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, 2011

 

o

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 o

 

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 o

 

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  o

 

 

 

Non-accelerated filer  o

 

Smaller reporting company  o

(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 o  No x

 

As of October 24, 2011, there were 104,494,374 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, 2011 and 2010

3

 

 

Condensed Consolidated Balance Sheet at September 30, 2011 and December 31, 2010

4

 

 

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2011 and 2010

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

32

 

 

Item 4.      Controls and Procedures

34

 

 

Part II. Other Information

 

 

 

Item 1.      Legal Proceedings

35

 

 

Item 1A.   Risk Factors

35

 

 

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

35

 

 

Item 6.      Exhibits

36

 

 

Signatures

37

 

2



Table of Contents

 

PART I. FINANCIAL INFORMATION

 

ITEM  1.                           Financial Statements

 

CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

(In thousands, except per share amounts)

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

OPERATING REVENUES

 

 

 

 

 

 

 

 

 

Natural Gas

 

$

218,521

 

$

192,026

 

$

588,976

 

$

526,424

 

Brokered Natural Gas

 

9,467

 

11,675

 

38,947

 

49,896

 

Crude Oil and Condensate

 

33,158

 

19,234

 

79,792

 

60,427

 

Other

 

971

 

1,127

 

4,124

 

3,901

 

 

 

262,117

 

224,062

 

711,839

 

640,648

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Cost

 

8,204

 

10,281

 

33,362

 

43,342

 

Direct Operations

 

27,292

 

26,466

 

76,878

 

73,796

 

Transportation and Gathering

 

19,768

 

4,932

 

48,710

 

13,488

 

Taxes Other Than Income

 

7,042

 

8,489

 

21,070

 

31,135

 

Exploration

 

20,190

 

9,665

 

31,090

 

28,324

 

Impairment of Oil and Gas Properties

 

 

35,789

 

 

35,789

 

Depreciation, Depletion and Amortization

 

90,293

 

85,355

 

250,642

 

235,579

 

General and Administrative

 

27,949

 

21,077

 

78,254

 

49,675

 

 

 

200,738

 

202,054

 

540,006

 

511,128

 

Gain / (Loss) on Sale of Assets

 

3,854

 

265

 

36,408

 

5,411

 

INCOME FROM OPERATIONS

 

65,233

 

22,273

 

208,241

 

134,931

 

Interest Expense and Other

 

18,517

 

16,758

 

53,928

 

47,439

 

Income Before Income Taxes

 

46,716

 

5,515

 

154,313

 

87,492

 

Income Tax Expense

 

18,234

 

1,617

 

58,268

 

33,215

 

NET INCOME

 

$

28,482

 

$

3,898

 

$

96,045

 

$

54,277

 

 

 

 

 

 

 

 

 

 

 

Earnings Per Share

 

 

 

 

 

 

 

 

 

Basic

 

$

0.27

 

$

0.04

 

$

0.92

 

$

0.52

 

Diluted

 

$

0.27

 

$

0.04

 

$

0.91

 

$

0.52

 

 

 

 

 

 

 

 

 

 

 

Weighted-Average Shares Outstanding

 

 

 

 

 

 

 

 

 

Basic

 

104,285

 

103,955

 

104,232

 

103,889

 

Diluted

 

105,460

 

105,225

 

105,316

 

105,144

 

 

 

 

 

 

 

 

 

 

 

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.

 

3



Table of Contents

 

CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

 

 

 

September 30,

 

December 31,

 

(In thousands, except share amounts)

 

2011

 

2010

 

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and Cash Equivalents

 

$

62,928

 

$

55,949

 

Accounts Receivable, Net

 

101,612

 

94,488

 

Income Taxes Receivable

 

10,158

 

 

Inventories

 

28,296

 

29,667

 

Derivative Instruments

 

100,489

 

16,926

 

Other Current Assets

 

6,554

 

5,978

 

Total Current Assets

 

310,037

 

203,008

 

Properties and Equipment, Net (Successful Efforts Method)

 

4,103,317

 

3,762,760

 

Other Assets

 

59,043

 

39,263

 

 

 

$

4,472,397

 

$

4,005,031

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Accounts Payable

 

$

207,798

 

$

229,981

 

Income Taxes Payable

 

 

25,957

 

Deferred Income Taxes

 

31,975

 

 

Accrued Liabilities

 

49,204

 

47,897

 

Total Current Liabilities

 

288,977

 

303,835

 

Pension and Postretirement Benefits

 

39,443

 

34,053

 

Long-Term Debt

 

1,205,000

 

975,000

 

Deferred Income Taxes

 

785,146

 

714,953

 

Asset Retirement Obligation

 

74,784

 

72,311

 

Other Liabilities

 

35,877

 

32,179

 

Total Liabilities

 

2,429,227

 

2,132,331

 

 

 

 

 

 

 

Commitments and Contingencies

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ Equity

 

 

 

 

 

Common Stock:

 

 

 

 

 

Authorized – 240,000,000 Shares of $0.10 Par Value in 2011 and 2010 Issued–104,492,690 Shares and 104,210,084 Shares in 2011 and 2010, respectively

 

10,449

 

10,421

 

Additional Paid-in Capital

 

730,985

 

720,920

 

Retained Earnings

 

1,235,059

 

1,148,391

 

Accumulated Other Comprehensive Income/(Loss)

 

70,026

 

(3,683

)

Less Treasury Stock, at Cost:

 

 

 

 

 

202,200 Shares in 2011 and 2010, respectively

 

(3,349

)

(3,349

)

Total Stockholders’ Equity

 

2,043,170

 

1,872,700

 

 

 

$

4,472,397

 

$

4,005,031

 

 

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

 

4



Table of Contents

 

CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

 

 

 

Nine Months Ended
September 30,

 

(In thousands)

 

2011

 

2010

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net Income

 

$

96,045

 

$

54,277

 

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

 

 

 

 

 

Depreciation, Depletion and Amortization

 

250,642

 

235,579

 

Impairment of Oil and Gas Properties

 

 

35,789

 

Deferred Income Tax Expense

 

57,381

 

30,465

 

(Gain) / Loss on Sale of Assets

 

(36,408

)

(5,411

)

Exploration Expense

 

13,851

 

10,473

 

Unrealized Loss / (Gain) on Derivative Instruments

 

950

 

(162

)

Amortization of Debt Issuance Costs

 

3,317

 

8,298

 

Stock-Based Compensation, Pension and Other

 

42,432

 

12,886

 

Changes in Assets and Liabilities:

 

 

 

 

 

Accounts Receivable, Net

 

(7,124

)

4,842

 

Income Taxes

 

(36,115

)

4,937

 

Inventories

 

1,371

 

(4,353

)

Other Current Assets

 

(832

)

3,070

 

Accounts Payable and Accrued Liabilities

 

(9,941

)

(14,252

)

Other Assets and Liabilities

 

(203

)

(8,838

)

Stock-Based Compensation Tax Benefit

 

 

(108

)

Net Cash Provided by Operating Activities

 

375,366

 

367,492

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Capital Expenditures

 

(668,987

)

(658,123

)

Proceeds from Sale of Assets

 

82,109

 

21,033

 

Net Cash Used in Investing Activities

 

(586,878

)

(637,090

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings from Debt

 

330,000

 

300,000

 

Repayments of Debt

 

(100,000

)

(10,000

)

Dividends Paid

 

(9,379

)

(9,348

)

Capitalized Debt Issuance Costs

 

(1,025

)

(13,696

)

Other

 

(1,105

)

72

 

Net Cash Provided by Financing Activities

 

218,491

 

267,028

 

 

 

 

 

 

 

Net Increase / (Decrease) in Cash and Cash Equivalents

 

6,979

 

(2,570

)

Cash and Cash Equivalents, Beginning of Period

 

55,949

 

40,158

 

Cash and Cash Equivalents, End of Period

 

$

62,928

 

$

37,588

 

 

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

 

5



Table of Contents

 

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, 2010 (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 current year presentation. These reclassifications have no impact on previously reported net income.

 

With respect to the unaudited financial information of the Company as of September 30, 2011 and for the three and nine months ended September 30, 2011 and 2010, 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 28, 2011 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 Issued Accounting Pronouncements

 

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU No. 2011-04 generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. ASU No. 2011-04 results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP and IFRS. The amendments in ASU No. 2011-04 are to be applied prospectively. For public entities, the amendments are effective for interim and annual periods beginning after December 15, 2011. Early application by public entities is not permitted. The Company does not expect this guidance to have a significant impact on its consolidated financial position, results of operations or cash flows.

 

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income,” requiring most entities to present items of net income and other comprehensive income either in one continuous statement—referred to as the statement of comprehensive income—or in two separate, but consecutive, statements of net income and other comprehensive income. The new requirements are effective for public entities for fiscal years (including interim periods) beginning after December 15, 2011. The Company does not expect this guidance to have a significant impact on its consolidated financial position, results of operations or cash flows.

 

6



Table of Contents

 

2. PROPERTIES AND EQUIPMENT, NET

 

Properties and equipment, net are comprised of the following:

 

 

 

September 30,

 

December 31,

 

(In thousands)

 

2011

 

2010

 

 

 

 

 

 

 

Proved Oil and Gas Properties

 

$

5,377,363

 

$

4,794,650

 

Unproved Oil and Gas Properties

 

505,131

 

490,181

 

Gathering and Pipeline Systems

 

237,666

 

237,043

 

Land, Building and Other Equipment

 

79,109

 

86,248

 

 

 

6,199,269

 

5,608,122

 

Accumulated Depreciation, Depletion and Amortization

 

(2,095,952

)

(1,845,362

)

 

 

$

4,103,317

 

$

3,762,760

 

 

At September 30, 2011, 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.

 

In the third quarter of 2010, the Company recorded a $35.8 million impairment of oil and gas properties 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).

 

Haynesville/Bossier Shale Joint Ventures

 

During the first nine months of 2011, the Company entered into two participation agreements with third parties related to certain of its Haynesville and Bossier Shale leaseholds in east Texas. Under the terms of the participation agreements, the third parties agreed to fund 100% of the cost to drill and complete certain Haynesville and Bossier Shale wells in the related leaseholds over a multi-year period in exchange for a 75% working interest in the leaseholds. During the first nine months of 2011, the Company received a reimbursement of drilling costs incurred of approximately $11.2 million associated with the wells that had commenced drilling prior to the execution of the participation agreements.

 

In May 2011, the Company sold certain of its Haynesville and Bossier Shale oil and gas properties in east Texas to a third party. The Company received approximately $47.0 million in cash proceeds and recognized a $34.2 million gain on sale of assets.

 

Other Divestitures

 

In July 2011, the Company entered into a purchase and sale agreement to sell certain oil and gas properties located in Colorado, Utah and Wyoming to BreitBurn Energy Partners L.P. for $285 million. This transaction closed on October 6, 2011 and is subject to certain post-closing adjustments scheduled to occur in the fourth quarter of 2011.  The net book value associated with the oil and gas properties and the related asset retirement obligation held for sale as of September 30, 2011 were $291.3 million and $12.1 million, respectively, and are included in Properties and Equipment, Net and Asset Retirement Obligation, respectively, in the Condensed Consolidated Balance Sheet.

 

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 was 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 these properties were considered Level 2 in the fair value hierarchy.

 

7



Table of Contents

 

3. ADDITIONAL BALANCE SHEET INFORMATION

 

Certain balance sheet amounts are comprised of the following:

 

 

 

September 30,

 

December 31,

 

(In thousands)

 

2011

 

2010

 

 

 

 

 

 

 

ACCOUNTS RECEIVABLE, NET

 

 

 

 

 

Trade Accounts

 

$

98,661

 

$

91,077

 

Joint Interest Accounts

 

5,871

 

4,901

 

Other Accounts

 

810

 

2,603

 

 

 

105,342

 

98,581

 

Allowance for Doubtful Accounts

 

(3,730

)

(4,093

)

 

 

$

101,612

 

$

94,488

 

INVENTORIES

 

 

 

 

 

Natural Gas in Storage

 

$

18,633

 

$

13,371

 

Tubular Goods and Well Equipment

 

10,150

 

17,072

 

Pipeline Imbalances

 

(487

)

(776

)

 

 

$

28,296

 

$

29,667

 

OTHER CURRENT ASSETS

 

 

 

 

 

Drilling Advances

 

$

821

 

$

2,796

 

Prepaid Balances

 

3,499

 

2,925

 

Restricted Cash

 

2,234

 

 

Deferred Income Taxes

 

 

257

 

 

 

$

6,554

 

$

5,978

 

OTHER ASSETS

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

15,503

 

15,788

 

Debt Issuance Costs

 

18,744

 

22,061

 

Derivative Instruments

 

23,453

 

 

Other Accounts

 

1,343

 

1,414

 

 

 

$

59,043

 

$

39,263

 

ACCOUNTS PAYABLE

 

 

 

 

 

Trade Accounts

 

$

18,570

 

$

27,401

 

Natural Gas Purchases

 

6,047

 

3,596

 

Royalty and Other Owners

 

43,025

 

36,034

 

Accrued Capital Costs

 

127,489

 

146,824

 

Taxes Other Than Income

 

2,477

 

2,655

 

Wellhead Gas Imbalances

 

4,498

 

5,142

 

Other Accounts

 

5,692

 

8,329

 

 

 

$

207,798

 

$

229,981

 

ACCRUED LIABILITIES

 

 

 

 

 

Employee Benefits

 

$

15,921

 

$

10,790

 

Pension and Postretirement Benefits

 

1,688

 

1,688

 

Taxes Other Than Income

 

15,151

 

14,576

 

Interest Payable

 

15,708

 

19,488

 

Other Accounts

 

736

 

1,355

 

 

 

$

49,204

 

$

47,897

 

OTHER LIABILITIES

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

24,362

 

$

21,600

 

Derivative Instruments

 

 

2,180

 

Other Accounts

 

11,515

 

8,399

 

 

 

$

35,877

 

$

32,179

 

 

8



Table of Contents

 

4. LONG-TERM DEBT

 

The Company’s debt consisted of the following:

 

(In thousands)

 

September 30,
2011

 

December 31,
2010

 

Long-Term Debt

 

 

 

 

 

7.33% Weighted-Average Fixed Rate Notes

 

$

95,000

 

$

95,000

 

6.51% Weighted-Average Fixed Rate Notes

 

425,000

 

425,000

 

9.78% Notes

 

67,000

 

67,000

 

5.58% Weighted-Average Fixed Rate Notes

 

175,000

 

175,000

 

Credit Facility

 

443,000

 

213,000

 

 

 

$

1,205,000

 

$

975,000

 

 

The Company’s revolving credit facility provides for an available line of credit 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. Effective April 1, 2011, the lenders under the Company’s revolving credit facility approved an increase in the Company’s Borrowing Base from $1.5 billion to $1.7 billion as part of the annual redetermination under the terms of the credit facility. The Company’s plan to sell certain oil and gas properties located in Colorado, Utah and Wyoming, triggered an interim redetermination of the Company’s Borrowing Base and the $1.7 billion Borrowing Base was reaffirmed by the lenders effective September 27, 2011.

 

At September 30, 2011, the Company had $443.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.0% and $456.8 million available for future borrowings. In addition, the Company had letters of credit outstanding at September 30, 2011 of $0.3 million.

 

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:

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

(In thousands)

 

2011

 

2010

 

2011

 

2010

 

Weighted-Average Shares - Basic

 

104,285

 

103,955

 

104,232

 

103,889

 

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

 

1,175

 

1,270

 

1,084

 

1,255

 

Weighted-Average Shares - Diluted

 

105,460

 

105,225

 

105,316

 

105,144

 

 

 

 

 

 

 

 

 

 

 

Weighted-Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect

 

 

 

 

220

 

 

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.

 

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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 the PaDEP reached agreement on modifications to the Consent Order (First Modified Consent Order). In the First Modified Consent Order, the 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 the PaDEP, which could include the plugging and abandonment of up to 10 additional wells. 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.

 

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.

 

The Company believed that it was 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. The Company believed that offering installation of a whole-house water treatment system to the 14 households constituted compliance with the Company’s obligations under these consent orders.

 

On December 15, 2010, the Company entered a global settlement agreement and new consent order with the PaDEP (Global Settlement Agreement), which supersedes the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the Global Settlement Agreement, among other things, the Company agreed to pay a total of $4.2 million into separate escrow accounts for the benefit of each affected household, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, remediate two wells in the affected area, provide pressure, water quality and well headspace data to the PaDEP and offer water treatment to the affected households. The Global Settlement Agreement settles all outstanding issues and claims that are known and that could have been brought against the Company by the PaDEP relating to the wells in the affected area and the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. It also allows the Company to begin hydraulic fracturing and to commence drilling new wells in the affected areas after providing the PaDEP with well pressure data. Under the Global Settlement Agreement, the Company has no obligation to connect the impacted water supplies to a community public water system.

 

On January 11, 2011, certain of the affected households appealed the Global Settlement Agreement to the Pennsylvania Environmental Hearing Board. A hearing on the merits of this appeal is not expected to occur until 2012.

 

As of the date of this report, the Company is in continuing discussions with the PaDEP to address the results of the Company’s well pressure tests, water quality sampling and well headspace screenings. The Company requested PaDEP approval to resume hydraulic fracturing and new well drilling operations in the affected area, along with a request to cease temporary water deliveries to the affected

 

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households.  On October 18, 2011, the PaDEP concurred that temporary water deliveries to the property owners who are subject to the Global Settlement Agreement are no longer required.

 

As of September 30, 2011, the Company has paid $1.3 million in fines and penalties to the PaDEP related to this matter, paid $2.0 million to seven of the affected households and accrued a $2.2 million settlement liability that represents the unpaid escrow balance, which is included in Other Liabilities in the Condensed Consolidated Balance Sheet.

 

Transportation Agreements

 

During the first nine months of 2011, the Company amended certain gas transportation and gathering agreements with third party pipelines that increased the minimum daily quantity, increased the transportation fee and/or extended the term of the agreement.

 

Future minimum obligations under gas transportation agreements as of September 30, 2011 are as follows:

 

(In thousands)

 

 

 

2011

 

$

11,969

 

2012

 

57,066

 

2013

 

56,965

 

2014

 

56,965

 

2015

 

56,965

 

Thereafter

 

555,268

 

 

 

$

795,198

 

 

For further information on the Company’s gas transportation agreements, please refer to Note 8 of the Notes to the Consolidated Financial Statements in the Form 10-K.

 

Drilling Rig Commitments

 

As of September 30, 2011, the Company has a three-year drilling rig commitment for its capital program in the Marcellus Shale in northeast Pennsylvania commencing in the fourth quarter of 2011.  As of September 30, 2011, the aggregate minimum future drilling rig commitment was approximately $20.4 million.

 

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 management purposes and are not held for trading purposes. As of September 30, 2011, the Company had 42 derivative contracts open: 27 natural gas price swap arrangements, five natural gas collar arrangements, six natural gas basis swaps, one crude oil price collar arrangement and three crude oil price swap arrangements. During the first nine months of 2011, the Company entered into 31 new derivative contracts covering anticipated natural gas and crude oil production for 2011, 2012 and 2013.

 

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Table of Contents

 

As of September 30, 2011, 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

 

$6.24

   per Mcf

 

3,254

   Mmcf

 

Oct. 2011 - Dec. 2011

 

Natural Gas Swaps

 

$5.18

   per Mcf

 

98,302

   Mmcf

 

Oct. 2011 - Dec. 2012

 

Natural Gas Swaps

 

$5.28

   per Mcf

 

17,854

   Mmcf

 

Jan. 2012 - Dec. 2012

 

Natural Gas Collars

 

$6.17 Ceiling/ $5.13 Floor

   per Mcf

 

17,805

   Mmcf

 

Jan. 2013 - Dec. 2013

 

Crude Oil Collars

 

$93.25 Ceiling / $80.00 Floor

   per Bbl

 

92

   Mbbl

 

Oct. 2011- Dec. 2011

 

Crude Oil Swaps

 

$106.20

   per Bbl

 

92

   Mbbl

 

Oct. 2011 - Dec. 2011

 

Crude Oil Swaps

 

$105.00

   per Bbl

 

366

   Mbbl

 

Jan. 2012 - Dec. 2012

 

 

 

 

 

 

 

 

 

 

 

Derivatives Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

Natural Gas Basis Swaps

 

$(0.27

)  per Mcf

 

16,123

   Mmcf

 

Jan. 2012 - Dec. 2012

 

 

The change in fair value of derivatives designated as hedges that is effective is recorded to Accumulated Other Comprehensive Income / (Loss) in Stockholders’ Equity in the Condensed Consolidated Balance Sheet. The ineffective portion of the change in 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 Revenue and Crude Oil and Condensate Revenue, as appropriate, in the Condensed Consolidated Statement of Operations.

 

The following disclosures reflect the impact 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, 2011

 

December 31, 2010

 

Derivatives Designated as Hedging Instruments

 

 

 

 

 

 

 

Commodity Contracts

 

Derivative Instruments (current assets)

 

$

102,908

 

$

16,926

 

Commodity Contracts

 

Other Assets

 

24,164

 

 

 

 

 

 

127,072

 

16,926

 

Derivatives Not Designated as Hedging Instruments

 

 

 

 

 

 

 

Commodity Contracts

 

Derivative Instruments (current assets)

 

(2,419

)

 

Commodity Contracts

 

Other Assets

 

(711

)

 

Commodity Contracts

 

Other Liabilities

 

 

(2,180

)

 

 

 

 

(3,130

)

(2,180

)

 

 

 

 

$

123,942

 

$

14,746

 

 

At September 30, 2011 and December 31, 2010, unrealized gains of $127.1 million ($78.8 million, net of tax) and $16.9 million ($10.5 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income / (Loss). Based upon estimates at September 30, 2011, the Company expects to reclassify $63.8 million in after-tax income associated with its commodity hedges from Accumulated Other Comprehensive Income / (Loss) to the Condensed Consolidated Statement of Operations over the next 12 months.

 

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Table of Contents

 

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

Location of Gain (Loss)
Reclassified from

 

Amount of Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)

 

Derivatives Designated as
Hedging Instruments

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Accumulated OCI into
Income

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

(In thousands)

 

2011

 

2010

 

2011

 

2010

 

(In thousands)

 

2011

 

2010

 

2011

 

2010

 

Commodity Contracts

 

$

98,143

 

$

24,758

 

$

159,030

 

$

79,514

 

Natural Gas Revenues

 

$

21,170

 

$

39,461

 

$

48,318

 

$

109,714

 

 

 

 

 

 

 

 

 

 

 

Crude Oil and Condensate Revenues

 

1,382

 

5,160

 

566

 

14,522

 

 

 

 

 

 

 

 

 

 

 

 

 

$

22,552

 

$

44,621

 

$

48,884

 

$

124,236

 

 

For the three and nine months ended September 30, 2011 and 2010, respectively, there was no ineffectiveness recorded in our Condensed Consolidated Statement of Operations related to our derivative instruments.

 

Derivatives Not Designated as
Hedging Instruments 

 

Location of Gain (Loss)
Recognized in Income on

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

(In thousands)

 

Derivatives

 

2011

 

2010

 

2011

 

2010

 

Commodity Contracts

 

Natural Gas Revenues

 

$

(64

)

$

(193

)

$

(950

)

$

162

 

 

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

 

Accounting Standards Codification (ASC) 820, “Fair Value Measurements and Disclosures,” 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. ASC 820 establishes formal fair value hierarchy 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.

 

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 14 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 impairments of long-lived assets, at fair value on a nonrecurring basis. During the nine month period ended September 30, 2010, the Company recorded an impairment related to certain oil and gas properties. Refer to Note 2 for additional disclosures related to fair value associated with the impaired properties.

 

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Table of Contents

 

As none of the Company’s other non-financial assets and liabilities were impaired as of September 30, 2011 and 2010 and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures are not provided.

 

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, 2011 and December 31, 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,
2011

 

Assets

 

 

 

 

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

15,503

 

$

 

$

 

$

15,503

 

Derivative Contracts

 

 

 

123,942

 

123,942

 

Total Assets

 

$

15,503

 

$

 

$

123,942

 

$

139,445

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

24,362

 

$

 

$

 

$

24,362

 

Derivative Contracts

 

 

 

 

 

Total Liabilities

 

$

24,362

 

$

 

$

 

$

24,362

 

 

(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
December 31,
2010

 

Assets

 

 

 

 

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

15,788

 

$

 

$

 

$

15,788

 

Derivative Contracts

 

 

 

16,926

 

16,926

 

Total Assets

 

$

15,788

 

$

 

$

16,926

 

$

32,714

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

21,600

 

$

 

$

 

$

21,600

 

Derivative Contracts

 

 

 

2,180

 

2,180

 

Total Liabilities

 

$

21,600

 

$

 

$

2,180

 

$

23,780

 

 

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 non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions, while non-performance risk of the Company is evaluated using a market credit spread provided by the Company’s bank. The impact of non-performance risk relative to the Company’s derivative contracts was $1.5 million and $0.5 million at September 30, 2011 and December 31, 2010, respectively.

 

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Table of Contents

 

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

(In thousands)

 

2011

 

2010

 

2011

 

2010

 

Balance at beginning of period

 

$

48,415

 

$

87,803

 

$

14,746

 

$

112,307

 

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

 

 

 

 

 

 

 

 

 

Included in Earnings (1)

 

22,488

 

44,428

 

47,934

 

124,398

 

Included in Other Comprehensive Income

 

75,591

 

(19,863

)

110,146

 

(44,722

)

Settlements

 

(22,552

)

(44,621

)

(48,884

)

(124,236

)

Transfers In and/or Out of Level 3

 

 

 

 

 

Balance at end of period

 

$

123,942

 

$

67,747

 

$

123,942

 

$

67,747

 

 


(1) A loss of $0.1 million and $1.0 million for the three and nine months ended September 30, 2011, respectively, and a loss of $0.2 million and a gain of $0.2 million for the three and nine months ended September 30, 2010, respectively, was unrealized and included in Natural Gas Revenues in the Condensed Consolidated Statement of Operations.

 

There were no transfers between Level 1 and Level 2 measurements for the three and nine months ended September 30, 2011 and 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.

 

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, 2011

 

December 31, 2010

 

(In thousands)

 

Carrying
Amount

 

Estimated Fair
Value

 

Carrying
Amount

 

Estimated Fair
Value

 

Long-Term Debt

 

$

1,205,000

 

$

1,339,410

 

$

975,000

 

$

1,100,830

 

 

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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 / (Loss). The following tables illustrate the calculation of Comprehensive Income / (Loss) for the three and nine months ended September 30, 2011 and 2010:

 

 

 

Three Months Ended

 

 

 

September 30,

 

(In thousands)

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

 

 

$

28,482

 

 

 

$

3,898

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Reclassification Adjustment for Settled Contracts, net of taxes of $8,570 and $17,158, respectively

 

 

 

(13,982

)

 

 

(27,463

)

Changes in Fair Value of Hedge Positions, net of taxes of $(37,314) and $(9,608), respectively

 

 

 

60,829

 

 

 

15,150

 

Defined Benefit Pension and Postretirement Plans:

 

 

 

 

 

 

 

 

 

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

 

$

 

 

 

$

1,242

 

 

 

Net Loss due to Remeasurement, net of taxes of $1,614 and $0, respectively

 

(2,487

)

 

 

 

 

 

Settlement, net of taxes of $(930) and $(785), respectively

 

1,516

 

 

 

1,280

 

 

 

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

 

98

 

 

 

98

 

 

 

Amortization of Prior Service Cost, net of taxes of $(87) and $(82), respectively

 

141

 

 

 

131

 

 

 

Amortization of Net Loss, net of taxes of $(954) and $(1,248), respectively

 

1,559

 

827

 

2,038

 

4,789

 

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

 

 

 

31

 

 

 

(42

)

Total Other Comprehensive Income / (Loss)

 

 

 

47,705

 

 

 

(7,566

)

 

 

 

 

 

 

 

 

 

 

Comprehensive Income / (Loss)

 

 

 

$

76,187

 

 

 

$

(3,668

)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

(In thousands)

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

 

 

$

96,045

 

 

 

$

54,277

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Reclassification Adjustment for Settled Contracts, net of taxes of $18,576 and $46,695, respectively

 

 

 

(30,308

)

 

 

(77,541

)

Changes in Fair Value of Hedge Positions, net of taxes of $(60,423) and $(30,730), respectively

 

 

 

98,607

 

 

 

48,784

 

Defined Benefit Pension and Postretirement Plans:

 

 

 

 

 

 

 

 

 

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

 

 

 

 

$

1,242

 

 

 

Net Loss due to Remeasurement, net of taxes of $1,614 and $0, respectively

 

(2,487

)

 

 

 

 

 

Settlement, net of taxes of $(930) and $(785), respectively

 

1,516

 

 

 

1,280

 

 

 

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

 

294

 

 

 

294

 

 

 

Amortization of Prior Service Cost, net of taxes of $(328) and $(97), respectively

 

534

 

 

 

158

 

 

 

Amortization of Net Loss, net of taxes of $(3,390) and $(1,818), respectively

 

5,530

 

5,387

 

2,966

 

5,940

 

Foreign Currency Translation Adjustment, net of taxes of $(9) and $(47), respectively

 

 

 

23

 

 

 

78

 

Total Other Comprehensive Income / (Loss)

 

 

 

73,709

 

 

 

(22,739

)

 

 

 

 

 

 

 

 

 

 

Comprehensive Income / (Loss)

 

 

 

$

169,754

 

 

 

$

31,538

 

 

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Table of Contents

 

Changes in the components of Accumulated Other Comprehensive Income/ (Loss), net of taxes, for the nine months ended September 30, 2011 were as follows:

 

(In thousands)

 

Net Gains /
(Losses) on Cash
Flow Hedges

 

Defined Benefit
Pension and
Postretirement
Plans

 

Foreign Currency
Translation
Adjustment

 

Total

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2010

 

$

10,494

 

$

(14,122

)

$

(55

)

$

(3,683

)

Net change in unrealized gain on cash flow hedges, net of taxes of ($41,847)

 

68,299

 

 

 

68,299

 

Net change in defined benefit pension and postretirement plans, net of taxes of ($3,214)

 

 

5,387

 

 

5,387

 

Change in foreign currency translation adjustment, net of taxes of $(9)

 

 

 

23

 

23

 

Balance at September 30, 2011

 

$

78,793

 

$

(8,735

)

$

(32

)

$

70,026

 

 

10. PENSION AND OTHER POSTRETIREMENT BENEFITS

 

The components of net periodic benefit costs, included in General and Administrative Expense in the Condensed Consolidated Statement of Operations, were as follows:

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

(In thousands)

 

2011

 

2010

 

2011

 

2010

 

Qualified and Non-Qualified Pension Plans

 

 

 

 

 

 

 

 

 

Current Period Service Cost

 

$

 

$

571

 

$

 

$

2,365

 

Interest Cost

 

650

 

885

 

2,251

 

2,870

 

Expected Return on Plan Assets

 

(945

)

(1,091

)

(3,265

)

(3,171

)

Amortization of Prior Service Cost

 

228

 

213

 

862

 

255

 

Amortization of Net Loss

 

2,373

 

3,128

 

8,498

 

4,310

 

Curtailment Loss

 

 

424

 

 

424

 

Settlement

 

2,446

 

2,065

 

2,446

 

2,065

 

Net Periodic Pension Cost

 

$

4,752

 

$

6,195

 

$

10,792

 

$

9,118

 

 

 

 

 

 

 

 

 

 

 

Postretirement Benefits Other than Pension Plans

 

 

 

 

 

 

 

 

 

Current Period Service Cost

 

$

335

 

$

316

 

$

1,004

 

$

949

 

Interest Cost

 

467

 

424

 

1,402

 

1,271

 

Amortization of Net Loss

 

140

 

158

 

422

 

474

 

Amortization of Net Obligation at Transition

 

158

 

158

 

474

 

474

 

Total Postretirement Benefit Cost

 

$

1,100

 

$

1,056

 

$

3,302

 

$

3,168

 

 

Employer Contributions

 

The funding levels of the pension and postretirement benefit 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 2011. The Company previously disclosed in its financial statements for the year ended December 31, 2010 that it had not determined if any additional discretionary funding would be made in 2011. During the nine months ended September 30, 2011, the Company did not make any contributions to its qualified and non-qualified pension plans; discretionary contributions may, however, be made prior to December 31, 2011.

 

Termination and Amendment of Qualified and Non-Qualified Pension Plans

 

In July 2010, the Company notified its employees of its plan to terminate its qualified pension 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

 

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September 30, 2010. The Company then amended and restated the qualified pension plan to freeze benefit accruals, to provide for termination of the plan, to allow for an early retirement enhancement to be available to all active participants as of September 30, 2010 regardless of their age and years of service as of that date, and to make certain changes that were required or made desirable as a result of developments in the law. Because no further benefits will accrue under the qualified pension plan after September 30, 2010, the Company’s related non-qualified pension plan was effectively frozen and no additional benefits will be accrued under those arrangements after September 30, 2010. For further information regarding termination and amendment of qualified and non-qualified pension plans, refer to Note 6 of the Notes to the Consolidated Financial Statements in the Form 10-K.

 

11. STOCK-BASED COMPENSATION

 

Stock-based compensation expense (including the supplemental employee incentive plan) during the first nine months of 2011 and 2010 was $29.3 million and $8.9 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 2011 and 2010 was $10.0 million and $3.8 million, respectively.

 

Restricted Stock Awards

 

During the first nine months of 2011, 5,300 restricted stock awards were granted with a weighted-average grant date per share value of $35.39. 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 assumption of 7.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

 

Restricted Stock Units

 

During the first nine months of 2011, 29,701 restricted stock units were granted to non-employee directors of the Company with a grant date per share value of $41.75. 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 2011, 95,750 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 $40.74 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:

 

Weighted-Average Value per Stock Appreciation Right Granted During the Period

 

$

18.94

 

Assumptions:

 

 

 

Stock Price Volatility

 

52.7

%

Risk Free Rate of Return

 

2.3

%

Expected Dividend Yield

 

0.3

%

Expected Term (in years)

 

5.0

 

 

Performance Share Awards

 

During the first nine months of 2011, three types of performance share awards were granted to employees for a total of 394,757 performance shares, which included 92,696 performance share awards based on market conditions and 302,061 performance share awards based on performance conditions measured against the Company’s internal performance metrics. Of the 302,061 performance-based awards 92,696 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 vesting date. 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 209,365 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 12 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of performance share awards.

 

The performance period for the awards based on internal performance metrics commenced on January 1, 2011 and ends on December 31, 2013 and the grant date per share value for these awards was $40.74, 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

 

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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, 2011, it is considered probable that the criteria for the performance-based awards will be met. The Company used an annual forfeiture rate assumption ranging from 0% to 7% for purposes of recognizing stock-based compensation expense for all performance-based share awards.

 

The performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three-year performance period.  The performance shares based on market conditions have both an equity and liability component.  The following assumptions were used for the performance shares based on market conditions using a Monte Carlo model to value the liability and equity components of the awards. The equity portion of the 2011 awards was valued on the grant date (February 17, 2011) and was not marked to market. The liability portion of the awards was valued as of September 30, 2011 on a mark-to-market basis.

 

 

 

Grant Date

 

September 30, 2011

 

Value per Share

 

$

31.23

 

$39.90 - $57.46

 

Assumptions:

 

 

 

 

 

Stock Price Volatility

 

62.0

%

41.94% - 60.91%

 

Risk Free Rate of Return

 

1.3

%

0.02% - 0.29%

 

Expected Dividend Yield

 

0.2

%

0.2%

 

 

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 is as follows:

 

(In thousands)

 

 

 

Carrying amount of asset retirement obligations at December 31, 2010

 

$

72,311

 

Liabilities incurred

 

897

 

Liabilities settled

 

(1,040

)

Accretion expense

 

2,616

 

Carrying amount of asset retirement obligations at September 30, 2011

 

$

74,784

 

 

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Table of Contents

 

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, 2011, and the related condensed consolidated statements of operations for the three month and nine month periods ended September 30, 2011 and 2010, and the condensed consolidated statement of cash flows for the nine month periods ended September 30, 2011 and 2010. 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, 2010, and the related consolidated statements of operations, stockholders’ equity, comprehensive income and of cash flows for the year then ended (not presented herein), and in our report dated February 28, 2011, 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, 2010, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

 

/s/ PricewaterhouseCoopers LLP

 

Houston, Texas

October 28, 2011

 

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Table of Contents

 

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, 2011 and 2010 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, 2010 (Form 10-K).

 

As a result of our production growth and the commencement of various transportation and gathering agreements in 2011, we began separately reporting our transportation and gathering costs as a component of operating expenses in the Condensed Consolidated Statement of Operations. Previously reported transportation and gathering costs were reflected as a component of Natural Gas Revenues and have been reclassified to conform to current year presentation. Accordingly, previously reported operating revenues and operating expenses have increased with no impact on previously reported net income.

 

Overview

 

On an equivalent basis, our production for the nine months ended September 30, 2011 increased by 42% compared to the nine months ended September 30, 2010. For the nine months ended September 30, 2011, we produced 132.7 Bcfe compared to 93.2 Bcfe for the nine months ended September 30, 2010. Natural gas production was 127.2 Bcf and crude oil/condensate/NGL production was 920 Mbbls for the first nine months of 2011. Natural gas production increased by 43% when compared to the first nine months of 2010, which had production of 89.2 Bcf. This increase was primarily a result of increased production in northeast Pennsylvania associated with our Marcellus Shale drilling program and upgrades to the Lathrop compressor station in Susquehanna County, Pennsylvania, which included the commissioning of new compression during the first nine months of 2011. Partially offsetting the production increase in northeast Pennsylvania were decreases in production primarily in east and south Texas due to normal production declines and a shift from gas to oil projects. Crude oil/condensate/NGL production increased by 39%, to 920 Mbbls, when compared to the first nine months of 2010, which had production of 660 Mbbls. This increase was primarily the result of increased production associated with our Eagle Ford Shale drilling program in south Texas.

 

Our average realized natural gas price for the first nine months of 2011 was $4.64 per Mcf, 21% lower than the $5.90 per Mcf price realized in the first nine months of 2010. Our average realized crude oil price for the first nine months of 2011 was $89.69 per Bbl, 8% lower than the $97.43 per Bbl price realized in the first nine months of 2010. 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, 2011 increased by $71.2 million, or 11%, from the nine months ended September 30, 2010. Natural gas revenues, excluding unrealized gains/losses from the change in fair value of our derivatives not designated as hedges, increased by $63.7 million, or 12%, for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010 as the increase in natural gas production more than offset the lower realized natural gas prices. Crude oil and condensate revenues increased by $19.4 million, or 32%, for the first nine months of 2011 as compared to the first nine months of 2010, due to increased crude oil production partially offset by lower realized crude oil prices. Brokered natural gas revenues decreased by $10.9 million, or 22%, due to a decreased sales price and decreased 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 2011, we expect to spend approximately $825 to $875 million in capital and exploration expenditures, using proceeds from the sale of assets to supplement our cash flows from operations in order to fund incremental capital and exploration expenditures. We believe our cash on hand, operating cash flows in 2011, proceeds from asset sales and borrowings from our credit facility will be more than sufficient to fund our capital and exploration spending in 2011. 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, 2011, we invested approximately $666.7 million in our exploration and development efforts.

 

During the first nine months of 2011, we drilled 85 gross wells (73 development, five exploratory and seven extension wells) with a success rate of 99% compared to 83 gross wells (69 development, four exploratory and 10 extension wells) with a success rate of 98% for the comparable period of the prior year. For the full year of 2011, we plan to drill approximately 140 gross (100 net) wells.

 

While we consider acquisitions from time to time, we continue to remain focused on our strategies of pursuing drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline

 

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Table of Contents

 

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.

 

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, 2011 were funds generated from the sale of natural gas and crude oil production (including hedge realizations), borrowings under our credit facility and the sales of properties and other assets. These cash flows were primarily used to fund our development and exploration expenditures, in addition to payment of dividends and repayment of debt. 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. 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 revenues.

 

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 availability under our credit facility and liquidity available to meet our working capital requirements.

 

 

 

Nine Months Ended

 

 

 

September 30,

 

(In thousands)

 

2011

 

2010

 

Cash Flows Provided by Operating Activities

 

$

375,366

 

$

367,492

 

Cash Flows Used in Investing Activities

 

(586,878

)

(637,090

)

Cash Flows Provided by Financing Activities

 

218,491

 

267,028

 

Net Increase / (Decrease) in Cash and Cash Equivalents

 

$

6,979

 

$

(2,570

)

 

Operating Activities. Key components impacting net operating cash flows are commodity prices, production volumes and operating expenses. Net cash provided by operating activities in the first nine months of 2011 increased by $7.9 million over the first nine months of 2010. This increase was primarily due to increased operating income in 2011 as a result of higher operating revenues and an increase in the gain on sale of assets that outpaced the increase in operating expenses.  This increase was offset by changes in working capital and long-term assets and liabilities which decreased operating cash flows. The increase in operating revenues was primarily due to an increase in equivalent production partially offset by lower realized natural gas and crude oil prices. Equivalent production volumes increased by 42% for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010 as a result of higher natural gas and crude oil production. Average realized natural gas prices decreased by 21% for the first nine months of 2011 compared to the first nine months of 2010. Average realized crude oil prices decreased by 8% compared to the same period. See “Results of Operations” for additional information relative to commodity price, production and operating expense 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.

 

Investing Activities. The primary use of cash in investing activities was capital spending. We established our 2011 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. Cash flows used in investing activities decreased by $50.2 million for the first nine months of 2011 compared to the first nine months of 2010. The decrease was primarily due to higher proceeds from sale of assets of $61.1 million slightly offset by an increase of $10.9 million in capital and exploration expenditures.

 

Financing Activities. Cash flows provided by financing activities decreased by $48.5 million from the first nine months of 2010 to the first nine months of 2011. This was primarily due to an increase in repayments of debt partially offset by higher borrowings, resulting in lower net borrowings, and lower capitalized debt issuance costs in the first nine months of 2011 compared to the first nine months of 2010.

 

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Table of Contents

 

At September 30, 2011, we had $443.0 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of 4.0%. 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. Effective April 1, 2011, the lenders under our credit facility approved an increase in the borrowing base under the facility from $1.5 billion to $1.7 billion as part of the annual redetermination under the terms of the credit facility.  Our plan to sell certain oil and gas properties located in Colorado, Utah and Wyoming, triggered an interim redetermination of the Company’s Borrowing Base and the $1.7 billion Borrowing Base was reaffirmed by the lenders effective September 27, 2011.  As of September 30, 2011, our available credit under our credit facility was $456.8 million.

 

We are in compliance in all material respects with our debt covenants as of September 30, 2011.

 

We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. Management believes that, with operating cash flow, existing cash on hand, availability under our revolving credit facility and proceeds from the sale of assets, we have the capacity to finance our spending plans, service our debt obligations as they become due and maintain our strong financial position.

 

Capitalization

 

Information about our capitalization is as follows:

 

 

 

September 30,

 

December 31,

 

(Dollars in millions)

 

2011

 

2010

 

 

 

 

 

 

 

 

 

Debt (1)

 

$

1,205.0

 

$

975.0

 

Stockholders’ Equity

 

2,043.2

 

1,872.7

 

Total Capitalization

 

$

3,248.2

 

$

2,847.7

 

 

 

 

 

 

 

Debt to Capitalization

 

37.1

%

34.2

%

 

 

 

 

 

 

Cash and Cash Equivalents

 

$

62.9

 

$

55.9

 

 


(1)   Includes $443.0 million and $213.0 million of borrowings outstanding under our revolving credit facility at September 30, 2011 and December 31, 2010, respectively.

 

During the nine months ended September 30, 2011, we paid dividends of $9.4 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, borrowings under our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.

 

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

 

 

 

Nine Months Ended

 

 

 

September 30,

 

(In millions)

 

2011

 

2010

 

Capital Expenditures

 

 

 

 

 

Drilling and Facilities

 

$

561.0

 

$

445.8

 

Leasehold Acquisitions

 

60.9

 

109.9

 

Acquisitions

 

 

0.8

 

Pipeline and Gathering

 

7.2

 

29.4

 

Other

 

6.5

 

6.6

 

 

 

635.6

 

592.5

 

Exploration Expense

 

31.1

 

28.3

 

Total

 

$

666.7

 

$

620.8

 

 

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Table of Contents

 

For the full year of 2011, we plan to drill approximately 140 gross (100 net) wells. This 2011 drilling program is part of approximately $825 to $875 million in total planned capital and exploration expenditures. See “Overview” 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

 

We have various contractual obligations in the normal course of our operations. For further information, please refer to “Transportation Agreements”  and “Drilling Rig Commitments” under Note 6 in the Notes to the Condensed Consolidated Financial Statements and Note 8 in the Notes to Consolidated Financial Statements included in our 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 Issued Accounting Pronouncements

 

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.” The amendments in ASU No. 2011-04 generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. ASU No. 2011-04 results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP and IFRSs. The amendments in ASU No. 2011-04 are to be applied prospectively. For public entities, the amendments are effective for interim and annual periods beginning after December 15, 2011. Early application by public entities is not permitted. We do not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.

 

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income,” requiring most entities to present items of net income and other comprehensive income either in one continuous statement—referred to as the statement of comprehensive income—or in two separate, but consecutive, statements of net income and other comprehensive income. The new requirements are effective for public entities for fiscal years (including interim periods) beginning after December 15, 2011. We do not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.

 

Results of Operations

 

Third Quarter of 2011 and 2010 Compared

 

We reported net income in the third quarter of 2011 of $28.5 million, or $0.27 per share, compared to net income in the third quarter of 2010 of $3.9 million, or $0.04 per share. Net income increased in the third quarter of 2011 by $24.6 million, primarily due to an increase in operating revenues and gain on sale of assets and a decrease in operating expenses partially offset by increases in interest expense and income tax expense.

 

Operating revenues increased by $38.1 million due to increased natural gas and crude oil and condensate revenues partially offset by decreased brokered natural gas revenues. Operating expenses decreased by $1.3 million between periods primarily due to a decrease in impairment of oil and gas properties, lower brokered natural gas cost and taxes other than income, partially offset by increases in transportation and gathering expenses, exploration expense, general and administration expense, depreciation, depletion, and amortization and direct operating expenses. In addition, net income was impacted during the third quarter by an increase in gain on sale of assets and higher income tax and interest expense.

 

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Table of Contents

 

Revenue, Price and Volume Variances

 

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

 

Revenue Variances (In thousands)

 

 

 

Three Months Ended September 30,

 

Variance

 

 

 

2011

 

2010

 

Amount

 

Percent

 

Natural Gas (1) 

 

$

218,585

 

$

192,219

 

$

26,366

 

14

%

Brokered Natural Gas

 

9,467

 

11,675

 

(2,208

)

(19

)%

Crude Oil and Condensate

 

33,158

 

19,234

 

13,924

 

72

%

Other

 

971

 

1,127

 

(156

)

(14

)%

 


(1)  Natural Gas Revenues exclude the unrealized loss of $0.1 and $0.2 million from the change in fair value of our derivatives not designated as hedges in 2011 and 2010, respectively.

 

 

 

 

 

 

 

 

 

Increase

 

 

 

Three Months Ended September 30,

 

Variance

 

(Decrease)

 

 

 

2011

 

2010

 

Amount

 

Percent

 

(In thousands)

 

Price Variances

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (1)

 

$

4.58

 

$

5.52

 

$

(0.94

)

(17

)%

$

(44,757

)

Crude Oil and Condensate (2)

 

$

86.89

 

$

98.26

 

$

(11.37

)

(12

)%

(4,339

)

Total

 

 

 

 

 

 

 

 

 

$

(49,096

)

Volume Variances

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Mmcf)

 

47,707

 

34,850

 

12,857

 

37

%

$

71,123

 

Crude Oil and Condensate (Mbbl)

 

382

 

196

 

186

 

95

%

18,263

 

Total

 

 

 

 

 

 

 

 

 

$

89,386

 

 


(1)  These prices include the realized impact of derivative instrument settlements, which increased the price by $0.44 per Mcf in 2011 and by $1.13 per Mcf in 2010.

(2)  These prices include the realized impact of derivative instrument settlements, which increased the price by $3.62 per Bbl in 2011 and by $26.33 per Bbl in 2010.

 

Natural Gas Revenues

 

The increase in natural gas revenues of $26.4 million, excluding the impact of unrealized losses discussed above, is primarily due to increased production during the third quarter of 2011, partially offset by lower realized natural gas prices. The increased production is primarily due to our Marcellus Shale drilling program in northeast Pennsylvania and the start up of additional compressors at the Lathrop compressor station in Susquehanna County, Pennsylvania.  This increase is partially offset by decreases in production in east and south Texas due to normal production declines and a shift from gas to oil projects.

 

Crude Oil and Condensate Revenues

 

The increase in crude oil and condensate revenues of $13.9 million is primarily due to increased production due to our Eagle Ford Shale drilling program in south Texas partially offset by lower realized oil prices.

 

25



Table of Contents

 

Brokered Natural Gas Revenue and Cost

 

 

 

 

 

 

 

 

 

 

 

Price and

 

 

 

Three Months Ended

 

 

 

Volume

 

 

 

September 30,

 

Variance

 

Variances

 

 

 

2011

 

2010

 

Amount

 

Percent

 

(In thousands)

 

Brokered Natural Gas Sales

 

 

 

 

 

 

 

 

 

 

 

Sales Price ($/Mcf)

 

$

4.99

 

$

5.14

 

$

(0.15

)

(3

)%

$

(285

)

Volume Brokered (Mmcf)

 

x

1,899

 

x

2,272

 

(373

)

(16

)%

(1,923

)

Brokered Natural Gas Revenues (In thousands)

 

$

9,467

 

$

11,675

 

 

 

 

 

$

(2,208

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Purchases

 

 

 

 

 

 

 

 

 

 

 

Purchase Price ($/Mcf)

 

$

4.32

 

$

4.53

 

$

(0.21

)

(5

)%

$

398

 

Volume Brokered (Mmcf)

 

x

1,899

 

x

2,272

 

(373

)

(16

)%

1,679

 

Brokered Natural Gas Cost (In thousands)

 

$

8,204

 

$

10,281

 

 

 

 

 

$

2,077

 

Brokered Natural Gas Margin (In thousands)

 

$

1,263

 

$

1,394

 

 

 

 

 

$

(131

)

 

The decreased brokered natural gas margin of $0.1 million is primarily a result of a decrease in brokered volumes coupled with a decrease in purchase price that outpaced the sales 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,

 

 

 

2011

 

2010

 

(In thousands)

 

Realized

 

Unrealized

 

Realized

 

Unrealized

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues - Increase / (Decrease) to Revenue

 

 

 

 

 

 

 

 

 

Cash Flow Hedges

 

 

 

 

 

 

 

 

 

Natural Gas

 

$

21,170

 

$

 

$

39,461

 

$

 

Crude Oil

 

1,382

 

 

5,160

 

 

Total Cash Flow Hedges

 

22,552

 

 

44,621

 

 

 

 

 

 

 

 

 

 

 

 

Other Derivative Financial Instruments

 

 

 

 

 

 

 

 

 

Natural Gas Basis Swaps

 

 

(64

)

 

(193

)

Total Other Derivative Financial Instruments

 

 

(64

)

 

(193

)

 

 

 

 

 

 

 

 

 

 

Total Cash Flow Hedges and Other Derivative Financial Instruments

 

$

22,552

 

$

(64

)

$

44,621

 

$

(193

)

 

26



Table of Contents

 

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 derivative contract counterparties are Bank of Montreal, BNP Paribas, JPMorgan Chase, Goldman Sachs and Bank of America.

 

Operating and Other Expenses

 

 

 

Three Months Ended

September 30,

 

Variance

 

(In thousands)

 

2011

 

2010

 

Amount

 

Percent

 

Operating and Other Expenses

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Cost

 

$

8,204

 

$

10,281

 

$

(2,077

)

(20

)%

Direct Operations

 

27,292

 

26,466

 

826

 

3

%

Transportation and Gathering

 

19,768

 

4,932

 

14,836

 

301

%

Taxes Other Than Income

 

7,042

 

8,489

 

(1,447

)

(17

)%

Exploration

 

20,190

 

9,665

 

10,525

 

109

%

Impairment of Oil and Gas Properties

 

 

35,789

 

(35,789

)

(100

)%

Depreciation, Depletion and Amortization

 

90,293

 

85,355

 

4,938

 

6

%

General and Administrative

 

27,949

 

21,077

 

6,872

 

33

%

Total Operating Expense

 

$

200,738

 

$

202,054

 

$

(1,316

)

(1

)%

 

 

 

 

 

 

 

 

 

 

(Gain) / Loss on Sale of Assets

 

$

(3,854

)

$

(265

)

$

3,589

 

1354

%

Interest Expense and Other

 

18,517

 

16,758

 

1,759

 

10

%

Income Tax Expense

 

18,234

 

1,617

 

16,617

 

1028

%

 

Total costs and expenses from operations decreased by $1.3 million, or 1%, in the third quarter of 2011 compared to the same period of 2010. The primary reasons for this fluctuation are as follows:

 

·                  Impairment of Oil and Gas Properties decreased by $35.8 million from the third quarter of 2011 compared to the third quarter of 2010 due to the impairment of two south Texas fields recognized in the third quarter of 2010 because of continued price declines and normal production declines.  There were no impairments in third quarter of 2011.

 

·                  Brokered Natural Gas Costs decreased $2.1 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

·                  Taxes Other Than Income decreased $1.5 million primarily due to lower ad valorem and franchise tax expense partially offset by higher production tax expense due to fewer tax credits and related refunds on qualifying wells received in the third quarter of 2011 compared to 2010.

 

·                  Transportation and Gathering increased by $14.8 million primarily due to the commencement of various firm transportation and gathering arrangements in the first nine months of 2011 in Susquehanna County, Pennsylvania.

 

·                  Exploration Expense increased $10.5 million primarily due to dry hole costs related to an exploratory well in Montana partially offset by lower geophysical and geological costs.

 

·                  General and Administrative increased by $6.9 million primarily due to $6.2 million higher stock-based compensation expense primarily associated with the mark to market of the liability portion of our performance shares as a result of our higher average stock price for the month of September 2011 compared to the average stock price for the month of September 2010.

 

·                  Depreciation, Depletion and Amortization increased by $4.9 million, of which $6.7 million was due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes partially offset by a lower DD&A rate of $1.62 per Mcfe for three months ended September 30, 2011 compared to $2.06 per Mcfe for three months ended September 30, 2010. The increase in depletion and depreciation was offset by a decrease in amortization of unproved properties of $2.3 million.

 

Gain / (Loss) on Sale of Assets

 

An aggregate gain of $3.9 million was recognized in the third quarter of 2011 primarily due to the sale of non-core assets as part of our ongoing asset portfolio management program.

 

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Table of Contents

 

Income Tax Expense

 

Income tax expense increased by $16.6 million in the third quarter of 2011 compared to the third quarter of 2010 primarily due to increased pretax income and a higher effective tax rate. The effective tax rate for the third quarter of 2011 and 2010 was 39.0% and 29.3%, respectively. The effective tax rate was higher as a result of provision to return adjustments recorded in the third quarter 2011 having a lesser impact due to higher quarterly pretax income.

 

Interest Expense and Other

 

Interest expense and other increased by $1.8 million in the third quarter of 2011 compared to the third quarter of 2010 primarily due to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately $407.7 million during the third quarter of 2011 compared to approximately $392.7 million during the third quarter of 2010. The increase in borrowings was partially offset by a lower weighted-average effective interest rate on the credit facility of approximately 3.7% during the third quarter of 2011 compared to approximately 3.8% during the third quarter of 2010. Furthermore, in December 2010 we issued $175 million aggregate principal amount of 5.58% weighted-average fixed rate notes, which increased interest expense recognized in the third quarter of 2011.

 

Nine Months of 2011 and 2010 Compared

 

We reported net income in the first nine months of 2011 of $96.0 million, or $0.92 per share, compared to net income in the first nine months of 2010 of $54.3 million, or $0.52 per share. Net income increased in the first nine months of 2011 by $41.8 million, primarily due to an increase in operating revenues and gain on sale of assets, partially offset by increases in operating expenses, interest expense and income tax expense.

 

Operating revenues increased by $71.2 million, largely due to increased natural gas and crude oil and condensate revenues, partially offset by decreased brokered natural gas revenues. Operating expenses increased by $28.9 million between periods primarily due to increases in transportation and gathering expenses, general and administrative expenses, depreciation, depletion and amortization and direct operations and exploration expense partially offset by a decrease in impairment of oil and gas properties and lower taxes other than income and brokered natural gas cost. In addition, net income was impacted during the first nine months by increased gain on sale of assets partially offset by higher interest expense and income tax expense.

 

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Table of Contents

 

Revenue, Price and Volume Variances

 

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

 

Revenue Variances (In thousands)

 

 

 

Nine Months Ended September 30,

 

Variance

 

 

 

2011

 

2010

 

Amount

 

Percent

 

Natural Gas (1) 

 

$

589,926

 

$

526,262

 

$

63,664

 

12

%

Brokered Natural Gas

 

38,947

 

49,896

 

(10,949

)

(22

)%

Crude Oil and Condensate

 

79,792

 

60,427

 

19,365

 

32

%

Other

 

4,124

 

3,901

 

223

 

6

%

 


(1)       Natural Gas Revenues exclude the unrealized loss of $1.0 million and the unrealized gain of $0.2 million from the change in fair value of our derivatives not designated as hedges in 2011 and 2010, respectively.

 

 

 

Nine Months Ended September 30,

 

Variance

 

 

 

2011

 

2010

 

Amount

 

Percent

 

Price Variances

 

 

 

 

 

 

 

 

 

Natural Gas (1)

 

$

4.64

 

$

5.90

 

$

(1.26

)

(21

)%

Crude Oil and Condensate (2)

 

$

89.69

 

$

97.43

 

$

(7.74

)

(8

)%

Total

 

 

 

 

 

 

 

 

 

Volume Variances

 

 

 

 

 

 

 

 

 

Natural Gas (Mmcf)

 

127,206

 

89,203

 

38,003

 

43

%

Crude Oil and Condensate (Mbbl)

 

890

 

620

 

270

 

43

%

Total

 

 

 

 

 

 

 

 

 

 


(1)       These prices include the realized impact of derivative instrument settlements, which increased the price by $0.38 per Mcf in 2011 and by $1.23 per Mcf in 2010.

(2)       These prices include the realized impact of derivative instrument settlements, which increased the price by $0.64 per Bbl in 2011 and by $23.42 per Bbl in 2010.

 

Natural Gas Revenues

 

The increase in Natural Gas Revenues of $63.7 million is primarily due to increased production during the first nine months of 2011, partially offset by lower realized natural gas prices. The increased production is primarily due to increased production associated with our Marcellus Shale drilling program and upgrades to the compressors at the Lathrop compressor station in Susquehanna County, Pennsylvania during the first nine months of the year, partially offset by decreases in production primarily in east and south Texas due to normal production declines and a shift from gas to oil projects.

 

Crude Oil and Condensate Revenues

 

The increase in Crude Oil and Condensate Revenues of $19.4 million is primarily due to increased production partially offset by lower realized oil prices.  The increase in production is primarily due to our drilling program in the Eagle Ford Shale in south Texas, partially offset by lower production in east Texas.

 

29



Table of Contents

 

Brokered Natural Gas Revenue and Cost

 

 

 

 

 

 

 

 

 

 

 

Price and

 

 

 

Nine Months Ended

 

 

 

 

 

Volume

 

 

 

September 30,

 

Variance

 

Variances

 

 

 

2011

 

2010

 

Amount

 

Percent

 

(In thousands)

 

Brokered Natural Gas Sales

 

 

 

 

 

 

 

 

 

 

 

Sales Price ($/Mcf)

 

$

5.15

 

$

5.60

 

$

(0.45

)

(8

)%

$

(3,402

)

Volume Brokered (Mmcf)

 

x

7,560

 

x

8,915

 

(1,355

)

(15

)%

(7,547

)

Brokered Natural Gas Revenues (In thousands)

 

$

38,947

 

$

49,896

 

 

 

 

 

$

(10,949

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Purchases

 

 

 

 

 

 

 

 

 

 

 

Purchase Price ($/Mcf)

 

$

4.41

 

$

4.86

 

$

(0.45

)

(9

)%

$

3,380

 

Volume Brokered (Mmcf)

 

x

7,560

 

x

8,915

 

(1,355

)

(15

)%

6,600

 

Brokered Natural Gas Cost (In thousands)

 

$

33,362

 

$

43,342

 

 

 

 

 

$

9,980

 

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Margin (In thousands)

 

$

5,585

 

$

6,554

 

 

 

 

 

$

(969

)

 

The decreased brokered natural gas margin of $1.0 million is primarily a result of a decrease in brokered volumes.

 

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,

 

 

 

2011

 

2010

 

(In thousands)

 

Realized

 

Unrealized

 

Realized

 

Unrealized

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues - Increase / (Decrease) to Revenue

 

 

 

 

 

 

 

 

 

Cash Flow Hedges

 

 

 

 

 

 

 

 

 

Natural Gas

 

$

48,318

 

$

 

$

109,714

 

$

 

Crude Oil

 

566

 

 

14,522

 

 

Total Cash Flow Hedges

 

48,884

 

 

124,236

 

 

 

 

 

 

 

 

 

 

 

 

Other Derivative Financial Instruments

 

 

 

 

 

 

 

 

 

Natural Gas Basis Swaps

 

 

(950

)

 

162

 

Total Other Derivative Financial Instruments

 

 

(950

)

 

162

 

 

 

 

 

 

 

 

 

 

 

Total Cash Flow Hedges and Other Derivative Financial Instruments

 

$

48,884

 

$

(950

)

$

124,236

 

$

162

 

 

30



Table of Contents

 

Operating and Other Expenses

 

 

 

Nine Months Ended
September 30,

 

Variance

 

(In thousands)

 

2011

 

2010

 

Amount

 

Percent

 

Operating and Other Expenses

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Cost

 

$

33,362

 

$

43,342

 

$

(9,980

)

(23

)%

Direct Operations

 

76,878

 

73,796

 

3,082

 

4

%

Transportation and Gathering

 

48,710

 

13,488

 

35,222

 

261

%

Taxes Other Than Income

 

21,070

 

31,135

 

(10,065

)

(32

)%

Exploration

 

31,090

 

28,324

 

2,766

 

10

%

Impairment of Oil and Gas Properties

 

 

35,789

 

(35,789

)

(100

)%

Depreciation, Depletion and Amortization

 

250,642

 

235,579

 

15,063

 

6

%

General and Administrative

 

78,254

 

49,675

 

28,579

 

58

%

Total Operating Expense

 

$

540,006

 

$

511,128

 

$

28,878

 

6

%

 

 

 

 

 

 

 

 

 

 

(Gain) / Loss on Sale of Assets

 

$

(36,408

)

$

(5,411

)

$

30,997

 

573

%

Interest Expense and Other

 

53,928

 

47,439

 

6,489

 

14

%

Income Tax Expense

 

58,268

 

33,215

 

25,053

 

75

%

 

Total costs and expenses from operations increased by $28.9 million, or 6%, in the first nine months of 2011 compared to the same period of 2010. The primary reasons for this fluctuation are as follows:

 

·                  Transportation and Gathering increased by $35.2 million primarily due to the commencement of various firm transportation and gathering arrangements in the first nine months of 2011 primarily in Susquehanna County, Pennsylvania.

 

·                  General and Administrative increased by $28.6 million primarily due to $19.2 million higher stock-based compensation expense primarily associated with the mark to market of the liability portion of our performance shares as a result of our higher average stock price for the month of September 2011 compared to the average stock price for the month of September 2010 and $5.9 million higher pension expense due to the acceleration of amortization of prior service costs and actuarial losses as a result of the plan termination and expected liquidation. Higher professional service costs also contributed to the increase.

 

·                  Depreciation, Depletion and Amortization increased by $15.1 million, of which $22.0 million was due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes offset by a lower DD&A rate of $1.67 per Mcfe for nine months ended September 30, 2011 compared to $2.14 per Mcfe for nine months ended September 30, 2010 and a $1.6 million increase in amortization of asset retirement obligation costs. The increase in depletion and depreciation was offset by a decrease in amortization of unproved properties of $8.5 million primarily due to a decrease in amortization rates due to a shift in our drilling and development activities.

 

·                  Direct Operations increased $3.1 million largely due to increased operating costs primarily driven by increased production. Contributing to the increase are higher workover and environmental and regulatory costs associated with the remediation of certain wells in northeast Pennsylvania as a result of the PaDEP Global Settlement. Offsetting these increases were lower compression expenses primarily due to the sale of our gathering system in northeast Pennsylvania in the fourth quarter of 2010 and increased use of centralized compression.  Lease maintenance costs were also lower in the first nine months of 2011 compared to the same period of 2010.

 

·                  Exploration Expense increased $2.8 million primarily due to higher dry hole costs incurred related to an exploratory well in Montana in 2011, partially offset by lower geophysical and geological costs primarily due to a reduction in the acquisition of seismic data.

 

·                  Impairment of Oil and Gas Properties decreased by $35.8 million for the first nine months of 2011 compared to the first nine months of 2010 due to the impairment of two south Texas fields recognized in the first nine months of 2010 as a result of continued price declines and normal production declines.  There were no impairments in the first nine months of 2011.

 

·                  Taxes Other Than Income decreased $10.1 million due to decreased production taxes as a result of tax refunds and credits received in 2011 on qualifying wells and lower ad valorem and business and occupational taxes partially offset by an increase in franchise taxes expense.

 

·                  Brokered Natural Gas Costs decreased $10.0 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

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Table of Contents

 

Gain / (Loss) on Sale of Assets

 

An aggregate gain of $36.4 million was recognized in the first nine months of 2011 on the sale of oil and gas properties in east Texas and the sale of non-core assets as part of our ongoing asset portfolio management program.  In 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.

 

Income Tax Expense

 

Income tax expense increased by $25.1 million in the first nine months of 2011 compared to the first nine months of 2010 primarily due to increased pretax income partially offset by a lower effective tax rate. The effective tax rate for the first nine months of 2011 and 2010 was 37.7% and 38.0%, respectively.

 

Interest Expense and Other

 

Interest expense and other increased by $6.5 million in the first nine months of 2011 compared to the first nine months of 2010 primarily due to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately $340.2 million during the first nine months of 2011 compared to approximately $304.1 million during the first nine months of 2010. The weighted-average effective interest rate on the credit facility increased to approximately 4.0% during the first nine months of 2011 compared to approximately 3.8% during the first nine months of 2010. In addition, in December 2010, we issued $175 million aggregate principal amount of 5.58% weighted-average fixed rate notes, which increased interest expense recognized in the first nine months of 2011.

 

Forward-Looking Information

 

The statements regarding future financial and operating performance and results, market prices, future hedging activities and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” 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.

 

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, 2011, we had 42 derivative contracts open: 27 natural gas price swap arrangements, five natural gas collar arrangements, six natural gas basis swaps, one crude oil price collar arrangement and three crude oil price swap arrangements. During the first nine months of 2011, we entered into 31 new derivative contracts covering anticipated crude oil and natural gas production for 2011, 2012, and 2013.

 

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Table of Contents

 

As of September 30, 2011, we had the following outstanding commodity derivatives:

 

Commodity and Derivative Type

 

Weighted-Average Contract Price

 

Volume

 

Contract Period

 

Net Unrealized
Gain / (Loss)

 

Derivatives Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Swaps

 

$6.24

 

per Mcf

 

3,254

 

Mmcf

 

Oct. 2011 - Dec. 2011

 

$

6,785

 

Natural Gas Swaps

 

$5.18

 

per Mcf

 

98,302

 

Mmcf

 

Oct. 2011 - Dec. 2012

 

86,650

 

Natural Gas Swaps

 

$5.28

 

per Mcf

 

17,854

 

Mmcf

 

Jan. 2012 - Dec. 2012

 

15,267

 

Natural Gas Collars

 

$6.17 Ceiling/ $5.13 Floor

 

per Mcf

 

17,805

 

Mmcf

 

Jan. 2013 - Dec. 2013

 

8,196

 

Crude Oil Collars

 

$93.25 Ceiling / $80.00 Floor

 

per Bbl

 

92

 

Mbbl

 

Oct. 2011- Dec. 2011

 

408

 

Crude Oil Swaps

 

$106.20

 

per Bbl

 

92

 

Mbbl

 

Oct. 2011 - Dec. 2011

 

2,466

 

Crude Oil Swaps

 

$105.00

 

per Bbl

 

366

 

Mbbl

 

Jan. 2012 - Dec. 2012

 

8,725

 

 

 

 

 

 

 

 

 

 

 

 

 

$

128,497

 

Derivatives Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Basis Swaps

 

$(0.27

)

per Mcf

 

16,123

 

Mmcf

 

Jan. 2012 - Dec. 2012

 

(3,073

)

 

 

 

 

 

 

 

 

 

 

 

 

$

125,424

 

 

The amounts set forth under the net unrealized gain / (loss) column in the table above represent our total unrealized gain position at September 30, 2011 and exclude the impact of non-performance risk of $1.5 million. Non-performance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while non-performance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

 

From time to time, we enter into natural gas and crude oil swap and collar agreements with counterparties to hedge price risk associated with a portion of our production. These agreements are not held for trading purposes. Under the 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. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us.

 

We had natural gas price swaps covering 51.9 Bcf, or 41%, of our first nine months of 2011 natural gas production at an average price of $5.36 per Mcf.

 

We had one crude oil swap covering 183 Mbbl, or 21%, of our first nine months of 2011 crude oil production, at an average price of $106.20 per Bbl.

 

During the first nine months of 2011, crude oil collars covered 273 Mbbl, or 31% of total crude oil production, with a weighted-average floor price of $80.00 per Bbl and a weighted-average ceiling price of $93.25 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 due to the short-term maturities of these instruments.

 

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.

 

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Table of Contents

 

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

 

 

 

September 30, 2011

 

December 31, 2010

 

(In thousands)

 

Carrying
Amount

 

Estimated Fair
Value

 

Carrying
Amount

 

Estimated Fair
Value

 

Long-Term Debt

 

$

1,205,000

 

$

1,339,410

 

$

975,000

 

$

1,100,830

 

 

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 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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Table of Contents

 

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.

 

We have received a number of Notices of Violation from the Pennsylvania Department of Environmental Protection (PaDEP) relating to alleged violations, primarily with respect to the Pennsylvania Clean Streams Law, the Pennsylvania Oil and Gas Act and the Pennsylvania Solid Waste Management Act and the rules and regulations promulgated thereunder. We have responded to these Notices of Violation, have remediated the areas in question and are actively cooperating with the PaDEP. While we cannot predict with certainty whether these Notices of Violation will result in fines and/or penalties, if fines and/or penalties are imposed, the aggregate of these fines and/or penalties could result in monetary sanctions in excess of $100,000.

 

In August 2011, the Company received a subpoena from the New York Attorney General’s Office requesting documents and information regarding the Company’s shale and unconventional reservoir reserves calculations. The Company is providing documents and information responsive to the request and is cooperating with the Attorney General’s Office in the matter.

 

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, 2010.

 

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 nine months ended September 30, 2011, 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, 2011 was 4,795,300.

 

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Table of Contents

 

ITEM 6.                               Exhibits

 

Exhibit
Number

 

Description

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.DEF

 

XBRL Taxonomy Extension Definition Linkbase Document

 

 

 

101.LAB

 

XBRL Taxonomy Extension Label Linkbase Document

 

 

 

101.PRE

 

XBRL Taxonomy Extension Presentation Linkbase Document

 

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Table of Contents

 

SIGNATURES

 

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

 

 

CABOT OIL & GAS CORPORATION

 

 

(Registrant)

 

 

 

October 28, 2011

By:

/S/    DAN O. DINGES

 

 

Dan O. Dinges

 

 

Chairman, President and

 

 

Chief Executive Officer

 

 

(Principal Executive Officer)

 

 

 

October 28, 2011

By:

/S/    SCOTT C. SCHROEDER

 

 

Scott C. Schroeder

 

 

Vice President, Chief Financial Officer and Treasurer

 

 

(Principal Financial Officer)

 

 

 

October 28, 2011

By:

/S/    TODD M. ROEMER

 

 

Todd M. Roemer

 

 

Controller

 

 

(Principal Accounting Officer)

 

37