10-Q 1 a12-18967_110q.htm 10-Q

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, 2012

 

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 22, 2012, there were 210,242,354 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 Balance Sheet at September 30, 2012 and December 31, 2011

3

 

 

Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2012 and 2011

4

 

 

Condensed Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011

5

 

 

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2012 and 2011

6

 

 

Notes to the Condensed Consolidated Financial Statements

7

 

 

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

21

 

 

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

22

 

 

Item 3.      Quantitative and Qualitative Disclosures about Market Risk

32

 

 

Item 4.      Controls and Procedures

35

 

 

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 BALANCE SHEET (Unaudited)

 

 

 

September 30,

 

December 31,

 

(In thousands, except share amounts)

 

2012

 

2011

 

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and Cash Equivalents

 

$

37,501

 

$

29,911

 

Accounts Receivable, Net

 

103,634

 

114,381

 

Income Taxes Receivable

 

1,183

 

1,388

 

Inventories

 

17,696

 

21,278

 

Derivative Instruments

 

61,723

 

174,263

 

Other Current Assets

 

2,937

 

4,579

 

Total Current Assets

 

224,674

 

345,800

 

Properties and Equipment, Net (Successful Efforts Method)

 

4,218,921

 

3,934,584

 

Derivative Instruments

 

4,379

 

21,249

 

Other Assets

 

34,963

 

29,860

 

 

 

$

4,482,937

 

$

4,331,493

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Accounts Payable

 

$

276,149

 

$

217,294

 

Current Portion of Long-Term Debt

 

75,000

 

 

Deferred Income Taxes

 

14,229

 

55,132

 

Accrued Liabilities

 

47,412

 

70,918

 

Total Current Liabilities

 

412,790

 

343,344

 

Postretirement Benefits

 

40,993

 

38,708

 

Long-Term Debt

 

987,000

 

950,000

 

Deferred Income Taxes

 

837,319

 

802,592

 

Asset Retirement Obligation

 

63,069

 

60,142

 

Other Liabilities

 

41,479

 

31,939

 

Total Liabilities

 

2,382,650

 

2,226,725

 

 

 

 

 

 

 

Commitments and Contingencies

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ Equity

 

 

 

 

 

Common Stock:

 

 

 

 

 

Authorized — 480,000,000 Shares of $0.10 Par Value in 2012 and 240,000,000 Shares of $0.10 Par Value in 2011 Issued—210,242,354 Shares and 209,019,458 Shares in 2012 and 2011, respectively

 

21,024

 

20,902

 

Additional Paid-in Capital

 

718,760

 

724,377

 

Retained Earnings

 

1,336,594

 

1,258,291

 

Accumulated Other Comprehensive Income

 

27,258

 

104,547

 

Less Treasury Stock, at Cost:

 

 

 

 

 

404,400 Shares in 2012 and 2011, respectively

 

(3,349

)

(3,349

)

Total Stockholders’ Equity

 

2,100,287

 

2,104,768

 

 

 

$

4,482,937

 

$

4,331,493

 

 

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

 

3



Table of Contents

 

 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)

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

OPERATING REVENUES

 

 

 

 

 

 

 

 

 

Natural Gas

 

$

231,896

 

$

218,521

 

$

639,729

 

$

588,976

 

Crude Oil and Condensate

 

57,870

 

33,158

 

165,317

 

79,792

 

Brokered Natural Gas

 

5,238

 

9,467

 

23,831

 

38,947

 

Other

 

1,870

 

971

 

5,790

 

4,124

 

 

 

296,874

 

262,117

 

834,667

 

711,839

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

Direct Operations

 

28,269

 

27,292

 

84,895

 

76,878

 

Transportation and Gathering

 

34,430

 

19,768

 

97,827

 

48,710

 

Brokered Natural Gas

 

4,258

 

8,204

 

20,380

 

33,362

 

Taxes Other Than Income

 

10,436

 

7,042

 

39,873

 

21,070

 

Exploration

 

9,303

 

20,190

 

29,548

 

31,090

 

Depreciation, Depletion and Amortization

 

110,448

 

90,293

 

335,421

 

250,642

 

General and Administrative

 

23,829

 

27,949

 

93,249

 

78,254

 

 

 

220,973

 

200,738

 

701,193

 

540,006

 

Gain / (Loss) on Sale of Assets

 

(126

)

3,854

 

67,042

 

36,408

 

INCOME FROM OPERATIONS

 

75,775

 

65,233

 

200,516

 

208,241

 

Interest Expense and Other

 

16,219

 

18,517

 

51,631

 

53,928

 

Income Before Income Taxes

 

59,556

 

46,716

 

148,885

 

154,313

 

Income Tax Expense

 

22,948

 

18,234

 

58,021

 

58,268

 

NET INCOME

 

$

36,608

 

$

28,482

 

$

90,864

 

$

96,045

 

 

 

 

 

 

 

 

 

 

 

Earnings Per Share

 

 

 

 

 

 

 

 

 

Basic

 

$

0.17

 

$

0.14

 

$

0.43

 

$

0.46

 

Diluted

 

$

0.17

 

$

0.14

 

$

0.43

 

$

0.46

 

 

 

 

 

 

 

 

 

 

 

Weighted-Average Shares Outstanding

 

 

 

 

 

 

 

 

 

Basic

 

209,656

 

208,570

 

209,433

 

208,463

 

Diluted

 

211,226

 

210,920

 

210,997

 

210,631

 

 

 

 

 

 

 

 

 

 

 

Dividends per common share

 

$

0.02

 

$

0.02

 

$

0.06

 

$

0.05

 

 

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 COMPREHENSIVE INCOME (Unaudited)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

(In thousands)

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

$

36,608

 

$

28,482

 

$

90,864

 

$

96,045

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Reclassification Adjustment for Settled Hedge Contracts(1) 

 

(37,294

)

(13,982

)

(115,943

)

(30,308

)

Changes in Fair Value of Hedge Contracts(2) 

 

(24,361

)

60,829

 

30,091

 

98,607

 

Defined Benefit Pension and Postretirement Plans:

 

 

 

 

 

 

 

 

 

Net Loss due to Remeasurement(3) 

 

 

(2,487

)

 

(2,487

)

Settlement(4) 

 

 

1,516

 

 

1,516

 

Amortization of Net Obligation at Transition(5) 

 

 

98

 

 

294

 

Amortization of Prior Service Cost(6) 

 

 

141

 

135

 

534

 

Amortization of Net Loss(7) 

 

79

 

1,559

 

8,428

 

5,530

 

Foreign Currency Translation Adjustment(8) 

 

 

31

 

 

23

 

Total Other Comprehensive Income / (Loss)

 

(61,576

)

47,705

 

(77,289

)

73,709

 

 

 

 

 

 

 

 

 

 

 

Comprehensive Income / (Loss)

 

$

(24,968

)

$

76,187

 

$

13,575

 

$

169,754

 

 


(1)

Net of income taxes of $23,644 and $8,570 for the three months ended September 30, 2012 and 2011, respectively, and $73,507 and $18,576 for the nine months ended September 30, 2012 and 2011, respectively.

 

 

(2)

Net of income taxes of $15,444 and $(37,314) for the three months ended September 30, 2012 and 2011, respectively, and $(19,208) and $(60,423) for the nine months ended September 30, 2012 and 2011, respectively.

 

 

(3)

Net of income taxes of $0 and $1,614 for the three months ended September 30, 2012 and 2011, respectively, and $0 and $1,614 for the nine months ended September 30, 2012 and 2011, respectively.

 

 

(4)

Net of income taxes of $0 and $(930) for the three months ended September 30, 2012 and 2011, respectively, and $0 and $(930) for the nine months ended September 30, 2012 and 2011, respectively.

 

 

(5)

Net of income taxes of $0 and $(60) for the three months ended September 30, 2012 and 2011, respectively, and $0 and $(180) for the nine months ended September 30, 2012 and 2011, respectively.

 

 

(6)

Net of income taxes of $0 and $(87) for the three months ended September 30, 2012 and 2011, respectively and $(86) and $(328) for the nine months ended September 30, 2012 and 2011, respectively.

 

 

(7)

Net of income taxes of $(53) and $(954) for the three months ended September 30, 2012 and 2011, respectively and $(5,347) and $(3,390) for the nine months ended September 30, 2012 and 2011, respectively.

 

 

(8)

Net of income taxes of $0 and $(6) for the three months ended September 30, 2012 and 2011, respectively and $0 and $(9) for the nine months ended September 30, 2012 and 2011, respectively.

 

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

 

5



Table of Contents

 

CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net Income

 

$

90,864

 

$

96,045

 

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

 

 

 

 

 

Depreciation, Depletion and Amortization

 

335,421

 

250,642

 

Deferred Income Tax Expense

 

42,714

 

57,381

 

(Gain) / Loss on Sale of Assets

 

(67,042

)

(36,408

)

Exploration Expense

 

12,118

 

13,851

 

Unrealized (Gain) / Loss on Derivative Instruments

 

449

 

950

 

Amortization of Debt Issuance Costs

 

4,300

 

3,317

 

Stock-Based Compensation, Pension and Other

 

37,518

 

42,432

 

Changes in Assets and Liabilities:

 

 

 

 

 

Accounts Receivable, Net

 

10,747

 

(7,124

)

Income Taxes

 

205

 

(36,115

)

Inventories

 

3,582

 

1,371

 

Other Current Assets

 

(1,125

)

(832

)

Accounts Payable and Accrued Liabilities

 

(16,391

)

(9,941

)

Other Assets and Liabilities

 

1,752

 

(203

)

Net Cash Provided by Operating Activities

 

455,112

 

375,366

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Capital Expenditures

 

(669,198

)

(668,987

)

Proceeds from Sale of Assets

 

132,740

 

82,109

 

Investment in Equity Method Investment

 

(4,488

)

 

Net Cash Used in Investing Activities

 

(540,946

)

(586,878

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings from Debt

 

280,000

 

330,000

 

Repayments of Debt

 

(168,000

)

(100,000

)

Dividends Paid

 

(12,561

)

(9,379

)

Capitalized Debt Issuance Costs

 

(5,005

)

(1,025

)

Other

 

(1,010

)

(1,105

)

Net Cash Provided by Financing Activities

 

93,424

 

218,491

 

 

 

 

 

 

 

Net Increase / (Decrease) in Cash and Cash Equivalents

 

7,590

 

6,979

 

Cash and Cash Equivalents, Beginning of Period

 

29,911

 

55,949

 

Cash and Cash Equivalents, End of Period

 

$

37,501

 

$

62,928

 

 

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

 

6



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 disclosed in its Annual Report on Form 10-K for the year ended December 31, 2011 (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 with current year presentation. These reclassifications have no impact on previously reported net income.

 

On January 3, 2012, the Board of Directors declared a 2-for-1 split of the Company’s common stock in the form of a stock dividend. The stock dividend was distributed on January 25, 2012 to shareholders of record as of January 17, 2012. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company’s common stock.

 

With respect to the unaudited financial information of the Company as of September 30, 2012 and for the three and nine months ended September 30, 2012 and 2011, 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 26, 2012 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.

 

Recent 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 this update 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. This update 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 are effective for interim and annual periods beginning after December 15, 2011 and are to be applied prospectively. This update did not have any impact on the Company’s consolidated financial position, results of operations or cash flows.

 

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income.” ASU No. 2011-05 was amended in December 2011 by ASU No. 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU No. 2011-05.” ASU No. 2011-12 defers only those changes in ASU No. 2011-05 that relate to the presentation of reclassification adjustments. All other requirements in ASU No. 2011-05 are not affected by ASU No. 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements.  ASU No. 2011-05 and 2011-12 are effective for fiscal years (including interim periods) beginning after December 15, 2011. The Company has elected to present two separate but consecutive financial statements. These updates did not have any impact on the Company’s consolidated financial position, results of operations or cash flows.

 

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. This guidance will primarily impact the Company’s disclosures associated with its commodity derivatives. The Company does not expect this guidance to have any impact on its consolidated financial position, results of operations or cash flows.

 

7



Table of Contents

 

2. PROPERTIES AND EQUIPMENT, NET

 

Properties and equipment, net are comprised of the following:

 

 

 

September 30,

 

December 31,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

Proved Oil and Gas Properties

 

$

5,618,507

 

$

5,006,846

 

Unproved Oil and Gas Properties

 

478,999

 

478,942

 

Gathering and Pipeline Systems

 

238,962

 

238,660

 

Land, Building and Other Equipment

 

83,301

 

80,908

 

 

 

6,419,769

 

5,805,356

 

Accumulated Depreciation, Depletion and Amortization

 

(2,200,848

)

(1,870,772

)

 

 

$

4,218,921

 

$

3,934,584

 

 

At September 30, 2012, 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.

 

Divestitures

 

In June 2012, the Company sold a 35% non-operated working interest associated with certain of its Pearsall shale undeveloped leaseholds in south Texas to a wholly-owned subsidiary of Osaka Gas Co., Ltd. (Osaka) for total consideration of approximately $251.0 million.  The Company received $125.0 million in cash proceeds and Osaka agreed to fund 85% of the Company’s share of future drilling and completion costs associated with these leaseholds until it has paid approximately $126.0 million in accordance with a joint development agreement entered into at the closing. The drilling and completion carry will terminate two years after the closing of the transaction. The Company recognized a $67.0 million gain on sale of assets associated with this sale.

 

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 reimbursement of drilling costs incurred of approximately $11.2 million associated with 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.

 

8



Table of Contents

 

3. ADDITIONAL BALANCE SHEET INFORMATION

 

Certain balance sheet amounts are comprised of the following:

 

 

 

September 30,

 

December 31,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

ACCOUNTS RECEIVABLE, NET

 

 

 

 

 

Trade Accounts

 

$

99,753

 

$

111,306

 

Joint Interest Accounts

 

3,804

 

5,417

 

Other Accounts

 

1,092

 

1,003

 

 

 

104,649

 

117,726

 

Allowance for Doubtful Accounts

 

(1,015

)

(3,345

)

 

 

$

103,634

 

$

114,381

 

INVENTORIES

 

 

 

 

 

Natural Gas in Storage

 

$

10,122

 

$

13,513

 

Tubular Goods and Well Equipment

 

6,507

 

7,146

 

Other Accounts

 

1,067

 

619

 

 

 

$

17,696

 

$

21,278

 

OTHER CURRENT ASSETS

 

 

 

 

 

Prepaid Balances and Other

 

2,937

 

2,345

 

Restricted Cash

 

 

2,234

 

 

 

$

2,937

 

$

4,579

 

OTHER ASSETS

 

 

 

 

 

Deferred Compensation Plan

 

$

11,462

 

$

10,838

 

Debt Issuance Cost

 

18,385

 

17,680

 

Equity Method Investment

 

4,450

 

 

Other Accounts

 

666

 

1,342

 

 

 

$

34,963

 

$

29,860

 

ACCOUNTS PAYABLE

 

 

 

 

 

Trade Accounts

 

$

17,511

 

$

18,253

 

Natural Gas Purchases

 

4,277

 

3,012

 

Royalty and Other Owners

 

47,699

 

48,113

 

Accrued Capital Costs

 

164,139

 

138,122

 

Taxes Other Than Income

 

1,415

 

2,076

 

Drilling Advances

 

33,244

 

1,489

 

Wellhead Gas Imbalances

 

2,358

 

2,312

 

Other Accounts

 

5,506

 

3,917

 

 

 

$

276,149

 

$

217,294

 

ACCRUED LIABILITIES

 

 

 

 

 

Employee Benefits

 

$

16,360

 

$

26,035

 

Pension and Postretirement Benefits

 

1,260

 

6,331

 

Taxes Other Than Income

 

12,450

 

12,297

 

Interest Payable

 

12,801

 

24,701

 

Derivative Contracts

 

2,941

 

385

 

Other Accounts

 

1,600

 

1,169

 

 

 

$

47,412

 

$

70,918

 

OTHER LIABILITIES

 

 

 

 

 

Deferred Compensation Plan

 

$

22,668

 

$

20,187

 

Derivative Contracts

 

5,868

 

 

Other Accounts

 

12,943

 

11,752

 

 

 

$

41,479

 

$

31,939

 

 

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4. DEBT AND CREDIT AGREEMENTS

 

The Company’s debt and credit agreements consisted of the following:

 

(In thousands)

 

September 30,
2012

 

December 31,
2011

 

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

 

300,000

 

188,000

 

Current Maturities

 

 

 

 

 

7.33% Weighted-Average Fixed Rate Notes

 

(75,000

)

 

Long-Term Debt, excluding Current Maturities

 

$

987,000

 

$

950,000

 

 

In May 2012, the Company amended its revolving credit facility to adjust the margins associated with borrowings under the facility and extend the maturity date from September 2015 to May 2017. The credit facility, as amended, provides for an available credit line of $900 million with an accordion feature, which allows the Company to increase the available credit line by an additional $500 million if one or more of the existing or new banks agree to provide such increased amount.  Interest rates under the credit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin, as follows:

 

 

 

Debt Percentage

 

 

 

<25%

 

>25% <50%

 

>50% <75%

 

>75% <90%

 

>90%

 

Eurodollar Loans

 

1.50%

 

1.75%

 

2.00%

 

2.25%

 

2.50%

 

ABR Loans

 

0.50%

 

0.75%

 

1.00%

 

1.25%

 

1.50%

 

 

As of September 30, 2012, the amended credit facility provided for a $1.7 billion borrowing base. The other terms and conditions of the amended facility are generally consistent with the terms and conditions of the credit agreement prior to its amendment.

 

In conjunction with entering into the amendment to the credit facility, the Company incurred $5.0 million of debt issuance costs, which were capitalized and will be amortized over the term of the amended credit facility. Approximately $1.3 million in unamortized cost associated with the original credit facility was recognized as a debt extinguishment cost, which was included in Interest Expense and Other in the Condensed Consolidated Statement of Operations, and the remaining unamortized costs of $11.0 million will be amortized over the term of the amended credit facility in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

 

At September 30, 2012, the Company had $300.0 million of borrowings outstanding under the amended credit facility at a weighted-average interest rate of 2.3% and $599.0 million available for future borrowings.

 

5. EQUITY METHOD INVESTMENT

 

Constitution Pipeline Company, LLC

 

The Company accounts for its investment in entities over which the Company has significant influence, but not control, using the equity method of accounting. Under the equity method of accounting, the Company records its proportionate share of net earnings, declared dividends and partnership distributions based on the most recently available financial statements of the investee (generally on a one month lag). The Company also evaluates its equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in the value of the investment.

 

In February 2012, the Company entered into a Precedent Agreement with Constitution Pipeline Company, LLC (Constitution), at the time a wholly owned subsidiary of Williams Partners L.P., to develop and construct a 120 mile large diameter pipeline to transport its production in northeast Pennsylvania to both the New England and New York markets.  Under the terms of the Precedent Agreement, the Company will have transportation rights for up to approximately 500,000 Mcf per day of capacity on the newly constructed pipeline, subject to regulatory approval and certain terms and conditions to be determined.

 

In April 2012, the Company entered into an Amended and Restated Limited Liability Company Agreement (LLC Agreement) with Constitution, which thereby became an unconsolidated investee. Under the terms of the LLC Agreement, the Company acquired a

 

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25% equity interest and agreed to invest approximately $187 million, subject to a contribution cap of $250 million.  The investment, which is expected to occur over the next three years, will fund the development and construction of the pipeline and related facilities.

 

During the first nine months of 2012, the Company made contributions of $4.5 million to fund costs associated with the project. The Company’s net book value in this equity investment was $4.5 million as of September 30, 2012 and is included in Other Assets in the Condensed Consolidated Balance Sheet. There were no material earnings or losses associated with Constitution during the first nine months of 2012.  Earnings (losses) on Equity Method Investment are included in Interest Expense and Other in the Condensed Consolidated Statement of Operations.

 

6. 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 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)

 

2012

 

2011

 

2012

 

2011

 

Weighted-Average Shares - Basic

 

209,656

 

208,570

 

209,433

 

208,463

 

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

 

1,570

 

2,350

 

1,564

 

2,168

 

Weighted-Average Shares - Diluted

 

211,226

 

210,920

 

210,997

 

210,631

 

 

 

 

 

 

 

 

 

 

 

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

 

46

 

 

102

 

 

 

7. COMMITMENTS AND CONTINGENCIES

 

Transportation Agreements

 

During the first nine months of 2012, the Company entered into a liquids transportation agreement that commenced in the third quarter of 2012. The Company’s total future minimum transportation commitments as of September 30, 2012 are as follows:

 

(In thousands)

 

 

 

2012

 

$

28,117

 

2013

 

121,920

 

2014

 

127,620

 

2015

 

127,698

 

2016

 

128,071

 

Thereafter

 

1,289,626

 

 

 

$

1,823,052

 

 

For further information on the Company’s transportation agreements, please refer to Note 7 of the Notes to the Consolidated Financial Statements in the 2011 Form 10-K.

 

Legal Matters

 

Preferential Purchase Right Litigation

 

In September 2005, the Company and Linn Energy, LLC were sued by Power Gas Marketing & Transmission, Inc. in the Court of Common Pleas of Indiana County, Pennsylvania. The lawsuit seeks unspecified damages arising out of the Company’s 2003 sale of oil and gas properties located in Indiana County, Pennsylvania, to Linn Energy, LLC. The plaintiff alleges breach of a preferential purchase right regarding those properties contained in a 1969 joint operating agreement to which the plaintiff was a party. The Company initially obtained judgment as a matter of law as to all claims in a decision by the trial court dated February 2007. Plaintiff

 

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appealed the ruling to the Pennsylvania Superior Court, where the ruling in favor of the Company was reversed and remanded to the trial court in March 2008. The Company appealed the Superior Court ruling to the Pennsylvania Supreme Court, but in December 2008 that Court declined to review. Effective July 2008, Linn Energy, LLC sold the subject properties to XTO Energy, Inc., giving rise to a second lawsuit for unspecified damages filed in September 2009 by EXCO—North Coast Energy, Inc., as successor in interest to Power Gas Marketing & Transmission, Inc., against the Company, Linn Energy, LLC and XTO Energy, Inc. The second lawsuit has been consolidated into the first lawsuit. A bench trial was held in early June 2012. Closing arguments have been set for mid-January 2013.

 

The Company believes that the plaintiff’s claims lack merit and does not consider a loss related to this matter to be probable; however, due to the inherent uncertainties of litigation, a loss is possible. In the event that the Company is found liable, the potential loss is currently estimated to be less than $15 million.

 

Other

 

The Company is also a defendant in various other legal proceedings arising in the normal course of business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company’s financial position, results of operations or cash flows.

 

Contingency Reserves

 

When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters in which reserves have been established. The Company believes that any such amount above the amounts accrued is not material to the Condensed Consolidated Financial Statements. Future changes in facts and circumstances not currently foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

 

Environmental Matters

 

Pennsylvania Department of Environmental Protection

 

On December 15, 2010, the Company entered into a consent order and settlement agreement (CO&SA) with the Pennsylvania Department of Environmental Protection (PaDEP), addressing a number of environmental issues originally identified in 2008 and 2009, including alleged releases of drilling mud and other substances, alleged record keeping violations at various wells and alleged natural gas contamination of water supplies to 14 households in Susquehanna County, Pennsylvania.  On January 11, 2011, certain of the affected households appealed the CO&SA to the Pennsylvania Environmental Hearing Board (PEHB).  On October 17, 2011, the Company requested PaDEP approval to resume hydraulic fracturing and new natural gas well drilling operations in the affected area, along with a request to cease temporary water deliveries to the affected households.  On October 18, 2011, the PaDEP concurred that temporary water deliveries to the property owners are no longer necessary.  On November 18, 2011, certain of the affected households appealed this order to the PEHB, which appeal was later consolidated with the CO&SA appeal.

 

The Company is in continuing discussions with the PaDEP to address the results of the Company’s natural gas well test data, water quality sampling and water well headspace screenings, which were required pursuant to the CO&SA. On August 21, 2012, the PaDEP notified the Company that it could commence completion operations on existing wells within the concerned area.

 

As of September 30, 2012, the Company has paid $1.3 million in settlement of fines and penalties sought or claimed by the PaDEP related to this matter and all of the affected households have accepted the $4.2 million that was placed into escrow for their benefit.  Furthermore, as of October 18, 2012, all of the appellants have dismissed their appeal to the PEHB. With the withdrawal of these appeals, the Company does not believe it has any further exposure related to this matter.

 

For additional information on the PaDEP matter, refer to Note 7 of the Notes to the Consolidated Financial Statements in the 2011 Form 10-K.

 

United States Environmental Protection Agency

 

By letter dated January 6, 2012, the United States Environmental Protection Agency (EPA) sent a Required Submission of Information—Dimock Township Drinking Water Contamination letter to the Company pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA). The Required Submission of Information requested all

 

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documents, water sampling results and any other correspondence related to the Company’s activities in the area of concern. The Company provided information pursuant to the request.

 

Upon review of information from Dimock residents, the PaDEP, and the Company, the EPA determined that further water well sampling was necessary and initiated two rounds of water sampling to address concerns about drinking water in Dimock. In July 2012, based on the outcome of the water sampling, the EPA determined that levels of contaminants do not pose a health concern and that it would take no further action.

 

8. 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, 2012, 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

 

$5.22

 

per Mcf

 

24,131

 

Mmcf

 

Oct. 2012 - Dec. 2012

 

Natural Gas Collars

 

$3.60 Floor / $4.17 Ceiling

 

per Mcf

 

2,963

 

Mmcf

 

Nov. 2012 - Dec. 2012

 

Natural Gas Collars

 

$5.15 Floor / $6.18 Ceiling

 

per Mcf

 

10,637

 

Mmcf

 

Jan. 2013 - Dec. 2013

 

Natural Gas Collars

 

$5.15 Floor / $6.23 Ceiling

 

per Mcf

 

7,092

 

Mmcf

 

Jan. 2013 - Dec. 2013

 

Natural Gas Collars

 

$3.09 Floor / $4.12 Ceiling

 

per Mcf

 

35,458

 

Mmcf

 

Jan. 2013 - Dec. 2013

 

Natural Gas Collars

 

$3.40 Floor / $4.12 Ceiling

 

per Mcf

 

17,729

 

Mmcf

 

Jan. 2013 - Dec. 2013

 

Natural Gas Collars

 

$3.35 Floor / $4.01 Ceiling

 

per Mcf

 

35,458

 

Mmcf

 

Jan. 2013 - Dec. 2013

 

Natural Gas Collars

 

$3.60 Floor / $4.17 Ceiling

 

per Mcf

 

17,729

 

Mmcf

 

Jan. 2013 - Dec. 2013

 

Crude Oil Swaps

 

$100.45

 

per Bbl

 

460

 

Mbbl

 

Oct. 2012 - Dec. 2012

 

Crude Oil Swaps

 

$101.90

 

per Bbl

 

1,095

 

Mbbl

 

Jan. 2013 - Dec. 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Basis Swaps

 

$(0.25

)

per Mcf

 

4,284

 

Mmcf

 

Oct. 2012 - Dec. 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In October 2012, the Company entered into additional natural gas collar arrangements with floor prices ranging from $3.76 to $3.86 per Mcf and ceiling prices ranging from $4.14 to $4.36 per Mcf covering 35,458 Mmcf of the Company’s anticipated natural gas production for 2013.

 

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, if any, 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.

 

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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, 2012

 

December 31, 2011

 

Derivatives Designated as Hedging Instruments

 

 

 

 

 

 

 

Commodity Contracts

 

Derivative Instruments (current assets)

 

$

62,532

 

$

177,389

 

Commodity Contracts

 

Accrued Liabilities

 

(2,941

)

(385

)

Commodity Contracts

 

Derivative Instruments (non-current assets)

 

4,379

 

21,249

 

Commodity Contracts

 

Other Liabilities

 

(5,868

)

 

 

 

 

 

58,102

 

198,253

 

Derivatives Not Designated as Hedging Instruments

 

 

 

 

 

 

 

Commodity Contracts

 

Derivative Instruments (current assets)

 

(809

)

(3,126

)

 

 

 

 

$

57,293

 

$

195,127

 

 

At September 30, 2012 and December 31, 2011, unrealized gains of $58.1 million ($35.6 million, net of tax) and $198.3 million ($121.4 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income / (Loss). Based upon estimates at September 30, 2012, the Company expects to reclassify $36.5 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.

 

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

 

 

 

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

 

Location of Gain (Loss)

 

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,

 

Reclassified from
Accumulated OCI into

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

(In thousands)

 

2012

 

2011

 

2012

 

2011

 

Income

 

2012

 

2011

 

2012

 

2011

 

Commodity Contracts

 

$

(39,805

)

$

98,143

 

$

49,299

 

$

159,030

 

Natural Gas Revenues

 

$

57,139

 

$

21,170

 

$

183,867

 

$

48,318

 

 

 

 

 

 

 

 

 

 

 

Crude Oil and Condensate Revenues

 

3,799

 

1,382

 

5,583

 

566

 

 

 

 

 

 

 

 

 

 

 

 

 

$

60,938

 

$

22,552

 

$

189,450

 

$

48,884

 

 

For the three and nine months ended September 30, 2012 and 2011, respectively, there was no ineffectiveness recorded in our Condensed Consolidated Statement of Operations related to our derivative instruments.

 

Derivatives Not Designated as

 

 

 

Three Months Ended

 

Nine Months Ended

 

Hedging Instruments 

 

Location of Gain (Loss) Recognized

 

September 30,

 

September 30,

 

(In thousands)

 

in Income on Derivative

 

2012

 

2011

 

2012

 

2011

 

Commodity Contracts

 

Natural Gas Revenues

 

$

(149

)

$

(64

)

$

(449

)

$

(950

)

 

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.

 

Certain 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.

 

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9. FAIR VALUE MEASUREMENTS

 

ASC 820, “Fair Value Measurements and Disclosures,” established a formal framework for measuring fair values of assets and liabilities in financial statements. ASC 820 also established a 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 13 of the Notes to the Consolidated Financial Statements in the 2011 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. As none of the Company’s non-financial assets and liabilities were impaired as of September 30, 2012 and 2011 and no other assets or liabilities were required to be measured at fair value on a non-recurring basis, additional disclosures are not provided.

 

Financial Assets and Liabilities

 

The Company’s 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:

 

(In thousands)

 

Quoted Prices in
Active Markets
for Identical
Assets (Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

September 30,
2012

 

Assets

 

 

 

 

 

 

 

 

 

Deferred Compensation Plan

 

$

11,462

 

$

 

$

 

$

11,462

 

Derivative Contracts

 

 

12,471

 

53,631

 

66,102

 

Total Assets

 

$

11,462

 

$

12,471

 

$

53,631

 

$

77,564

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Deferred Compensation Plan

 

$

22,668

 

$

 

$

 

$

22,668

 

Derivative Contracts

 

 

 

 

8,809

 

8,809

 

Total Liabilities

 

$

22,668

 

$

 

$

8,809

 

$

31,477

 

 

(In thousands)

 

Quoted Prices in
Active Markets
for Identical
Assets (Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

December 31,
2011

 

Assets

 

 

 

 

 

 

 

 

 

Deferred Compensation Plan

 

$

10,838

 

$

 

$

 

$

10,838

 

Derivative Contracts

 

 

 

195,512

 

195,512

 

Total Assets

 

$

10,838

 

$

 

$

195,512

 

$

206,350

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Deferred Compensation Plan

 

$

20,187

 

$

 

$

 

$

20,187

 

Derivative Contracts

 

 

 

385

 

385

 

Total Liabilities

 

$

20,187

 

$

 

$

385

 

$

20,572

 

 

The Company’s investments associated with its 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.

 

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The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using an income approach that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, basis differentials, 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 determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. 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 significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors.  An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

 

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)

 

2012

 

2011

 

2012

 

2011

 

Balance at beginning of period

 

$

129,213

 

$

48,415

 

$

195,127

 

$

14,746

 

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

 

 

 

 

 

 

 

 

 

Included in Earnings (1)

 

56,990

 

22,488

 

183,418

 

47,934

 

Included in Other Comprehensive Income

 

(85,466

)

75,591

 

(153,008

)

110,146

 

Settlements

 

(55,915

)

(22,552

)

(181,100

)

(48,884

)

Transfers In and/or Out of Level 3

 

 

 

385

 

 

Balance at end of period

 

$

44,822

 

$

123,942

 

$

44,822

 

$

123,942

 

 


(1)

Unrealized losses of $0.1 million and $0.1 million for the three months ended September 30, 2012 and 2011, respectively, and unrealized losses of $0.4 million and $1.0 million for the nine months ended September 30, 2012 and 2011, respectively, were 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 nine months ended September 30, 2012 and 2011.

 

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 fixed-rate notes and the credit facility is based on interest rates currently available to the Company.  The Company’s long-term debt is valued using an income approach and classified as Level 3 in the fair value hierarchy.

 

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, 2012

 

December 31, 2011

 

(In thousands)

 

Carrying
Amount

 

Estimated Fair
Value

 

Carrying
Amount

 

Estimated Fair
Value

 

Long-Term Debt

 

$

1,062,000

 

$

1,195,717

 

$

950,000

 

$

1,082,531

 

Current Maturities

 

(75,000

)

(78,095

)

 

 

Long-Term Debt, excluding Current Maturities

 

$

987,000

 

$

1,117,622

 

$

950,000

 

$

1,082,531

 

 

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10. ACCUMULATED COMPREHENSIVE INCOME / (LOSS)

 

Changes in the components of Accumulated Other Comprehensive Income / (Loss), net of taxes, for the nine months ended September 30, 2012 were as follows:

 

(In thousands)

 

Net Gains /
(Losses) on Cash
Flow Hedges

 

Defined Benefit
Pension and
Postretirement
Plans

 

Total

 

Balance at December 31, 2011

 

$

121,358

 

$

(16,811

)

$

104,547

 

Net change in unrealized gain on cash flow hedges, net of taxes of $54,299

 

(85,852

)

 

(85,852

)

Net change in defined benefit pension and postretirement plans, net of taxes of $(5,433)

 

 

8,563

 

8,563

 

Balance at September 30, 2012

 

$

35,506

 

$

(8,248

)

$

27,258

 

 

11. 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)

 

2012

 

2011

 

2012

 

2011

 

Qualified and Non-Qualified Pension Plans

 

 

 

 

 

 

 

 

 

Interest Cost

 

$

 

$

650

 

$

922

 

$

2,251

 

Expected Return on Plan Assets

 

 

(945

)

(1,748

)

(3,265

)

Settlement

 

 

2,446

 

7,111

 

2,446

 

Amortization of Prior Service Cost

 

 

228

 

221

 

862

 

Amortization of Net Loss

 

 

2,373

 

13,083

 

8,498

 

Net Periodic Pension Cost

 

$

 

$

4,752

 

$

19,589

 

$

10,792

 

 

 

 

 

 

 

 

 

 

 

Postretirement Benefits

 

 

 

 

 

 

 

 

 

Current Period Service Cost

 

$

234

 

$

335

 

$

1,280

 

$

1,004

 

Interest Cost

 

351

 

467

 

1,187

 

1,402

 

Amortization of Net Loss

 

132

 

140

 

692

 

422

 

Amortization of Net Obligation at Transition

 

 

158

 

 

474

 

Total Postretirement Benefit Cost

 

$

717

 

$

1,100

 

$

3,159

 

$

3,302

 

 

Termination and Amendment of Qualified Pension Plan

 

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 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.

 

On March 14, 2012, the Internal Revenue Service provided the Company with a favorable determination letter for the termination of the Company’s qualified pension plan. In June and July 2012, the Company made final contributions of $9.6 million and $3.6 million, respectively, to fund the liquidation of the trust under the qualified pension plan. As of September 30, 2012, the benefit obligations associated with the qualified pension plan were fully satisfied.

 

For further information regarding termination and amendment of the Company’s pension plans, refer to Note 5 of the Notes to the Consolidated Financial Statements in the 2011 Form 10-K.

 

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12. STOCK-BASED COMPENSATION

 

Stock-based compensation expense during the first nine months of 2012 and 2011 was $23.4 million and $29.3 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 2012 and 2011 was $10.4 million and $10.0 million, respectively.

 

Restricted Stock Awards

 

During the first nine months of 2012, 4,350 restricted stock awards were granted with a weighted-average grant date per share value of $32.18. 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 6.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

 

Restricted Stock Units

 

During the first nine months of 2012, 38,304 restricted stock units were granted to non-employee directors of the Company with a grant date per share value of $36.55. 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 2012, 120,442 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 $35.18 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

 

$16.31

 

 

 

 

 

Assumptions

 

 

 

Stock Price Volatility

 

55.3

%

Risk Free Rate of Return

 

0.9

%

Expected Dividend Yield

 

0.3

%

Expected Term (in years)

 

5.0

 

 

Performance Share Awards

 

During the first nine months of 2012, three types of performance share awards were granted to employees for a total of 518,602 performance shares, which included 401,141 performance share awards based on performance conditions measured against the Company’s internal performance metrics and 117,461 performance share awards based on market conditions. The Company used an annual forfeiture rate assumption ranging from 0% to 6% for purposes of recognizing stock-based compensation expense for all performance share awards. The performance period for the awards granted in 2012 commenced on January 1, 2012 and ends on December 31, 2014.  Refer to Note 11 of the Notes to the Consolidated Financial Statements in the 2011 Form 10-K for further description of the various types of performance share awards.

 

Awards Based on Performance Conditions. The performance awards based on internal metrics had a grant date per share value of $35.18, which is based on the average of the high and low stock price on the grant date. These awards represent the right to receive up to 100% of the award in shares of common stock.  Of the 401,141 performance awards based on internal metrics, 117,461 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 283,680 performance 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. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the

 

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performance period. These performance criteria are based on the Company’s average production, average finding costs and average reserve replacement over the three-year performance period.

 

Based on the Company’s probability assessment at September 30, 2012, it is considered probable that criteria for these awards will be met.

 

Awards Based on Market Conditions. The 117,461 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. These performance shares have both an equity and liability component. The equity portion of the 2012 awards was valued on the grant date (February 16, 2012) and was not marked to market. The liability portion of the awards was valued as of September 30, 2012 on a mark-to-market basis.

 

The following assumptions were used to value the equity and liability components of the Company’s performance share awards based on market conditions using a Monte Carlo model:

 

 

 

Grant Date

 

September 30, 2012

 

Value per Share

 

$28.31

 

$29.39 - $44.56

 

Assumptions:

 

 

 

 

 

Stock Price Volatility

 

46.7

%

36.2% - 50.7%

 

Risk Free Rate of Return

 

0.4

%

0.1% - 0.3%

 

Expected Dividend Yield

 

0.2

%

0.2%

 

 

Supplemental Employee Incentive Plan

 

On May 1, 2012, the Company’s Board of Directors adopted a new Supplemental Employee Incentive Plan (“Plan”) to replace the previously adopted supplemental employee incentive plan that expired on June 30, 2012.  There were no amounts paid under the expired plan. The Plan commenced on July 1, 2012 and is intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time, non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price. The Plan is accounted for as a liability award under ASC 718, “Compensation — Stock Compensation.” The Company recognized stock-based compensation expense / (benefit) of $1.6 million and ($0.1) million for the three and nine months ended September 30, 2012, respectively, which is included in General and Administrative expense in the Condensed Consolidated Statement of Operations.

 

The Plan provides for a payout if, for any 20 trading days out of any 60 consecutive trading days, the closing price per share of the Company’s common stock equals or exceeds the price goal of $50 per share by June 30, 2014 (interim trigger date) or $75 per share by June 30, 2016 (final trigger date). Under the Plan, each eligible employee may receive (upon approval by the Compensation Committee) a distribution of 20% of base salary if the interim trigger is met or 50% of base salary if the final trigger is met (or an incremental 30% of base salary if the Company paid interim distributions upon achievement of the interim trigger).

 

In accordance with the Plan, in the event the interim or final trigger date occurs between July 1, 2012 and December 31, 2014, 25% of the total distribution will be paid immediately and the remaining 75% will be deferred and paid at a future date as described in the Plan.  For final trigger dates occurring between January 1, 2015 and June 30, 2016, total distribution will be paid immediately.

 

The Compensation Committee can increase any of the payments as applied to any employee if desired. Any deferred portion will only be paid if the participant is employed by the Company, or has terminated employment by reason of retirement, death or disability (as provided in the Plan). Payments are subject to certain other restrictions contained in the Plan.

 

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Table of Contents

 

13. ASSET RETIREMENT OBLIGATION

 

Activity related to the Company’s asset retirement obligation is as follows:

 

(In thousands)

 

 

 

Balance at December 31, 2011

 

$

60,142

 

Liabilities incurred

 

1,731

 

Liabilities settled

 

(1,050

)

Accretion expense

 

2,283

 

Change in Estimate

 

(37

)

Balance at September 30, 2012

 

$

63,069

 

 

14. INCREASE IN AUTHORIZED SHARES

 

In May 2012, the stockholders of the Company approved an increase in the authorized number of shares of common stock from 240 million to 480 million shares.

 

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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, 2012, and the related condensed consolidated statements of operations and comprehensive income for the three and nine month periods ended September 30, 2012 and 2011, and the condensed consolidated statement of cash flows for the nine month periods ended September 30, 2012 and 2011. 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, 2011, 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, 2012, 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, 2011, 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 26, 2012

 

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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, 2012 and 2011 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, 2011 (Form 10-K).

 

On January 3, 2012, the Board of Directors declared a 2-for-1 split of our common stock in the form of a stock dividend. The stock dividend was distributed on January 25, 2012 to shareholders of record as of January 17, 2012. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of our common stock.

 

Overview

 

On an equivalent basis, our production for the nine months ended September 30, 2012 increased by 42% compared to the nine months ended September 30, 2011. For the nine months ended September 30, 2012, we produced 188.9 Bcfe compared to 132.7 Bcfe for the nine months ended September 30, 2011. Natural gas production was 178.4 Bcf and crude oil/condensate/NGL production was 1,760 Mbbls for the first nine months of 2012. Natural gas production increased by 40% when compared to the first nine months of 2011, which had production of 127.2 Bcf. This increase was primarily a result of increased production in the Marcellus shale associated with our drilling program and infrastructure installation and upgrades in Susquehanna County, Pennsylvania. Partially offsetting the natural gas production increase in the Marcellus shale were decreases in natural gas production in east Texas due to reduced drilling activity and normal production declines along with the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011. Crude oil/condensate/NGL production increased by 91%, to 1,760 Mbbls, when compared to the first nine months of 2011, which had production of 920 Mbbls, primarily due to our focus on liquids projects associated with our Eagle Ford shale drilling program in south Texas and the Marmaton oil play in Oklahoma.

 

Our average realized natural gas price for the first nine months of 2012 was $3.57 per Mcf, 23% lower than the $4.64 per Mcf price realized in the first nine months of 2011. Our average realized crude oil price for the first nine months of 2012 was $100.30 per Bbl, 12% higher than the $89.69 per Bbl price realized in the first nine months of 2011. 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 capital program, production volumes or future revenues.

 

Operating revenues for the nine months ended September 30, 2012 increased by $122.8 million, or 17%, from the nine months ended September 30, 2011. Natural gas revenues, excluding unrealized gains/losses from the change in fair value of our derivatives not designated as hedges, increased by $50.3 million, or 9%, for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 as the increase in natural gas production more than offset the lower realized natural gas prices. Crude oil and condensate revenues increased by $85.5 million, or 107%, for the first nine months of 2012 as compared to the first nine months of 2011, due to increased crude oil production and realized crude oil prices. Brokered natural gas revenues decreased by $15.1 million, or 39%, due to a lower sales price and 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 2012, we expect to spend approximately $900 million to $950 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 above previously budgeted amounts. We believe our existing cash on hand, operating cash flows, borrowings under our credit facility, if required, and proceeds from the sale of assets will be more than sufficient to fund our capital and exploration spending in the current year. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly. For the nine months ended September 30, 2012, we invested approximately $712.9 million in our exploration and development efforts.

 

During the first nine months of 2012, we drilled 104 gross wells (94 development, four exploratory and six extension wells) with a success rate of 97% compared to 85 gross wells (73 development, five exploratory and seven extension wells) with a success rate of 99% for the comparable period of the prior year. For the full year of 2012, we plan to drill approximately 150 to 170 gross wells.

 

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Table of Contents

 

Our 2012 strategy will remain consistent with 2011. We remain focused on pursuing drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. For 2012, we have allocated our planned program for capital and exploration expenditures primarily to the Marcellus shale in northeast Pennsylvania, the Eagle Ford oil shale in south Texas, including a portion toward the Pearsall shale (below the Eagle Ford oil shale), and the Marmaton oil play in Oklahoma. We believe these strategies are appropriate for our portfolio of projects and the current commodity pricing environment and will continue to add shareholder value over the long-term.

 

In June 2012, we sold a 35% non-operated working interest associated with certain of our Pearsall shale undeveloped leaseholds in south Texas. For further information, please refer to “Divestitures” under Note 2 in the Notes to the Condensed Consolidated Financial Statements.

 

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, 2012 were funds generated from the sale of natural gas and crude oil production (including realizations from our derivative instruments), proceeds from the sale of assets and net borrowings under our credit facility. These cash flows were primarily used to fund our capital and exploration expenditures, contributions to our pension plan and payment of dividends. See below for additional discussion and analysis of cash flow.

 

Operating cash flow fluctuations are substantially driven by commodity prices, changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been and continue to be 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. 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)

 

2012

 

2011

 

Cash Flows Provided by Operating Activities

 

$

455,112

 

$

375,366

 

Cash Flows Used in Investing Activities

 

(540,946

)

(586,878

)

Cash Flows Provided by Financing Activities

 

93,424

 

218,491

 

Net Increase / (Decrease) in Cash and Cash Equivalents

 

$

7,590

 

$

6,979

 

 

Operating Activities.  Net cash provided by operating activities in the first nine months of 2012 increased by $79.7 million over the first nine months of 2011. This increase was primarily due to favorable changes in working capital and long-term assets and liabilities and higher operating revenues partially offset by higher operating expenses (excluding non-cash expenses). The increase in operating revenues was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices. Equivalent production volumes increased by 42% for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011 as a result of higher natural gas and crude oil production. Average realized crude oil prices increased by 12% compared to the same period while average realized natural gas prices decreased by 23% for the first nine months of 2012 compared to the first nine months of 2011.

 

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.

 

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Table of Contents

 

Investing Activities. Cash flows used in investing activities decreased by $45.9 million for the first nine months of 2012 compared to the first nine months of 2011. The decrease was primarily due an increase of $50.6 million in proceeds from sale of assets, partially offset by $4.5 million of capital contributions associated with our equity method investment in Constitution Pipeline Company, LLC (Constitution).

 

Financing Activities. Cash flows provided by financing activities decreased by $125.1 million from the first nine months of 2011 to the first nine months of 2012. This decrease was primarily due to $118.0 million lower net borrowings ($50.0 million decrease in borrowings and $68.0 million increase in repayments of debt), $4.0 million higher debt issuance costs associated with our amended credit facility and $3.2 million higher dividend payments.

 

In May 2012, we amended our revolving credit facility to adjust the margins associated with borrowings under the facility and extend the maturity date from September 2015 to May 2017. The credit facility, as amended, provides for an available credit line of $900 million and contains a $500 million accordion feature whereby we may increase the available credit line to $1.4 billion, if one or more of the existing banks or new banks agree to provide such increased commitment amount. As of September 30, 2012, the borrowing base under our amended credit facility was $1.7 billion.

 

At September 30, 2012, we had $300.0 million of borrowings outstanding under the amended credit facility at a weighted-average interest rate of 2.3% and $599.0 million available for future borrowings.

 

We were in compliance in all material respects with our debt covenants as of September 30, 2012.

 

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 internally generated cash flow from operations, existing cash on hand, proceeds from the sale of assets and availability under our revolving credit facility, if required, 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,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

Debt (1)

 

$

1,062,000

 

$

950,000

 

Stockholders’ Equity

 

2,100,287

 

2,104,768

 

Total Capitalization

 

$

3,162,287

 

$

3,054,768

 

 

 

 

 

 

 

Debt to Capitalization

 

34

%

31

%

 

 

 

 

 

 

Cash and Cash Equivalents

 

$

37,501

 

$

29,911

 

 


(1) Includes $75.0 million of current portion of long-term debt at September 30, 2012 and $300.0 million and $188.0 million of borrowings outstanding under our revolving credit facility at September 30, 2012 and December 31, 2011, respectively.

 

During the nine months ended September 30, 2012, we paid dividends of $12.6 million ($0.06 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, if necessary, borrowings under our revolving credit facility. We budget these capital expenditures based on our current estimate of future commodity prices and projected cash flows for the year.

 

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Table of Contents

 

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

 

 

 

Nine Months Ended

 

 

 

September 30,

 

(In thousands)

 

2012

 

2011

 

Capital Expenditures

 

 

 

 

 

Drilling and Facilities

 

$

602,820

 

$

561,017

 

Leasehold Acquisitions

 

74,426

 

60,922

 

Pipeline and Gathering

 

(365

)

7,218

 

Other

 

6,457

 

6,452

 

 

 

683,338

 

635,609

 

Exploration Expense

 

29,548

 

31,090

 

Total

 

$

712,886

 

$

666,699

 

 

For the full year of 2012, we plan to drill approximately 150 to 170 gross wells. Our 2012 drilling program includes between $900 million to $950 million in total planned 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 above previously budgeted amounts. See “Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our 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” under Note 7 in the Notes to the Condensed Consolidated Financial Statements for changes in our commitments for the first nine months of 2012. There have been no other material changes to our contractual obligations described under “Gas Transportation Agreements”, “Drilling Rig Commitments”, “Hydraulic Fracturing Services Commitments” and “Lease Commitments” as disclosed in Note 7 in the Notes to Consolidated Financial Statements included in our 2011 Form 10-K.

 

In February 2012, we entered into a Precedent Agreement with Constitution, at that time a wholly owned subsidiary of Williams Partners L.P., to develop and construct a 120 mile large diameter pipeline to transport our production in northeast Pennsylvania to both the New England and New York markets. In April 2012, we entered into an Amended and Restated Limited Liability Company Agreement with Constitution. Refer to Note 5 in the Notes to Condensed Consolidated Financial Statements for further details.

 

Critical Accounting Policies and Estimates

 

Our discussion and analysis of our financial condition and results of operations are based upon our 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 2011 Form 10-K for further discussion of our critical accounting policies.

 

Recent 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 this update 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. This update 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 are effective for interim and annual periods beginning after December 15, 2011 and are to be applied prospectively. This update did not have any 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.” ASU No. 2011-05 was amended in December 2011 by ASU No. 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU No. 2011-05.”  ASU No. 2011-12 defers only those changes in ASU No. 2011-05 that relate to the presentation of reclassification adjustments. All other requirements in ASU No. 2011-05 are not affected by ASU No. 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. ASU No. 2011-05 and 2011-12 are effective for fiscal years (including interim

 

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periods) beginning after December 15, 2011. We elected to present two separate but consecutive financial statements. These updates did not have any impact on our consolidated financial position, results of operations or cash flows.

 

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. This guidance will primarily impact our disclosures associated with our commodity derivatives. We do not expect this guidance to have any impact on our consolidated financial position, results of operations or cash flows.

 

Results of Operations

 

Third Quarters of 2012 and 2011 Compared

 

We reported net income in the third quarter of 2012 of $36.6 million, or $0.17 per share, compared to $28.5 million, or $0.14 per share in the third quarter of 2011. The increase in net income was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices and higher operating costs.

 

Revenue, Price and Volume Variances

 

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

 

 

 

Three Months Ended September 30,

 

Variance

 

Revenue Variances (In thousands)

 

2012

 

2011

 

Amount

 

Percent

 

Natural Gas (1) 

 

$

232,045

 

$

218,585

 

$

13,460

 

6%

 

Crude Oil and Condensate

 

57,870

 

33,158

 

24,712

 

75%

 

Brokered Natural Gas

 

5,238

 

9,467

 

(4,229

)

(45)%

 

Other

 

1,870

 

971

 

899

 

93%

 

 


(1) Natural Gas Revenues exclude the unrealized loss of $0.1 million and $0.1 million from the change in fair value of our derivatives not designated as hedges in 2012 and 2011, respectively.

 

 

 

Three Months Ended September 30,

 

Variance

 

Increase
(Decrease)

 

 

 

2012

 

2011

 

Amount

 

Percent

 

(In thousands)

 

Price Variances

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (1)

 

$

3.68

 

$

4.58

 

$

(0.90

)

(20)%

 

$

(55,170

)

Crude Oil and Condensate (2)

 

$

101.34

 

$

86.89

 

$

14.45

 

17%

 

8,283

 

Total

 

 

 

 

 

 

 

 

 

$

(46,887

)

Volume Variances

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Mmcf)

 

62,692

 

47,707

 

14,985

 

31%

 

$

68,630

 

Crude Oil and Condensate (Mbbl)

 

571

 

382

 

189

 

49%

 

16,429

 

Total

 

 

 

 

 

 

 

 

 

$

85,059

 

 


(1) These prices include the realized impact of derivative instrument settlements, which increased the price by $0.91 per Mcf in 2012 and $0.44 per Mcf in 2011.

(2) These prices include the realized impact of derivative instrument settlements, which increased the price by $6.65 per Bbl in 2012 and $3.62 per Bbl in 2011.

 

Natural Gas Revenues

 

The increase in natural gas revenues of $13.5 million, excluding the impact of unrealized losses, is due to increased production during the third quarter of 2012, partially offset by lower realized natural gas prices. The increase in production was primarily a result of higher production in the Marcellus shale associated with our drilling program and infrastructure installation and upgrades in Susquehanna County, Pennsylvania. Partially offsetting the increase in natural gas production in the Marcellus shale were decreases in natural gas production in east Texas due to reduced drilling activity and normal production declines along with the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011.

 

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Crude Oil and Condensate Revenues

 

The increase in crude oil and condensate revenues of $24.7 million is primarily due to our focus on liquids projects associated with our Eagle Ford shale drilling program in south Texas and the Marmaton oil play in Oklahoma and higher realized oil prices.

 

Brokered Natural Gas Revenue and Cost

 

 

 

 

 

 

 

 

 

 

 

Price and

 

 

 

Three Months Ended

 

 

 

 

 

Volume

 

 

 

September 30,

 

Variance

 

Variances

 

 

 

2012

 

2011

 

Amount

 

Percent

 

(In thousands)

 

Brokered Natural Gas Sales

 

 

 

 

 

 

 

 

 

 

 

Sales Price ($/Mcf)

 

$

3.28

 

$

4.99

 

$

(1.71

)

(34)%

 

$

(2,712

)

Volume Brokered (Mmcf)

 

x

1,595

 

x

1,899

 

(304

)

(16)%

 

(1,517

)

Brokered Natural Gas Revenues (In thousands)

 

$

5,238

 

$

9,467

 

 

 

 

 

$

(4,229

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Purchases

 

 

 

 

 

 

 

 

 

 

 

Purchase Price ($/Mcf)

 

$

2.67

 

$

4.32

 

$

(1.65

)

(38)%

 

$

2,633

 

Volume Brokered (Mmcf)