsylvania. Partially offsetting the production increase in the North region were decreases in production in Canada due to the sale of our Canadian properties in April 2009, as well as lower production in the South region due to normal production declines, delays in completion, and a shift from gas to oil projects. Oil production increased by 2%, to 620 Mbbls, when compared to the first nine months of 2009, which had production of 607 Mbbls. This increase was primarily the result of increased production in the South region, offset by decreased production in the North.

Our average realized natural gas price for the first nine months of 2010 was $5.75 per Mcf, 22% lower than the $7.39 per Mcf price realized in the first nine months of 2009. Our average realized crude oil price for the first nine months of 2010 was $97.43 per Bbl, 18% higher than the $82.48 per Bbl price realized in the first nine months of 2009. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to “Results of Operations” below. Commodity prices are determined by many 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 supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our future revenues, capital program or production volumes.

Operating revenues for the nine months ended September 30, 2010 decreased slightly by $18.6 million, or 3%, from the nine months ended September 30, 2009 as the lower realized natural gas prices noted above more than offset the higher equivalent production. Natural gas production revenues decreased by $25.6 million, or 5%, for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009 due to the decrease in realized natural gas prices, partially offset by the increase in natural gas production. Crude oil and condensate revenues increased by $10.4 million, or 21%, for the first nine months of 2010 as compared to the first nine months of 2009, due to increases in realized crude oil prices and crude oil production. Brokered natural gas revenues decreased by $4.2 million, or 8%, due to a decreased sales price, partially offset by increased brokered volumes.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. For 2010, we expect to spend approximately $790.0 million in capital and exploration expenditures. We believe our cash on hand, operating cash flow in 2010 and borrowings from our credit facility will be sufficient to fund our remaining budgeted capital and exploration spending in 2010. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease our capital and exploration expenditures accordingly. For the nine months ended September 30, 2010, we invested approximately $621 million in our exploration and development efforts.

During the first nine months of 2010, we drilled 83 gross wells (69 development, four exploratory and 10 extension wells) with a success rate of 98% compared to 119 gross wells (107 development, six exploratory and six extension wells) with a success rate of 98% for the comparable period of the prior year. For the full year of 2010, we plan to drill approximately 117 gross (94.6 net) wells.

We continue to remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. We believe these strategies are appropriate for our portfolio of projects and the current industry environment and will continue to add shareholder value over the long-term.

 

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In June 2010, we sold our Woodford shale prospect located in Oklahoma to Continental Resources, Inc. We received approximately $15.9 million in cash proceeds and recognized a $10.3 million gain on sale of assets. In July 2010, we sold certain oil and gas properties located in Colorado to Patera Oil & Gas LLC for approximately $3.0 million. During the second quarter of 2010, we recognized an impairment loss of approximately $5.8 million associated with the proposed sale of these properties. In April 2009, we sold our Canadian properties to a privately held Canadian company for a $16.0 million loss. In the first quarter of 2009, we received approximately $11.4 million in cash proceeds and recognized a $12.7 million gain on sale of assets primarily related to the sale of the Thornwood properties in the North region. Refer to Note 2 of the Notes to the Condensed Consolidated Financial Statements for further details.

In September 2010, the Company signed a purchase and sale agreement with a private company to sell certain oil and gas properties in the Texas panhandle for $11.5 million. The transaction is expected to close in the fourth quarter of 2010. The net book value of these properties as of September 30, 2010 was $0.1 million.

In September 2010, we amended and restated our revolving credit facility to increase the available credit line to $900 million and with an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount, and to extend the term to September 2015. In June 2010, we amended the agreements governing our senior notes and credit facility to amend the required asset coverage ratio (the present value of our proved reserves plus working capital to debt) contained in the agreements. The amendment also impacted the ratio for maximum calculated indebtedness to borrowing base (as defined in the credit facility agreement). Refer to Note 4 of the Notes to the Condensed Consolidated Financial Statements for further details.

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

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the nine months ended September 30, 2010 were funds generated from the sale of natural gas and crude oil production, realized derivative contracts, borrowings under our credit facility and asset dispositions. These cash flows were primarily used to fund our development and exploration expenditures, in addition to payment of dividends. See below for additional discussion and analysis of cash flow.

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 volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, as described in our Form 10-K and other filings with the Securities and Exchange Commission, have also influenced prices throughout the recent years. Commodity prices continue to experience increased volatility due to adverse market conditions in the economy. In addition, fluctuations 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.

Our working capital is also substantially influenced by variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. We believe we have adequate credit availability and liquidity to meet our working capital requirements.

 

     Nine Months Ended
September 30,
 

(In thousands)

   2010     2009  

Cash Flows Provided by Operating Activities

   $ 367,492      $ 417,130   

Cash Flows Used in Investing Activities

     (637,090     (345,997

Cash Flows (Used in) / Provided by Financing Activities

     267,028        (63,564
                

Net (Decrease) / Increase in Cash and Cash Equivalents

   $ (2,570   $ 7,569   
                

Operating Activities. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities in the first nine months of 2010 decreased by $49.6 million over the first nine months of 2009. This decrease was mainly due to lower natural gas prices offset by higher crude oil prices and equivalent production. Average realized natural gas prices decreased by 22% for the first nine months of 2010 compared to the first nine months of 2009, while average realized crude oil prices increased by 18% compared to the same period. Equivalent production volumes increased by 21% for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 as a result of higher natural gas and crude oil production. See “Results of Operations” for additional information relative to commodity price and production movements. 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. Realized prices may decline in future periods.

As of September 30, 2010, we have natural gas price swaps covering 9.0 Bcf of our 2010 natural gas production at an average price of $9.30 per Mcf and natural gas price swaps covering 12.9 Bcf of our 2011 natural gas production at an average price of $6.24 per Mcf.

 

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Investing Activities. The primary use of cash in investing activities was capital spending. We established our capital budget based on our current estimate of future commodity prices and cash flows. Due to the volatility of commodity prices and new opportunities which may arise, our capital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased by $291.1 million from the first nine months of 2010 compared to the first nine months of 2009. The increase was primarily due to an increase of $231.9 million in capital expenditures offset by lower proceeds from sale of assets of $59.2 million.

Financing Activities. Cash flows provided by financing activities increased by $330.6 million from the first nine months of 2009 to the first nine months of 2010. This was primarily due to an increase in borrowings under our credit facility in the first nine months of 2010 and debt repayments in the first nine months of 2009.

At September 30, 2010, we had $433.0 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of 3.78%. The credit facility provides for an available credit line of $900 million and contains an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks based on our reserve reports and engineering reports) and certain other assets and the outstanding principal balance of our senior notes. The credit facility also provides for the issuance of letters of credit, which would reduce the Company’s borrowing capacity. The amended facility provides for a $1.5 billion borrowing base and matures in September 2015. As of September 30, 2010, our available credit under our credit facility is $466.7 million.

We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. Management believes that, with internally generated cash, existing cash and availability under our revolving credit facility, we have the capacity to finance our spending plans, service our debt obligations as they become due and maintain our strong financial position. At the same time, we continue to closely monitor the capital markets.

Capitalization

Information about our capitalization is as follows:

 

(Dollars in millions)

   September 30,
2010
    December 31,
2009
 

Debt (1)

   $ 1,095.0      $ 805.0   

Stockholders’ Equity

     1,843.3        1,812.5   
                

Total Capitalization

   $ 2,938.3      $ 2,617.5   
                

Debt to Capitalization

     37.3     30.8

Cash and Cash Equivalents

   $ 37.6      $ 40.2   

 

(1)

Includes $75.0 million of current portion of Long-term Debt at September 30, 2010. Includes $433.0 million and $143.0 million of borrowings outstanding under our revolving credit facility at September 30, 2010 and December 31, 2009, respectively.

During the nine months ended September 30, 2010, we paid dividends of $9.3 million ($0.09 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

Capital and Exploration Expenditures

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

 

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The following table presents major components of capital and exploration expenditures for the nine-month period ended September 30, 2010 and 2009:

 

     Nine Months Ended
September 30,
 

(In millions)

   2010      2009  

Capital Expenditures

     

Drilling and Facilities (1)

   $ 445.8       $ 294.7   

Leasehold Acquisitions

     109.9         20.8   

Acquisitions

     0.8         0.4   

Pipeline and Gathering

     29.4         15.3   

Other

     6.6         4.6   
                 
     592.5         335.8   

Exploration Expense

     28.3         31.3   
                 

Total

   $ 620.8       $ 367.1   
                 

 

(1)

Includes Canadian currency translation effects of $4.6 million in 2009. There was no impact from Canadian currency translation in 2010.

For the full year of 2010, we plan to drill approximately 117 gross (94.6 net) wells. This 2010 drilling program includes approximately $790.0 million in total capital and exploration expenditures. See the “Overview” discussion for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease the capital and exploration expenditures accordingly.

Contractual Obligations

At September 30, 2010, we were obligated to make future payments under gas transportation agreements. For further information, please refer to “Firm Gas Transportation Agreements” under Note 6 in the Notes to the Condensed Consolidated Financial Statements and Note 7 in the Notes to Consolidated Financial Statements included in our Form 10-K.

Critical Accounting Policies and Estimates

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

Recently Adopted Accounting Standards

In February 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-09, “Subsequent Events,” which amends Accounting Standards Codification (ASC) 855 to eliminate the requirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and its adoption had no impact on our financial position, results of operations or cash flows.

Effective January 1, 2010, we partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). The principal impact was to require the expansion of our disclosure regarding our derivative instruments. Accordingly, we will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on our financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please refer to Note 8 in the Notes to the Condensed Consolidated Financial Statements.

 

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Results of Operations

Third Quarters of 2010 and 2009 Compared

We reported net income in the third quarter of 2010 of $3.9 million, or $0.04 per share, compared to net income in the third quarter of 2009 of $38.9 million, or $0.38 per share. Net income decreased in the third quarter of 2010 by $35.0 million, primarily due to an increase in operating expenses partially offset by an increase in operating revenues.

Operating revenues increased by $12.1 million, largely due to increases in natural gas production revenues and brokered natural gas revenues, partially offset by a decrease in crude oil and condensate revenues. Operating expenses increased by $64.3 million between periods primarily due to increases in impairment of oil and gas properties, depreciation, depletion and amortization, general and administrative expenses, direct operations and brokered natural gas costs partially offset by lower exploration expense and taxes other than income. In addition, net income was impacted in during the third quarter by slightly higher interest expense and lower income tax expense. Income tax expense was lower during the third quarter of 2010 due to lower pretax income and a lower effective tax rate.

Revenue, Price and Volume Variances

Below is a discussion of revenue, price and volume variances.

 

     Three Months Ended
September 30
     Variance  
     2010      2009      Amount     Percent  

Revenue Variances (In thousands)

                          

Natural Gas Production (1)

   $ 187,287       $ 179,040       $ 8,247        5

Brokered Natural Gas

     11,675         9,032         2,643        29

Crude Oil and Condensate

     19,234         19,574         (340     (2 %) 

Other

     1,127         608         519        85

 

(1)

Natural Gas Production Revenues excludes the unrealized loss from the change in fair value of our basis swaps of $0.2 million and $1.2 million for the quarter ended September 30, 2010 and September 30, 2009, respectively.

 

     Three Months Ended
September 30,
     Variance     Increase
(Decrease)
 
     2010      2009      Amount     Percent     (In thousands)  

Price Variances

            

Natural Gas Production (1)

   $ 5.37       $ 7.40       $ (2.03     (27 %)    $ (70,678

Crude Oil and Condensate (2)

   $ 98.26       $ 87.49       $ 10.77        12     2,111   
                  

Total

             $ (68,567
                  

Volume Variances

            

Natural Gas Production (Mmcf)

     34,850         24,194         10,656        44   $ 78,925   

Crude Oil and Condensate (Mbbl)

     196         224         (28     (13 %)      (2,451
                  

Total

             $ 76,474   
                  

 

(1)

These prices include the realized impact of derivative instrument settlements, which increased the price by $1.13 per Mcf in 2010 and by $4.25 per Mcf in 2009.

(2)

These prices include the realized impact of derivative instrument settlements, which increased the price by $26.33 per Bbl in 2010 and by $23.40 per Bbl in 2009.

Natural Gas Production Revenues

The increase in Natural Gas Production Revenue of $8.2 million is primarily due to an increase in natural gas production in the North region associated with increased drilling and the start up of the Lathrop compressor station in the Marcellus shale at the end of the second quarter of 2010. Partially offsetting this increase was the decrease in realized natural gas prices, decreased production in the South region associated with normal production declines, delays in completions and a shift from gas to oil projects, as well as the sale of our Canadian properties in April 2009.

Crude Oil and Condensate Revenues

The $0.3 million decrease in crude oil and condensate revenues is primarily due to decreased production in the North and South regions partially offset by an increase in realized crude oil prices.

 

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Table of Contents

 

Brokered Natural Gas Revenue and Cost

 

      Three Months  Ended
September 30,
                  Price and
Volume

Variances
(In thousands)
 
      Variance    
   2010      2009      Amount      Percent    

Brokered Natural Gas Sales

             

Sales Price ($/Mcf)

   $ 5.14       $ 4.04       $ 1.10         27   $ 2,469   

Volume Brokered (Mmcf)

   x 2,272       x  2,238         34         2     174   
                               

Brokered Natural Gas Revenues (In thousands)

   $ 11,675       $ 9,032            $ 2,643   
                               

Brokered Natural Gas Purchases

             

Purchase Price ($/Mcf)

   $ 4.53       $ 3.48       $ 1.05         30   $ (2,377

Volume Brokered (Mmcf)

   x 2,272       x 2,238         34         2     (118
                               

Brokered Natural Gas Cost (In thousands)

   $ 10,281       $ 7,786            $ (2,495
                               

Brokered Natural Gas Margin (In thousands)

   $ 1,394       $ 1,246            $ 148   
                               

The increased brokered natural gas margin of $0.1 million is a result of an increase in brokered volumes coupled with an increase in sales price that outpaced the increase in purchase price.

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,
 
     2010     2009  

(In thousands)

   Realized      Unrealized     Realized      Unrealized  

Operating Revenues—Increase / (Decrease) to Revenue

          

Cash Flow Hedges

          

Natural Gas Production

   $ 39,461       $ 0      $ 102,787       $ 0   

Crude Oil

     5,160         0        5,241         0   
                                  

Total Cash Flow Hedges

     44,621         0        108,028         0   
                                  

Other Derivative Financial Instruments

          

Natural Gas Basis Swaps

     0         (193     0         (1,233
                                  

Total Other Derivative Financial Instruments

     0         (193     0         (1,233
                                  

Total Cash Flow Hedges and Other Derivative Financial Instruments

   $ 44,621       $ (193   $ 108,028       $ (1,233
                                  

We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties. Our primary derivative contract counterparties are Bank of Montreal, BNP Paribas, JPMorgan Chase, Key Bank, Bank of America and Morgan Stanley.

 

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Operating and Other Expenses

 

     Three Months Ended
September 30,
     Variance  

(In thousands)

   2010     2009      Amount     Percent  

Operating and Other Expenses

         

Brokered Natural Gas Cost

   $ 10,281      $ 7,786       $ 2,495        32

Direct Operations - Field and Pipeline

     26,466        23,012         3,454        15

Taxes Other Than Income

     8,489        10,719         (2,230     (21 %) 

Exploration

     9,665        14,395         (4,730     (33 %) 

Impairment of Oil and Gas Properties

     35,789        0         35,789        100

Depreciation, Depletion and Amortization

     85,355        62,037         23,318        38

General and Administrative

     21,077        14,921         6,156        41
                                 

Total Operating Expense

   $ 197,122      $ 132,870       $ 64,252        48

(Gain) / Loss on Sale of Assets

   $ (265   $ 572       $ (837     (146 %) 

Interest Expense and Other

     16,758        14,857         1,901        13

Income Tax Expense

     1,617        20,969         (19,352     (92 %) 

Total costs and expenses from operations increased by $64.3 million, or 48%, in the third quarter of 2010 compared to the same period of 2009. The primary reasons for this fluctuation are as follows:

 

   

Impairment of Oil and Gas Properties increased by $35.8 million from the third quarter of 2009 compared to the third quarter due to the impairment of two south Texas fields because of continued price declines and normal production declines.

 

   

Depreciation, Depletion and Amortization increased by $23.3 million from the third quarter of 2009 compared to the third quarter of 2010, of which $19.8 million is due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes offset slightly by a lower DD&A rate. Amortization of unproved properties increased $3.5 million primarily due to increased unproved leasehold costs in Susquehanna County and South Texas in late 2009 and early 2010.

 

   

General and Administrative expenses increased by $6.2 million from the third quarter of 2009 compared to the third quarter of 2010. This increase is primarily due to higher pension expense as a result of the termination of our qualified and non-qualified pension plans, and higher incentive compensation and professional service costs, partially offset by decreased stock-based compensation expense.

 

   

Direct Operations increased $3.5 million largely due to increased plug and abandonment costs, accrued lease operating expenses, lease maintenance costs, outside operated properties and workover costs partially offset by decreased compressor costs and contract labor.

 

   

Brokered Natural Gas Costs increased $2.5 million from the third quarter of 2010 compared to third quarter of 2009. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

   

Exploration Expense decreased $4.7 million primarily due to lower idle rig expense and dry hole costs partially offset by increased geophysical and geological costs.

 

   

Taxes Other Than Income decreased $2.2 million primarily due to decreased production and ad valorem taxes partially offset by increased business and occupational taxes and franchise taxes.

Income Tax Expense

Income tax expense decreased by $19.4 million in the third quarter of 2010 primarily due to decreased pretax income and a lower effective tax rate. The effective tax rate for the third quarter of 2010 and 2009 was 29.3% and 35.0%, respectively. The effective tax rate was lower as a result of return to provision adjustments recorded in the quarter which had a greater impact due to significantly lower quarterly pretax income.

Interest Expense, Net

Interest expense, net increased by $1.9 million in the third quarter of 2010 compared to the third quarter of 2009 primarily due to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately $392.7 million during the third quarter of 2010 compared to approximately $145.3 million during the third quarter of 2009. The weighted-average effective interest rate on the credit facility increased to approximately 3.8% during the third quarter of 2010 compared to approximately 3.6% during the third quarter of 2009.

 

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Nine Months of 2010 and 2009 Compared

We reported net income for the first nine months of 2010 of $54.3 million, or $0.52 per share, compared to the first nine months of 2009 of $112.0 million, or $1.08 per share. Net income decreased for the first nine months of 2010 by $57.7 million, primarily due to a decrease in operating revenues and an increase in operating expenses.

Operating revenues decreased by $18.6 million, largely due to decreases in natural gas production revenues and brokered natural gas revenues partially offset by increases in crude oil and condensate revenues. Operating expenses increased by $74.0 million between periods due primarily to increases in impairment of oil and gas properties, depreciation, depletion and amortization and direct operations. These increases were partially offset by lower brokered natural gas costs, taxes other than income and exploration expense. In addition, net income was impacted in the first nine months of 2010 by higher interest expense and decreased income tax expense. Income tax expense was lower for the first nine months of 2010 due to lower pretax income partially offset by a higher effective tax rate.

Revenue, Price and Volume Variances

Below is a discussion of revenue, price and volume variances.

 

     Nine Months Ended
September 30,
     Variance  

Revenue Variances (In thousands)

   2010      2009      Amount     Percent  

Natural Gas Production (1)

   $ 512,774       $ 538,960       $ (26,186     (5 %) 

Brokered Natural Gas

     49,896         54,117         (4,221     (8 %) 

Crude Oil and Condensate

     60,427         50,026         10,401        21

Other

     3,901         3,099         802        26

 

(1)

Natural Gas Production Revenues excludes the unrealized gain from the change in fair value of our basis swaps of $0.2 million for the nine months ended September 30, 2010 and the unrealized loss from the change in fair value of our basis swaps of $0.4 million for the nine months ended September 30, 2009.

 

     Nine Months Ended
September 30,
                 Increase
(Decrease)
(In thousands)
 
      Variance    
     2010      2009      Amount     Percent    
Price Variances             

Natural Gas Production (1)

   $ 5.75       $ 7.39       $ (1.64     (22 %)    $ (146,181

Crude Oil and Condensate (2)

   $ 97.43       $ 82.48       $ 14.95        18     9,329   
                  

Total

             $ (136,852
                  

Volume Variances

            

Natural Gas Production (Mmcf)

     89,203         72,979         16,224        22   $ 119,995   

Crude Oil and Condensate (Mbbl)

     620         607         13        2     1,072   
                  

Total

             $ 121,067   
                  

 

(1)

These prices include the realized impact of derivative instrument settlements, which increased the price by $1.23 per Mcf in 2010 and by $3.91 per Mcf in 2009.

(2)

These prices include the realized impact of derivative instrument settlements, which increased the price by $23.42 per Bbl in 2010 and by $30.64 per Bbl in 2009.

Natural Gas Production Revenues

The decrease in Natural Gas Production Revenue of $26.2 million is due primarily to the decrease in realized natural gas prices, decreased production in the South region associated with normal production declines, delays in completions and a shift from gas to oil projects, as well as the sale of our Canadian properties in April 2009. Partially offsetting these decreases was an increase in natural gas production in the North region associated with increased drilling and the start up of the Lathrop compressor station in the Marcellus shale at the end of the second quarter of 2010.

Crude Oil and Condensate Revenues

The $10.4 million increase in crude oil and condensate revenues is primarily due to an increase in realized crude oil prices and an increase in crude oil production in the South region. These increases are partially offset by lower production in the North region and Canada.

 

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Brokered Natural Gas Revenue and Cost

 

     Nine Months Ended
September 30,
     Variance    

Price and

Volume

Variances

 
     2010      2009      Amount     Percent     (In thousands)  

Brokered Natural Gas Sales

            

Sales Price ($/Mcf)

   $ 5.60       $ 6.49       $ (0.89     (14 %)    $ (7,973

Volume Brokered (Mmcf)

   x 8,915       x 8,337         578        7     3,752   
                              

Brokered Natural Gas Revenues (In thousands)

   $ 49,896       $ 54,117           $ (4,221
                              

Brokered Natural Gas Purchases

            

Purchase Price ($/Mcf)

   $ 4.86       $ 5.78       $ (0.92     (16 %)    $ 8,218   

Volume Brokered (Mmcf)

   x 8,915       x 8,337         578        7     (3,341
                              

Brokered Natural Gas Cost (In thousands)

   $ 43,342       $ 48,219           $ 4,877   
                              

Brokered Natural Gas Margin (In thousands)

   $ 6,554       $ 5,898           $ 656   
                              

The increased brokered natural gas margin of $0.7 million is a result of an increase in volumes brokered that outpaced the decreases in sales and purchase price.

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,
 
     2010      2009  

(In thousands)

   Realized      Unrealized      Realized      Unrealized  

Operating Revenues—Increase / (Decrease) to Revenue

           

Cash Flow Hedges

           

Natural Gas Production

   $ 109,714       $ 0       $ 285,453       $ 0   

Crude Oil

     14,522         0         18,597         0   
                                   

Total Cash Flow Hedges

     124,236         0         304,050         0   
                                   

Other Derivative Financial Instruments

           

Natural Gas Basis Swaps

     0         162         0         (418
                                   

Total Other Derivative Financial Instruments

     0         162         0         (418
                                   

Total Cash Flow Hedges and Other Derivative Financial Instruments

   $ 124,236       $ 162       $ 304,050       $ (418
                                   

Operating and Other Expenses

 

     Nine Months Ended
September 30,
     Variance  

(In thousands)

   2010     2009      Amount     Percent  

Operating and Other Expenses

         

Brokered Natural Gas Cost

   $ 43,342      $ 48,219       $ (4,877     (10 %) 

Direct Operations—Field and Pipeline

     73,796        71,564         2,232        3

Taxes Other Than Income

     31,135        34,531         (3,396     (10 %) 

Exploration

     28,324        31,258         (2,934     (9 %) 

Impairment of Oil and Gas Properties

     35,789        0         35,789        100

Depreciation, Depletion and Amortization

     235,579        188,967         46,612        25

General and Administrative

     49,675        49,103         572        1
                                 

Total Operating Expense

   $ 497,640      $ 423,642       $ 73,998        17

(Gain) / Loss on Sale of Assets

   $ (5,411   $ 3,283       $ (8,694     (265 %) 

Interest Expense and Other

     47,439        44,129         3,310        8

Income Tax Expense

     33,215        62,751         (29,536     (47 %) 

 

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Total operating expenses increased by $74.0 million in the first nine months of 2010 compared to the same period of 2009. The primary reasons for this fluctuation are as follows:

 

   

Depreciation, Depletion and Amortization increased by $46.6 million for the first nine months of 2010 compared to the first nine months of 2009, of which $34.8 million is associated with increased depreciation and depletion primarily due to a higher DD&A rate as a result of higher capital costs and increased equivalent production volumes. Amortization of unproved properties increased $11.8 million primarily due to increased unproved leasehold costs in Susquehanna County and South Texas in late 2009 and 2010.

 

   

Impairment of Oil and Gas Properties increased by $35.8 million for the first nine months of 2010 compared to the first nine months of 2009 due to the impairment of two south Texas fields because of continued price declines and normal production declines.

 

   

Brokered Natural Gas Cost decreased by $4.9 million for the first nine months of 2010 compared to the first nine months of 2009. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

   

Taxes Other Than Income decreased $3.4 million primarily due to decreased production and ad valorem taxes partially offset by increased business and occupational taxes and franchise taxes.

 

   

Exploration Expense decreased $2.9 million primarily due to lower idle rig expense and dry hole costs partially offset by increased geophysical and geological costs.

Gain on Sale of Assets

An aggregate gain of $5.4 million was recognized in the first nine months of 2010. During the first nine months of 2010, a gain of $10.3 million was recognized on the sale of the Woodford shale prospect, offset by an impairment charge of $5.8 million on assets held for sale in the second quarter of 2010. In the first nine months of 2009, a $3.3 million aggregate loss on sale of assets was recognized. During 2009, we recorded a $16.0 million loss on sale of assets, primarily due to the sale of the Canadian properties. In addition, we recognized a $12.7 million gain on sale of assets during the first nine months of 2009 primarily related to the first quarter 2009 sale of Thornwood properties in the North.

Income Tax Expense

Income tax expense decreased by $29.5 million in the first nine months of 2010 due to decreased pretax income partially offset by a higher effective tax rate. The effective tax rate for the first nine months of 2010 and 2009 was 38.0% and 35.9%, respectively. The effective tax rate was higher as a result of a shift in earnings being generated from states with lower tax rates to states with higher tax rates.

Interest Expense, Net

Interest expense, net increased by $3.3 million in the first nine months of 2010 compared to the first nine months of 2009 primarily due to increased interest expense related to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately $304.1 million during the first nine months of 2010 compared to approximately $162.7 million during the first nine months of 2009. The weighted-average effective interest rate on the credit facility decreased to approximately 3.8% during the first nine months of 2010 compared to approximately 4.1% during the first nine months of 2009.

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 crude 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

Market Risk

Our primary market risk is exposure to crude oil and natural gas prices. Realized prices are mainly driven by worldwide prices for crude oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The debt and equity markets continue to experience unfavorable conditions, which may affect our ability to access those markets. As a result of the volatility and continued uncertainty in the capital markets and our increased level of borrowings, we may experience increased costs associated with future borrowings and debt issuances. We will continue to monitor events and circumstances surrounding each of our lenders in our revolving credit facility.

 

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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 in periods of increasing 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 as well as Note 7 of the Notes to the Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

As of September 30, 2010, we had 23 derivative contracts open: 15 natural gas price swap arrangements, six natural gas basis swaps and two crude oil price swap arrangements. During the first nine months of 2010, the Company entered into five new derivative contracts covering anticipated crude oil production for 2010 and natural gas production for 2011.

As of September 30, 2010, we had the following outstanding commodity derivatives:

 

Commodity and Derivative Type

   Weighted-Average
Contract Price
     Volume     

Contract Period

   Net Unrealized Gain /
(Loss)

(In thousands)
 

Derivatives Designated as
Hedging Instruments

           

Natural Gas Swaps

   $ 9.30    per Mcf         9,038    Mmcf       October - December 2010    $ 61,052   

Natural Gas Swaps

   $ 6.24    per Mcf         12,909    Mmcf       January - December 2011      4,245   

Crude Oil Swaps

   $ 104.25    per Bbl         184     Mbbl       October - December 2010      4,242   
                 
            $ 69,539   

Derivatives Not Designated as Hedging Instruments

           

Natural Gas Basis Swaps

   $ (0.27)    per Mcf         16,123    Mmcf       January - December 2012      (1,792
                 
            $ 67,747   
                 

The amounts set forth under the net unrealized gain column in the table above represent our total unrealized gain position at September 30, 2010 and include the impact of nonperformance risk. Nonperformance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions.

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 cash flow hedges are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

During the first nine months of 2010, natural gas price swaps covered 26.8 Bcf, or 30%, of our first nine months of 2010 gas production at an average price of $9.30 per Mcf.

We had two crude oil price swaps covering 546 Mbbl, or 88%, of our first nine months of 2010 oil production at an average price of $104.25 per Bbl.

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

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

Fair Market Value of Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value.

 

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The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and credit facility to new issues (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and credit facility is based on interest rates currently available to us.

We use available marketing data and valuation methodologies to estimate the fair value of debt.

 

     September 30, 2010     December 31, 2009  

(In thousands)

   Carrying
Amount
    Estimated
Fair Value
    Carrying
Amount
     Estimated
Fair Value
 

Long-Term Debt

   $ 1,095,000      $ 1,258,007      $ 805,000       $ 863,559   

Current Maturities

     (75,000     (78,760     0         0   
                                 

Long-Term Debt, excluding Current Maturities

   $ 1,020,000      $ 1,179,247      $ 805,000       $ 863,559   
                                 

 

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 Rules 13a-15 and 15d-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 at a reasonable assurance level 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 third quarter of 2010 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 heading “Environmental Matters” in Note 6 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this quarterly report is incorporated by reference in response to this item.

 

ITEM 1A. Risk Factors

For additional information about the risk factors facing the Company, see Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

 

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The Board of Directors has authorized a share repurchase program under which the Company may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During the three months ended September 30, 2010, the Company did not repurchase any shares of common stock. All purchases executed to date have been through open market transactions. The maximum number of shares that may yet be purchased under the plan as of September 30, 2010 was 4,795,300.

 

ITEM 5. Other Information

In connection with the termination of its qualified and non-qualified pension plans described in Note 10 of the Notes to the Condensed Consolidated Financial Statements, on October 27, 2010, the Company terminated its non-qualified supplemental executive retirement plan (“SERP”). Related to the termination of the SERP, the Company also amended the change in control agreements with certain officers of the Company to remove a provision in the agreements providing for an additional three-year service credit under the SERP upon a change in control. This amendment was necessary in order to comply with Section 409A of the Internal Revenue Code.

 

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ITEM 6. Exhibits

 

Exhibit

Number

  

Description

  4.1   

Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001).

 

(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).

 

(b) Amendment No. 2 to Note Purchase Agreement, dated as of September 28, 2010.

  4.2    Credit Agreement, dated as of September 22, 2010, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities LLC, as Syndication Agent, Bank of Montreal, as Documentation Agent, and the Lenders party thereto.
15.1    Awareness letter of PricewaterhouseCoopers LLP
31.1    302 Certification - Chairman, President and Chief Executive Officer
31.2    302 Certification - Vice President, Chief Financial Officer and Treasurer
32.1    906 Certification
*101.INS    XBRL Instance Document
*101.SCH    XBRL Taxonomy Extension Schema Document
*101.CAL    XBRL Taxonomy Extension Calculation Linkbase Document
*101.LAB    XBRL Taxonomy Extension Label Linkbase Document
*101.PRE    XBRL Taxonomy Extension Presentation Linkbase Document

 

* Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

 

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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 29, 2010   By:  

/S/    DAN O. DINGES        

    Dan O. Dinges
    Chairman, President and
    Chief Executive Officer
    (Principal Executive Officer)
October 29, 2010   By:  

/S/    SCOTT C. SCHROEDER        

    Scott C. Schroeder
    Vice President, Chief Financial Officer and Treasurer
    (Principal Financial Officer)
October 29, 2010   By:  

/S/    TODD M. ROEMER        

    Todd M. Roemer
    Controller
    (Principal Accounting Officer)

 

34

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