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~~June 30, ~~2012~~2013

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~~July 22, ~~2012,~~2013, there were ~~210,242,354~~210,764,304 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~~June 30, ~~2012~~2013 and December 31, ~~2011~~2012	3

Condensed Consolidated Statement of Operations for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2012~~2013 and ~~2011~~2012	4

Condensed Consolidated Statement of Comprehensive Income for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2012~~2013 and ~~2011~~2012	5

Condensed Consolidated Statement of Cash Flows for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2012~~2013 and ~~2011~~2012	6

Notes to the Condensed Consolidated Financial Statements	7

Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information	2118

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2219

Item 3. Quantitative and Qualitative Disclosures about Market Risk	3228

Item 4. Controls and Procedures	3529

Part II. Other Information

Item 1. Legal Proceedings	3530

Item 1A. Risk Factors	3530

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	3530

Item 5. Other Information	30

Item 6. Exhibits	3631

Signatures	3732

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

	June 30,			December 31,
(In thousands, except share amounts)	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	47,277		$	30,736
Accounts receivable, net	204,970			172,419
Income taxes receivable	7,273			—
Inventories	18,276			14,173
Deferred income taxes	50,864			—
Derivative instruments	69,644			50,824
Other current assets	4,889			2,158
Total current assets	403,193			270,310
Properties and equipment, net (Successful efforts method)	4,558,207			4,310,977
Derivative instruments	17,963			—
Other assets	38,573			35,026
	$	5,017,936		$	4,616,313

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	356,851		$	312,480
Current portion of long-term debt	75,000			75,000
Accrued liabilities	58,571			49,789
Income taxes payable	3,969			1,667
Deferred income taxes	—			5,203
Total current liabilities	494,391			444,139
Postretirement benefits	40,313			38,864
Long-term debt	1,067,000			1,012,000
Deferred income taxes	1,015,493			882,672
Asset retirement obligation	68,390			67,016
Other liabilities	46,108			40,175
Total liabilities	2,731,695			2,484,866

Commitments and contingencies

Stockholders’ equity
Common stock:
Authorized — 480,000,000 shares of $0.10 par value in 2013 and 2012, respectively
Issued—210,758,335 shares and 210,429,731 shares in 2013 and 2012, respectively	21,076			21,043
Additional paid-in capital	725,156			716,609
Retained earnings	1,496,795			1,373,264
Accumulated other comprehensive income / (loss)	46,563			23,880
Less treasury stock, at cost:
404,400 shares in 2013 and 2012, respectively	(3,349		)	(3,349		)
Total stockholders’ equity	2,286,241			2,131,447
	$	5,017,936		$	4,616,313

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

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

Three Months Ended
June 30,

Six Months Ended
June 30,

(In thousands, except per share amounts)

2013

2012

2013

2012

OPERATING REVENUES

Natural gas

$
368,391

$
201,051

$
662,184

$
407,833

Crude oil and condensate

70,226

57,466

135,881

107,447

Brokered natural gas

8,244

5,149

19,137

18,593

Other

2,819

1,991

5,763

3,920

449,680

265,657

822,965

537,793

OPERATING EXPENSES

Direct operations

36,978

29,306

68,475

56,626

Transportation and gathering

52,648

33,139

98,869

63,397

Brokered natural gas cost

6,704

4,250

15,093

16,122

Taxes other than income

11,364

10,854

23,051

29,437

Exploration

4,529

16,244

8,553

20,245

Depreciation, depletion and amortization

151,389

114,616

300,042

224,973

General and administrative

21,608

46,872

57,312

69,421

285,220

255,281

571,395

480,221

Gain / (loss) on sale of assets

276

67,703

180

67,168

INCOME FROM OPERATIONS

164,736

78,079

251,750

124,740

Interest expense and other

16,701

18,495

32,956

35,412

Income before income taxes

148,035

59,584

218,794

89,328

Income tax expense

58,921

23,647

86,856

35,073

NET INCOME

$
89,114

$
35,937

$
131,938

$
54,255

Earnings per share

Basic

$
0.42

$
0.17

$
0.63

$
0.26

Diluted

$
0.42

$
0.17

$
0.62

$
0.26

Weighted-average shares outstanding

Basic

210,349

209,512

210,250

209,320

Diluted

211,745

211,158

211,492

210,974

Dividends per common share

$
0.02

$
0.02

$
0.04

$
0.04

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

Three Months Ended

Six Months Ended

June 30,

June 30,

(In thousands)

2013

2012

2013

2012

Net income

$
89,114

$
35,937

$
131,938

$
54,255

Other comprehensive income / (loss), net of taxes:

Reclassification adjustment for settled hedge contracts (1)

(1,105
)
(44,579
)
(10,430
)
(78,649
)
Changes in fair value of hedge contracts (2)

69,839

11,246

32,864

54,451

Pension and postretirement benefits:

Amortization of prior service cost (3)

—

67

—

135

Amortization of net loss (4)

124

4,174

249

8,349

Total other comprehensive income / (loss)

68,858

(29,092
)
22,683

(15,714
)

Comprehensive income / (loss)

$
157,972

$
6,845

$
154,621

$
38,541

(1)Net of income taxes of $717 and $28,263 for the three months ended June 30, 2013 and 2012, respectively, and $6,762 and $49,863 for the six months ended June 30, 2013 and 2012, respectively.
(2)        Net of income taxes of $(45,274) and $(7,130) for the three months ended June 30, 2013 and 2012, respectively, and $(21,303) and $(34,653) for the six months ended June 30, 2013 and 2012, respectively.
(3)        Net of income taxes of $0 and $(43) for the three months ended June 30, 2013 and 2012, respectively, and $0 and $(86) for the six months ended June 30, 2013 and 2012, respectively.
(4)        Net of income taxes of $(81) and $(2,647) for the three months ended June 30, 2013 and 2012, respectively, and $(161) and $(5,294) for the six months ended June 30, 2013 and 2012, respectively.
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

Six Months Ended

June 30,

(In thousands)

2013

2012

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

$
131,938

$
54,255

Adjustments to reconcile net income to cash provided by operating activities:

Depreciation, depletion and amortization

300,042

224,973

Deferred income tax expense

69,662

27,073

(Gain) / loss on sale of assets

(180
)
(67,168
)
Exploration expense

806

10,925

Unrealized (gain) / loss on derivative instruments

—

300

Amortization of debt issuance costs

1,842

3,334

Stock-based compensation, pension and other

27,355

26,987

Changes in assets and liabilities:

Accounts receivable, net

(32,551
)
25,214

Inventories

(4,103
)
9,293

Other current assets

(2,733
)
(3,691
)
Accounts payable and accrued liabilities

9,661

(28,675
)
Income taxes

(4,971
)
4,775

Other assets and liabilities

547

3,547

Stock-based compensation tax benefit

(7,348
)
—

Net cash provided by operating activities

489,967

291,142

CASH FLOWS FROM INVESTING ACTIVITIES

Capital expenditures

(524,056
)
(411,327
)
Proceeds from sale of assets

906

132,715

Investment in equity method investment

(4,250
)
(2,088
)
Net cash used in investing activities

(527,400
)
(280,700
)

CASH FLOWS FROM FINANCING ACTIVITIES

Borrowings from debt

325,000

170,000

Repayments of debt

(270,000
)
(148,000
)
Stock-based compensation tax benefit

7,348

—

Dividends paid

(8,407
)
(8,368
)
Capitalized debt issuance costs

—

(5,005
)
Other

33

(339
)
Net cash provided by financing activities

53,974

8,288

Net (decrease) / increase in cash and cash equivalents

16,541

18,730

Cash and cash equivalents, beginning of period

30,736

29,911

Cash and cash equivalents, end of period

$
47,277

$
48,641

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~~2012 (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~~June 30, ~~2012~~2013 and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2012~~2013 and ~~2011,~~2012, 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~~July 26, ~~2012~~2013 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,~~Effective January 1, 2013, the ~~Financial Accounting Standards Board (FASB) issued~~Company adopted the amended disclosure requirements prescribed in 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” and ASU No. 2013-01, “Clarifying the Scope of 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~~impacted the ~~Company’s~~ disclosures associated with ~~its~~the Company’s commodity ~~derivatives. The Company does~~derivatives (Note 7) and did not ~~expect this guidance to have any~~ impact on its consolidated financial position, results of operations or cash flows.

7

~~Table~~Effective January 1, 2013, the Company adopted the amended disclosure requirements prescribed in ASU No. 2013-02, “Reporting of ~~Contents~~Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This guidance impacted the Company’s disclosures associated with items reclassified from accumulated other comprehensive income / (loss) (Note 9) and did not impact its consolidated financial position, results of operations or cash flows.

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

June 30,

December 31,

(In thousands)

2013

2012

Proved oil and gas properties

$
6,245,196

$
5,724,940

Unproved oil and gas properties

458,047

467,483

Gathering and pipeline systems

240,062

239,656

Land, building and other equipment

90,690

86,137

7,033,995

6,518,216

Accumulated depreciation, depletion and amortization

(2,475,788
)
(2,207,239
)

$
4,558,207

$
4,310,977

At ~~September~~June 30, ~~2012,~~2013, 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.

7

Table of Contents
Divestitures

In June 2012, the Company sold a 35% non-operated working interest associated with certain of its Pearsall ~~shale~~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 drilling and completion carry under the ~~first nine months~~joint development agreement will terminate two years after the closing of ~~2011,~~the transaction; however, based on the Company’s current drilling and completion activities in the Pearsall Shale, the Company ~~entered into two participation agreements with third parties related to certain of its Haynesville and Bossier shale leaseholds in east Texas. Under~~expects that 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~~carry will be fully satisfied in the ~~related leaseholds over a multi-year period in exchange for a 75% working interest in the leaseholds. During the first nine months~~second half 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~~2013.

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

June 30,

December 31,

(In thousands)

2013

2012

Accounts receivable, net

Trade accounts

$
193,695

$
165,070

Joint interest accounts

6,694

5,659

Other accounts

6,260

2,817

206,649

173,546

Allowance for doubtful accounts

(1,679
)
(1,127
)

$
204,970

$
172,419

Inventories

Natural gas in storage

$
8,629

$
7,494

Tubular goods and well equipment

9,274

6,392

Other accounts

373

287

$
18,276

$
14,173

Other current assets

Prepaid balances and other

4,889

2,158

$
4,889

$
2,158

Other assets

Deferred compensation plan

$
11,416

$
10,608

Debt issuance cost

15,578

17,420

Equity method investment

11,501

6,915

Other accounts

78

83

$
38,573

$
35,026

Accounts payable

Trade accounts

$
19,134

$
14,037

Natural gas purchases

6,335

4,892

Royalty and other owners

81,743

66,321

Accrued capital costs

184,891

164,862

Taxes other than income

6,947

10,224

Drilling advances

51,026

44,203

Producer gas imbalances

1,368

1,602

Other accounts

5,407

6,339

$
356,851

$
312,480

Accrued liabilities

Employee benefits

$
20,779

$
16,011

Postretirement benefits

1,304

1,304

Taxes other than income

11,374

8,735

Interest payable

22,128

22,329

Derivative instruments

—

192

Other accounts

2,986

1,218

$
58,571

$
49,789

Other liabilities

Deferred compensation plan

$
30,385

$
23,893

Other accounts

15,723

16,282

$
46,108

$
40,175

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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 thousands)

June 30,
2013

December 31,
2012

Total 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

380,000

325,000

Current maturities

7.33% weighted-average fixed rate notes

(75,000
)
(75,000
)
Long-term debt, excluding current maturities

$
1,067,000

$
1,012,000

~~In May 2012,~~Effective April 17, 2013, the ~~Company amended its~~lenders under the Company’s revolving credit facility approved an increase in the Company’s borrowing base from $1.7 billion to ~~adjust~~$2.3 billion as part of the ~~margins associated with borrowings~~annual redetermination 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 moreterms of the ~~existing or new banks agree to provide such increased amount. Interest rates~~credit facility. The Company’s commitments 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~~$900.0 million remained unchanged. At June 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,~~2013, the Company had ~~$300.0~~$380.0 million of borrowings outstanding under ~~the amended~~its revolving credit facility at a weighted-average interest rate of ~~2.3%~~2.0% and ~~$599.0~~$519.0 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
10

~~Table of Contents~~
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

—

Three Months Ended

Six Months Ended

June 30,

June 30,

(In thousands)

2013

2012

2013

2012

Weighted-average shares - basic

210,349

209,512

210,250

209,320

Dilution effect of stock appreciation rights and stock awards at end of period

1,396

1,646

1,242

1,654

Weighted-average shares - diluted

211,745

211,158

211,492

210,974

Weighted-average stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect

1

122

287

179

7.6. COMMITMENTS AND CONTINGENCIES

Contractual Obligations
The Company has various contractual obligations in the normal course of its operations. Except for certain amended transportation agreements and two new drilling rig commitments described below, there have been no material changes to our contractual obligations described under “Transportation Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 8 in the Notes to Consolidated Financial Statements included in the Form 10-K.

Transportation Agreements

During the ~~first nine months~~second quarter of ~~2012,~~2013, the Company ~~entered into a liquids~~amended certain natural gas 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~~agreements associated with the Company’s production in Pennsylvania. This amendment increased the Company’s future aggregate obligations under its transportation agreements ~~please refer~~by approximately $25.3 million compared to those amounts in disclosed in Note ~~7 of~~8 in the Notes to ~~the~~ Consolidated Financial Statements included 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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Table of Contents

~~appealed~~Drilling Rig Commitments

During the ~~ruling~~second quarter of 2013, the Company entered into two drilling rig commitments for its capital program in the Marcellus Shale that are expected to commence in the third and fourth quarters of 2013 and have initial terms of two and three years, respectively. There have been no material changes to the ~~Pennsylvania Superior Court, where~~Company’s existing drilling rig commitments previously disclosed in Note 8 in the ~~ruling~~Notes to the Consolidated Financial Statements included in ~~favor~~the Form 10-K. The future minimum commitments under all of the ~~Company was reversed~~Company’s drilling rig commitments as of June 30, 2013 are approximately $7.0 million in 2013, $14.9 million in 2014, $6.8 million in 2015 and ~~remanded to the trial court~~$4.4 million 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.2016.

~~Other~~Legal Matters

The Company is ~~also~~ a defendant in various ~~other~~ legal proceedings arising in the normal course of business. All known liabilities are accrued when management determines they are probable based on ~~management’s~~its 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. During 2010 and 2011, the Company paid a total of $1.3 million in settlement of fines and penalties sought or claimed by the PaDEP related to this matter. 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,~~households pursuant to prior consent orders with the PaDEP. 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. All appellants have accepted their portion of the $2.2 million that was placed into escrow in 2011 for their benefit and on October 18, 2012 had dismissed their appeal to the PEHB. Subsequent to the withdrawal of the appeals, the PEHB allowed three groups of appellants to reinstate their appeal. It is expected that the PEHB will hold a hearing with respect to the appellants’ appeal in the second half of 2013.

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

~~Table of Contents~~

~~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.

8.7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations onrelated to its 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 where such derivatives do not ~~subjecting~~subject 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.

Table of Contents

As of ~~September~~June 30, ~~2012,~~2013, 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

				Collars
				Floor				Ceiling				Swaps
Type of Contract	Volume		Contract Period	Range *(1)*		Weighted Average *(1)*		Range *(1)*		Weighted Average *(1)*		(Weighted Average) *(1)*

Natural gas collars	8.9	Bcf	Jul. 2013 - Dec. 2013	$	—	$	5.15	$	6.18-$6.23	$	6.20
Natural gas collars	109.0	Bcf	Jul. 2013 - Dec. 2013	$	3.09-$4.37	$	3.63	$	3.98-$5.02	$	4.27
Natural gas collars	53.3	Bcf	Jul. 2013 - Dec. 2014	$	3.60-$3.96	$	3.78	$	4.55-$4.59	$	4.57
Natural gas collars	124.1	Bcf	Jan. 2014 - Dec. 2014	$	3.86-$4.37	$	4.19	$	4.63-$4.80	$	4.70
Crude oil swaps	552	Mbbl	Jul. 2013 - Dec. 2013									$	101.90

~~In October 2012, the Company entered into additional natural~~(1)Natural gas ~~collar arrangements with floor~~ prices ~~ranging from $3.76 to $3.86~~are stated per Mcf and ~~ceiling~~crude oil prices ~~ranging from $4.14 to $4.36~~are stated per ~~Mcf covering 35,458 Mmcf of the Company’s anticipated natural gas production for 2013.~~barrel.

The ~~change~~changes in the fair value of derivatives designated as hedges that isare effective isare recorded to ~~Accumulated Other Comprehensive Income~~accumulated other comprehensive income / ~~(Loss)~~(loss) in ~~Stockholders’ Equity~~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~~natural gas revenue and ~~Crude Oil~~crude oil and ~~Condensate Revenue, as appropriate,~~condensate revenue in the Condensed Consolidated Statement of Operations.

~~Table of Contents~~

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

		Fair Values of Derivative Instruments
		Derivative Assets				Derivative Liabilities

(In thousands)	Balance Sheet Location	June 30, 2013		December 31, 2012		June 30, 2013		December 31, 2012
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments (current assets)	$	69,644	$	50,824	$	—	$	—
Commodity contracts	Derivative instruments (non-current assets)	17,963		—		—		—
Commodity contracts	Accrued liabilities	—		—		—		192
Commodity contracts	Derivative instruments (non-current liabilities)	—		—		—		—

		$	87,607	$	50,824	$	—	$	192

At ~~September~~June 30, ~~2012~~2013 and December 31, ~~2011,~~2012, unrealized gains of ~~$58.1~~$87.6 million ($~~35.6~~53.1 million, net of tax) and ~~$198.3~~unrealized gains of $50.6 million ($~~121.4~~30.7 million, net of tax), respectively, were recorded in ~~Accumulated Other Comprehensive Income~~accumulated other comprehensive income / ~~(Loss).~~(loss) in stockholder’s equity in the Condensed Consolidated Balance Sheet. Based upon estimates at ~~September~~June 30, ~~2012,~~2013, the Company expects to reclassify ~~$36.5~~$42.3 million in after-tax income associated with its commodity hedges from ~~Accumulated Other Comprehensive Income~~accumulated other comprehensive income / ~~(Loss)~~(loss) to the Condensed Consolidated Statement of Operations over the next 12 months.

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Offsetting of Derivative Assets and Liabilities in the Condensed Consolidated Balance Sheet

(In thousands)	June 30, 2013			December 31, 2012
Derivative Assets
Gross amounts of recognized assets	$	89,840		$	54,454
Gross amounts offset in the statement of financial position	(2,233		)	(3,630		)
Net amounts of assets presented in the statement of financial position	87,607			50,824
Gross amounts of financial instruments not offset in the statement of financial position	549			1,892
Net amount	$	88,156		$	52,716

Derivative Liabilities
Gross amounts of recognized liabilities	$	2,233		$	3,822
Gross amounts offset in the statement of financial position	(2,233		)	(3,630		)
Net amounts of liabilities presented in the statement of financial position	—			192
Gross amounts of financial instruments not offset in the statement of financial position	—			—
Net amount	$	—		$	192

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

Derivatives Designated as Hedging Instruments

	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands)	2013		2012		2013		2012
Commodity Contracts	$	115,113	$	18,376	$	54,167	$	89,104

Location of Gain (Loss)	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Reclassified from Accumulated OCI into	Three Months Ended June 30,					Six Months Ended June 30,
Income (In thousands)	2013			2012		2013		2012
Natural gas revenues	$	(272	)	$	69,732	$	13,056	$	126,728
Crude oil and condensate revenues	2,094			3,110		4,136		1,784
	$	1,822		$	72,842	$	17,192	$	128,512

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2012~~2013 and ~~2011,~~2012, 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
)

Derivatives Not Designated as Hedging Instruments

	Location of Gain (Loss) Recognized in Income on	Three Months Ended June 30,					Six Months Ended June 30,

(In thousands)	Derivatives	2013		2012			2013		2012

Commodity Contracts	Natural gas revenues	$	—	$	(342	)	$	—	$	(300	)

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~~each of its counterparties that allow it to offset ~~payables against receivables~~assets and liabilities 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~~liabilities in certain situations.

~~Table of Contents~~

9.8. FAIR VALUE MEASUREMENTS

~~ASC 820, “Fair Value Measurements and Disclosures,” established a formal framework~~The Company follows the authoritative guidance for measuring fair ~~values~~value of assets and liabilities in its financial statements. ~~ASC 820~~The authoritative guidance 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 1314 of the Notes to the Consolidated Financial Statements in the ~~2011~~ Form 10-K.

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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~~June 30, ~~2012~~2013 and ~~2011~~2012 and no other assets or liabilities were required to be measured at fair value on a non-recurring basis, additional disclosures are not provided.

The estimated fair value of the Company’s asset retirement obligation at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligation is deemed to use Level 3 inputs.

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)		June 30, 2013
Assets
Deferred compensation plan	$	11,416	$	—	$	—	$	11,416
Derivative instruments	—		3,729		83,878		87,607
Total assets	$	11,416	$	3,729	$	83,878	$	99,023

Liabilities
Deferred compensation plan	$	30,385	$	—	$	—	$	30,385
Derivative instruments	—		—		—		—

Total liabilities	$	30,385	$	—	$	—	$	30,385

(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

(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, 2012
Assets
Deferred compensation plan	$	10,608	$	—	$	—	$	10,608
Derivative instruments	—		9,473		41,351		50,824

Total assets	$	10,608	$	9,473	$	41,351	$	61,432

Liabilities
Deferred compensation plan	$	23,893	$	—	$	—	$	23,893
Derivative instruments	—		—		192		192

Total liabilities	$	23,893	$	—	$	192	$	24,085

The Company’s investments associated with its ~~Deferred Compensation Plan~~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.

~~Table of Contents~~

The derivative ~~contracts~~instruments 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~~Estimates are verified using relevant NYMEX futures contracts ~~or are compared~~and compares them to multiple quotes obtained from counterparties for reasonableness. The determination of the fair values presented above also incorporates a credit adjustment for ~~non-performance~~nonperformance risk. The Company measured the ~~non-performance~~nonperformance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions

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in which it has derivative transactions, while ~~non-performance~~nonperformance 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						Three Months Ended						Six Months Ended
	September 30,						September 30,						June 30,						June 30,
(In thousands)	2012			2011			2012			2011			2013			2012			2013			2012
Balance at beginning of period	$	129,213		$	48,415		$	195,127		$	14,746		$	(29,899	)	$	218,942		$	41,159		$	195,127
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
Total gains / (losses) (realized or unrealized):
Included in earnings (1)													(272		)	69,390			13,056			126,428
Included in other comprehensive income													113,777			(90,234		)	42,719			(67,541		)
Settlements	(55,915		)	(22,552		)	(181,100		)	(48,884		)	272			(68,885		)	(13,056		)	(125,186		)
Transfers In and/or Out of Level 3	—			—			385			—
Transfers in and/or out of level 3													—			—			—			385
Balance at end of period	$	44,822		$	123,942		$	44,822		$	123,942		$	83,878		$	129,213		$	83,878		$	129,213

~~(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

(1) There were no unrealized gains or losses for the three and six months ended June 30, 2013. Unrealized losses of $0.3 million for the three and six months ended June 30, 2012, 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~~three and six months ended ~~September~~June 30, ~~2012~~2013 and ~~2011.~~2012.

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~~amount the Company would have to ~~acquire~~pay a third party to assume 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.~~hierarchy due to the unobservable nature of the inputs.

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

	June 30, 2013						December 31, 2012
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
Total debt	$	1,142,000		$	1,235,176		$	1,087,000		$	1,213,474
Current maturities	(75,000		)	(75,301		)	(75,000		)	(77,175		)
Long-term debt, excluding current maturities	$	1,067,000		$	1,159,875		$	1,012,000		$	1,136,299

1614

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~~10.~~9. ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

Changes in ~~the components of Accumulated Other Comprehensive Income~~accumulated other comprehensive income / ~~(Loss),~~(loss) by component, net of ~~taxes, for the nine months ended September 30, 2012~~tax, 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

(In thousands)	Net Gains (Losses) on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2012	$	30,717		$	(6,837	)	$	23,880
Other comprehensive income before reclassifications	32,864			—			32,864
Amounts reclassified from accumulated other comprehensive income	(10,430		)	249			(10,181		)
Net current-period other comprehensive income	22,434			249			22,683
Balance at June 30, 2013	$	53,151		$	(6,588	)	$	46,563

Amounts reclassified from accumulated other comprehensive income / (loss) into the Condensed Consolidated Statement of Operations were as follows:

(In thousands)	Three Months Ended June 30, 2013			Six Months Ended June 30, 2013			Affected Line Item in the Statement Where Net Income is Presented
Net gains / (losses) on cash flow hedges
Commodity contracts	$	(272	)	$	13,056		Natural gas revenues
Commodity contracts	2,094			4,136			Crude oil and condensate revenues

Postretirement benefits
Amortization of net loss	(205		)	(410		)	General and administrative expense
	1,617			16,782			Total before tax
	(636		)	(6,601		)	Tax (expense) / benefit
Total reclassifications for the period	$	981		$	10,181		Net of tax

~~11.~~10. PENSION AND ~~OTHER~~ POSTRETIREMENT BENEFITS

The components of net periodic benefit costs, included in ~~General~~general and ~~Administrative Expense~~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

	Three Months Ended					Six Months Ended
	June 30,					June 30,

(In thousands)	2013		2012			2013		2012
Qualified Pension Plan *(1)*
Interest cost	$	—	$	461		$	—	$	922
Expected return on plan assets	—		(874		)	—		(1,748		)
Settlement	—		7,111			—		7,111
Amortization of prior service cost	—		110			—		221
Amortization of net loss	—		6,541			—		13,083

Net periodic pension cost	$	—	$	13,349		$	—	$	19,589

Postretirement Benefits
Service cost	$	415	$	523		$	830	$	1,046
Interest cost	395		418			790		836
Amortization of net loss	205		280			410		560

Total postretirement benefit cost	$	1,015	$	1,221		$	2,030	$	2,442

~~Termination and Amendment of Qualified Pension Plan~~(1)

InOn 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~~13, 2012, the Company made a final ~~contributions~~distribution of ~~$9.6 million and $3.6 million, respectively, to fund the liquidation of the trust under~~benefits from 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.~~11. STOCK-BASED COMPENSATION

Stock-based compensation expense during the first ~~nine~~six months of 2013 and 2012 ~~and 2011~~ was ~~$23.4~~$28.7 million and ~~$29.3~~$13.1 million, respectively, and is included in ~~General~~general and ~~Administrative Expense~~administrative expense in the Condensed Consolidated Statement of Operations. Stock-based compensation expense in the ~~third~~second quarter of 2013 and 2012 ~~and 2011~~ was ~~$10.4~~$10.0 million and ~~$10.0~~$11.4 million, respectively.

Restricted Stock Awards

During the first ~~nine~~six months of ~~2012, 4,350~~2013, 2,050 restricted stock awards were granted to employees with a weighted-average grant date per share value of ~~$32.18.~~$68.87. The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The Company used an annual forfeiture rate assumption of 6.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

Restricted Stock Units

During the first ~~nine~~six months of ~~2012, 38,304~~2013, 23,576 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date per ~~share~~unit value of ~~$36.55.~~$53.75. The fair value of these units is measured atbased on 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~~six months of ~~2012,~~2013, three types of performance share awards were granted to employees for a total of ~~518,602~~402,250 performance shares, which included ~~401,141~~274,760 performance share awards based on performance conditions measured against the Company’s internal performance metrics and ~~117,461~~127,490 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~~2013 commenced on January 1, ~~2012~~2013 and ends on December 31, ~~2014.~~2015. Refer to Note 1112 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,~~$53.23, 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~~274,760 performance awards based on internal metrics, ~~117,461~~84,990 shares have a three-year graded performance period. For these shares, ~~one-third~~25% of the shares ~~are issued~~vest on each of the first and second anniversary dates following the date of the grant and 50% of the shares vest on the third anniversary date following the date of the 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 anniversary date will be forfeited.

For the remaining ~~283,680~~189,770 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

~~Table of Contents~~

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~~June 30, ~~2012,~~2013, it is considered probable that the criteria for ~~these~~the performance awards based on performance conditions will be met.

Awards Based on Market Conditions. The ~~117,461~~127,490 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~~fifteen 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~~2013 awards was valued on the grant date (February ~~16, 2012)~~21, 2013) and was not marked to market. The liability portion of the awards was valued as of ~~September~~June 30, ~~2012~~2013 on a mark-to-market basis.

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The following assumptions were used to determine the grant date fair value of the equity component and the period-end fair value of the liability ~~components~~component of the Company’s performance share awards based on market conditions using a Monte Carlo model:

				Grant Date		June 30, 2013
	Grant Date		September 30, 2012
Value per Share	$28.31		$29.39 - $44.56	$	46.12	$46.09 - $70.96
Assumptions:
Stock Price Volatility	46.7	%	36.2% - 50.7%	43.8%		31.6% - 43.1%
Risk Free Rate of Return	0.4	%	0.1% - 0.3%	0.4%		0.1% - 0.5%
Expected Dividend Yield	0.2	%	0.2%	0.2%		0.1%

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~~For further information regarding the ~~expired plan. The~~terms of the Plan, ~~commenced on July 1, 2012 and is intended~~refer to ~~provide a compensation tool tied~~Note 12 of the Notes to ~~stock market value creation to serve as an incentive and retention vehicle for full-time, non-officer employees by providing for cash payments~~the Consolidated Financial Statements 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.”~~Form 10-K. The Company recognized stock-based compensation expense ~~/ (benefit)~~ of ~~$1.6~~$1.7 million and ~~($0.1)~~$5.1 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2012,~~2013, respectively, which is included in ~~General~~general and ~~Administrative~~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,~~On February 11, 2013, the ~~closing price per share of the Company’s common stock equals or exceeds~~Company achieved 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 ifprior to the interim trigger ~~is met or 50%~~date. Accordingly, a total distribution of ~~base salary if~~approximately $6.8 million was made to 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~~Company’s eligible employees under the Plan, ~~in the event the interim or final trigger date occurs between July 1, 2012 and December 31, 2014,~~of which 25% of the total distribution, ~~will be~~or $1.7 million, was paid ~~immediately~~in February 2013 and the remaining 75% ~~will be~~, or $5.1 million, is deferred ~~and paid at a future date as described~~until August 2014 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 inaccordance with the Plan.

~~Table of Contents~~

~~13.~~12. ASSET RETIREMENT OBLIGATION

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

(In thousands)
Balance at December 31, 2011	$	60,142
Balance at December 31, 2012				$	67,016
Liabilities incurred	1,731			2,354
Liabilities settled	(1,050		)	(757		)
Accretion expense	2,283			1,777
Change in Estimate	(37		)
Balance at September 30, 2012	$	63,069
Balance at June 30, 2013				$	70,390

As of June 30, 2013, approximately $2.0 million, which represents the current portion of the Company’s asset retirement obligation, is included in accrued liabilities in the Condensed Consolidated Balance Sheet.

~~14. INCREASE IN AUTHORIZED SHARES~~13. Subsequent Event-Stock Split

~~In May 2012,~~On July 23, 2013, the ~~stockholders~~Board of Directors declared a 2-for-1 stock split of the ~~Company approved an increase~~Company’s common stock in the ~~authorized number~~form of ~~shares~~a stock dividend. The stock dividend will be distributed on August 14, 2013 to shareholders of record on August 6, 2013.

The pro forma effect on the June 30, 2013 Condensed Consolidated Balance Sheet is to reduce additional paid-in-capital and increase common stock ~~from 240~~by $21.1 million, respectively. Pro forma earnings per share and weighted-average shares outstanding, giving retroactive effect to ~~480 million shares.~~the stock split are as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Earnings per share
Basic – as reported (pre-stock split)	$	0.42	$	0.17	$	0.63	$	0.26
Basic – pro forma (post-stock split)	0.21		0.09		0.32		0.13
Diluted – as reported (pre-stock split)	0.42		0.17		0.62		0.26
Diluted – pro forma (post-stock split)	0.21		0.09		0.31		0.13

Weighted-average shares outstanding
Basic – as reported (pre-stock split)	210,349		209,512		210,250		209,320
Basic – pro forma (post-stock split)	420,698		419,024		420,500		418,640
Diluted – as reported (pre-stock split)	211,745		211,158		211,492		210,974
Diluted – pro forma (post-stock split)	423,490		422,316		422,984		421,948

2017

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of ~~September~~June 30, ~~2012,~~2013, and the related condensed consolidated statements of operations and of comprehensive income for the three and ~~nine~~six month periods ended ~~September~~June 30, ~~2012~~2013 and ~~2011,~~2012 and the condensed consolidated statement of cash flows for the ~~nine~~six month periods ended ~~September~~June 30, ~~2012~~2013 and ~~2011.~~2012. 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,~~2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity ~~comprehensive income~~ and of cash flows for the year then ended (not presented herein), and in our report dated February 28, ~~2012,~~2013, 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,~~2012, 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~~July 26, ~~2012~~2013

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

The following review of operations for the three and ~~nine~~six month periods ended ~~September~~June 30, ~~2012~~2013 and ~~2011~~2012 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~~2012 (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~~six months ended ~~September~~June 30, ~~2012~~2013 increased by ~~42%~~51% compared to the ~~nine~~six months ended ~~September~~June 30, ~~2011.~~2012. For the ~~nine~~six months ended ~~September~~June 30, ~~2012,~~2013, we produced ~~188.9~~184.5 Bcfe, or 1,019.6 Mmcfe per day, compared to ~~132.7~~122.4 Bcfe, or 672.8 Mmcfe per day, for the ~~nine~~six months ended ~~September~~June 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~~60.1 Bcf, or 52%, to 175.8 Bcf for the first six months of 2013 compared to 115.7 Bcf for the first ~~nine~~six months of ~~2011, which had production of 127.2 Bcf.~~2012. This increase was primarily athe result of increased production in the Marcellus ~~shale~~Shale associated with our drilling program and continued expansion of infrastructure ~~installation and upgrades in Susquehanna County, Pennsylvania. Partially offsetting the natural gas production increase~~ in the ~~Marcellus shale were~~area. This increase was partially offset by decreases in ~~natural gas~~ production in ~~east~~ Texas, Oklahoma and West Virginia due to reduced natural gas 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.~~declines. Crude oil/condensate/NGL production increased by ~~91%~~323 Mbbls, or 29%, ~~to 1,760~~from 1,131 Mbbls ~~when compared to~~in the first ~~nine~~six months of ~~2011, which had~~2012 to 1,454 Mbbls in the first six months of 2013. This increase was primarily the result of increased production ~~of 920 Mbbls, primarily due to~~resulting from our ~~focus on liquids projects associated with our Eagle Ford shale~~oil-focused drilling program in south Texas and ~~the Marmaton oil play in~~ Oklahoma.

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Our average realized natural gas price for the first ~~nine~~six months of ~~2012~~2013 was ~~$3.57~~$3.77 per Mcf, ~~23% lower~~7% higher than the ~~$4.64~~$3.52 per Mcf price realized in the first ~~nine~~six months of ~~2011.~~2012. Our average realized crude oil price for the first ~~nine~~six months of ~~2012~~2013 was ~~$100.30~~$102.65 per Bbl, ~~12%~~3% higher than the ~~$89.69~~$99.76 per Bbl price realized in the first ~~nine~~six months of ~~2011.~~2012. 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 natural gas and crude oil ~~and natural gas~~ reserves at economical costs are critical to our long-term success.

During the first six months of 2013, we drilled 83 gross wells (69.7 net) with a success rate of 96% compared to 66 gross wells (51.2 net) with a success rate of 99% for the comparable period of the prior year. For ~~2012,~~the six months ended June 30, 2013, our total capital and exploration spending was $554.1 million compared to $436.5 million for the six months ended June 30, 2012. The increase in capital spending was primarily due to our Marcellus Shale horizontal drilling program in northeast Pennsylvania, the Eagle Ford and Pearsall Shale in south Texas and the Marmaton oil play in Oklahoma. For the full year 2013, we ~~expect~~plan to ~~spend~~drill approximately ~~$900 million~~185 to ~~$950 million~~195 gross wells (155 to 165 net). Our 2013 drilling program includes between $1.1 billion and $1.2 billion in capital and exploration expenditures ~~using proceeds from the sale of assets~~and is expected to ~~supplement our~~be funded by operating cash ~~flows from operations in order to fund incremental capital and exploration expenditures above previously budgeted amounts. We believe our~~flow, existing cash ~~on hand, operating cash flows,~~and, if required, 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.~~facility. 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.

~~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~~six months ended ~~September~~June 30, ~~2012~~2013 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.

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Our working capital is also substantially influenced by the 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

	Six Months Ended
	June 30,
(In thousands)	2013			2012
Cash flows provided by operating activities	$	489,967		$	291,142
Cash flows used in investing activities	(527,400		)	(280,700		)
Cash flows provided by financing activities	53,974			8,288
Net increase in cash and cash equivalents	$	16,541		$	18,730

Operating Activities. Net cash provided by operating activities in the first ~~nine~~six months of ~~2012~~2013 increased by ~~$79.7~~$198.8 million over the first ~~nine~~six months of ~~2011.~~2012. 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). and unfavorable changes in working capital and long-term assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production and higher realized natural gas and crude oil ~~prices partially offset by lower realized natural gas~~ prices. Equivalent production volumes increased by ~~42%~~51% for the ~~nine~~six months ended ~~September~~June 30, ~~2012~~2013 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2011 as a result of higher~~2012. Average realized natural gas prices increased by 7% and ~~crude oil production. Average~~average realized crude oil prices increased by ~~12% compared to the same period while average realized natural gas prices decreased by 23%~~3% for the first ~~nine~~six months of ~~2012~~2013 compared to the first ~~nine~~six months of ~~2011.~~2012.

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.

~~Table of Contents~~

Investing Activities. Cash flows used in investing activities ~~decreased~~increased by ~~$45.9~~$246.7 million for the first ~~nine~~six months of ~~2012~~2013 compared to the first ~~nine~~six months of ~~2011.~~2012. The ~~decrease~~increase was primarily due ~~an increase~~to $131.8 million of ~~$50.6 million in~~lower proceeds from sale of assets, ~~partially offset by $4.5~~an increase of $112.7 million in capital expenditures and an increase of $2.2 million in capital contributions associated with our equity method investment in Constitution Pipeline Company, LLC (Constitution).

Financing Activities. Cash flows provided by financing activities ~~decreased~~increased by ~~$125.1~~$45.7 million ~~from~~for the first ~~nine~~six months of ~~2011~~2013 compared to the first ~~nine~~six months of 2012. This ~~decrease~~increase was primarily due to ~~$118.0~~$33.0 million ~~lower~~of higher net borrowings, ~~($50.0~~an increase of $7.3 million ~~decrease~~ in ~~borrowings and $68.0 million increase in repayments of debt), $4.0 million higher debt issuance costs~~tax benefits associated with our ~~amended credit facility~~stock-based compensation and ~~$3.2 million higher dividend payments.~~a $5.0 decrease in capitalized debt issuance costs.

~~In May 2012, we amended~~Effective April 17, 2013, the lenders under our revolving credit facility approved an increase in our borrowing base from $1.7 billion to ~~adjust~~$2.3 billion as part of the ~~margins associated with borrowings~~annual redetermination under the ~~facility and extend~~terms of the ~~maturity date from September 2015 to May 2017.~~revolving credit facility. The Company’s commitments under the credit facility ~~as amended, provides for an available credit line~~ of ~~$900~~$900.0 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 Septemberremained unchanged. At June 30, ~~2012, the borrowing base under our amended credit facility was $1.7 billion.~~

~~At September 30, 2012,~~2013, we had ~~$300.0~~$380.0 million of borrowings outstanding under ~~the amended~~our revolving credit facility at a weighted-average interest rate of ~~2.3%~~2.0% and ~~$599.0~~$519.0 million available for future borrowings.

We were in compliance with all restrictive financial covenants in ~~all material respects with our debt covenants~~both the revolving credit facility and senior notes as of ~~September~~June 30, ~~2012.~~2013.

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.

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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

	June 30,		December 31,
(Dollars in thousands)	2013		2012

Debt (1)	$	1,142,000	$	1,087,000
Stockholders’ equity	2,286,241		2,131,447
Total capitalization	$	3,428,241	$	3,218,447

Debt to capitalization	33%		34%

Cash and cash equivalents	$	47,277	$	30,736

(1)Includes $75.0 million of current portion of long-term debt at ~~September~~June 30, 2013 and December 31, 2012 and ~~$300.0~~$380.0 million and ~~$188.0~~$325.0 million of borrowings outstanding under our revolving credit facility at ~~September~~June 30, ~~2012~~2013 and December 31, ~~2011,~~2012, respectively.

During the ~~nine~~six months ended ~~September~~June 30, ~~2012,~~2013, we paid dividends of ~~$12.6~~$8.4 million ($~~0.06~~0.04 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 and exploration expenditures based on our current estimate of future commodity prices and projected cash flows for the year.

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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

Six Months Ended

June 30,

(In thousands)

2013

2012

Capital expenditures

Drilling and facilities

$
506,210

$
363,756

Leasehold acquisitions

39,047

47,399

Pipeline and gathering

263

(466
)
Other

—

5,562

545,520

416,251

Exploration expense

8,553

20,245

Total

$
554,073

$
436,496

For the full year of ~~2012,~~2013, we plan to drill approximately ~~150~~185 to ~~170~~195 gross ~~wells.~~wells (155 to 165 net). Our ~~2012~~2013 drilling program includes between ~~$900 million~~$1.1 billion to ~~$950 million~~$1.2 billion 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.~~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 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~~Except for the amended transportation agreements and two new drilling rig commitments described in Note ~~7 in the Notes~~6 to the Condensed Consolidated Financial Statements ~~for changes~~included in ~~our commitments for the first nine months of 2012. There~~this Form 10-Q, there have been no ~~other~~ material changes to our contractual obligations described under ~~“Gas Transportation~~“Transportation Agreements”, “Drilling Rig ~~Commitments”, “Hydraulic Fracturing Services~~ Commitments” and “Lease Commitments” as disclosed in Note 78 in the Notes to Consolidated Financial Statements and the obligations described under “Contractual Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” 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~~21

Table 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.Contents

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,~~Effective January 1, 2013, we adopted the ~~Financial Accounting Standards Board (FASB) issued~~amended disclosure requirements prescribed in Accounting Standards Update (ASU) No. ~~2011-04, “Amendments to Achieve Common Fair Value Measurement~~2011-11, “Disclosures about Offsetting Assets and ~~Disclosure Requirements in U.S. GAAP~~Liabilities” and ~~IFRSs.~~ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” 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~~guidance impacted the disclosures associated with our commodity derivatives 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,~~Effective January 1, 2013, we adopted the ~~FASB issued~~amended disclosure requirements prescribed in ASU No. ~~2011-05, “Presentation~~2013-02, “Reporting 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~~Amounts Reclassified Out of Accumulated Other Comprehensive ~~Income in ASU No. 2011-05.~~Income.” 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
25

~~Table of Contents~~
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~~impacted our disclosures associated with ~~our commodity derivatives. We do~~items reclassified from accumulated other comprehensive income / (loss) and did not ~~expect this guidance to have any~~ impact on our consolidated financial position, results of operations or cash flows.

Results of Operations

~~Third~~Second Quarters of ~~2012~~2013 and ~~2011~~2012 Compared

We reported net income in the ~~third~~second quarter of ~~2012~~2013 of ~~$36.6~~$89.1 million, or $0.42 per share, compared to $35.9 million, or $0.17 per share, ~~compared to $28.5 million, or $0.14 per share~~ in the ~~third~~second quarter of ~~2011.~~2012. The increase in net income was primarily due to an increase in equivalent production and higher realized ~~crude oil~~natural gas prices, partially offset by ~~lower realized natural gas prices and~~ higher operating ~~costs.~~expenses and slightly lower crude oil prices.

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%

Three Months Ended June 30,

Variance

Revenue Variances (In thousands)

2013

2012

Amount

Percent

Natural gas (1)

$
368,391

$
201,393

$
166,998

83%

Crude oil and condensate

70,226

57,466

12,760

22%

Brokered natural gas

8,244

5,149

3,095

60%

Other

2,819

1,991

828

42%

(1)Natural ~~Gas Revenues~~gas revenues exclude the unrealized loss of ~~$0.1 million and $0.1~~$0.3 million from the change in fair value of our derivatives not designated as hedges in ~~2012 and 2011, respectively.~~2012. There were no unrealized gains or losses in 2013.

Three Months Ended June 30,

Variance

Increase
(Decrease)

Three Months Ended September 30,

Variance

Increase
(Decrease)

2012

2011

Amount

Percent

(In thousands)

2013

2012

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

Natural gas (1)

$
4.06

$
3.39

$
0.67

20%

$
61,075

Crude oil and condensate (2)

$
101.39

$
102.61

$
(1.22
)
(1%
)
(840
)

Total

$
(46,887
)

$
60,235

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

Natural gas (Bcf)

90.7

59.2

31.5

53%

$
105,923

Crude oil and condensate (Mbbl)

693

560

133

24%

13,600

Total

$
85,059

$
119,523

(1)These prices include the realized impact of derivative instrument settlements, which increased the price by ~~$0.91~~$1.18 per Mcf in ~~2012 and $0.44 per Mcf~~2012. There was no impact on the realized price from derivative instrument settlements in ~~2011.~~2013.
(2)These prices include the realized impact of derivative instrument settlements, which increased the price by ~~$6.65~~$3.02 per Bbl in ~~2012~~2013 and ~~$3.62~~decreased the price by $5.55 per Bbl in ~~2011.~~2012.
22

Table of Contents

Natural Gas Revenues

The increase in natural gas revenues of ~~$13.5~~$167.0 million, excluding the impact of the unrealized losses on derivative instruments discussed above, is primarily due to increased production ~~during the third quarter of 2012, partially offset by lower~~and higher realized natural gas prices. The ~~increase in~~increased production was primarily a result of higher production in the Marcellus ~~shale~~Shale associated with our drilling program and expanded infrastructure, ~~installation~~partially offset by decreases in production primarily in Texas, Oklahoma and ~~upgrades in Susquehanna County, Pennsylvania. Partially offsetting the increase in~~West Virginia due reduced natural gas ~~production~~drilling in ~~the Marcellus shale were decreases in natural gas production in east Texas due to reduced drilling activity~~these areas and normal production ~~declines along with the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011.~~
26

~~Table of Contents~~declines.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of ~~$24.7~~$12.8 million is primarily due to ~~our focus on liquids projects~~increased production associated with our ~~Eagle Ford shale~~oil-focused drilling program in south Texas and ~~the Marmaton oil play in~~ Oklahoma, ~~and higher~~partially offset by slightly lower 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)

x
1,595

x
1,899

(304
)
(16)%

1,313

Brokered Natural Gas Cost (In thousands)

$
4,258

$
8,204

$
3,946

Brokered Natural Gas Margin (In thousands)

$
980

$
1,263

$
(283
)

Price and

Three Months Ended

Volume

June 30,

Variance

Variances

2013

2012

Amount

Percent

(In thousands)

Brokered Natural Gas Sales

Sales price ($/Mcf)

$
4.81

$
2.82

$
1.99

71%

$
3,414

Volume brokered (Mmcf)

x
1,714

x
1,827

(113
)
(6%
)
(319
)

Brokered natural gas (In thousands)

$
8,244

$
5,149

$
3,095

Brokered Natural Gas Purchases

Purchase price ($/Mcf)

$
3.91

$
2.33

$
1.58

68%

$
(2,717
)
Volume brokered (Mmcf)

x
1,714

x
1,827

(113
)
(6%
)
263

Brokered natural gas (In thousands)

$
6,704

$
4,250

$
(2,454
)

Brokered natural gas margin (In thousands)

$
1,540

$
899

$
641

The ~~decreased~~increase in brokered natural gas margin of ~~$0.3~~$0.6 million is primarily a result of ~~a decrease~~an increase in sales price that outpaced the ~~decrease~~increase in purchase price, ~~and~~partially offset by lower brokered volumes.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the increase / (decrease) to revenue from the realized impact of cash settlements for derivative instruments designated as cash flow hedges and the net unrealized change in fair value of other financial derivative instruments:

Three Months Ended September 30,

(In thousands)

2012

2011

Cash Flow Hedges

Natural Gas

$
57,139

$
21,170

Crude Oil

3,799

1,382

Other Financial Derivative Instruments

Natural Gas Basis Swaps

(149
)
(64
)

$
60,789

$
22,488

Three Months Ended
June 30,

(In thousands)

2013

2012

Cash Flow Hedges

Natural gas

$
(272
)
$
69,732

Crude oil

2,094

3,110

Other Derivative Financial Instruments

Natural gas basis swaps

—

(342
)

$
1,822

$
72,500

2723

Table of Contents
Operating and Other Expenses

Three Months Ended
September 30,

Variance

(In thousands)

2012

2011

Amount

Percent

Operating and Other Expenses

Direct Operations

$
28,269

$
27,292

$
977

4%

Transportation and Gathering

34,430

19,768

14,662

74%

Brokered Natural Gas

4,258

8,204

(3,946
)
(48)%

Taxes Other Than Income

10,436

7,042

3,394

48%

Exploration

9,303

20,190

(10,887
)
(54)%

Depreciation, Depletion and Amortization

110,448

90,293

20,155

22%

General and Administrative

23,829

27,949

(4,120
)
(15)%

Total Operating Expense

$
220,973

$
200,738

$
20,235

10%

(Gain) / Loss on Sale of Assets

$
126

$
(3,854
)
$
(3,980
)
(103)%

Interest Expense and Other

16,219

18,517

(2,298
)
(12)%

Income Tax Expense

22,948

18,234

4,714

26%

Three Months Ended June 30,

Variance

(In thousands)

2013

2012

Amount

Percent

Operating and Other Expenses

Direct operations

$
36,978

29,306

$
7,672

26%

Transportation and gathering

52,648

33,139

19,509

59%

Brokered natural gas

6,704

4,250

2,454

58%

Taxes other than income

11,364

10,854

510

5%

Exploration

4,529

16,244

(11,715
)
(72%
)
Depreciation, depletion and amortization

151,389

114,616

36,773

32%

General and administrative

21,608

46,872

(25,264
)
(54%
)

Total operating expense

$
285,220

$
255,281

$
29,939

12%

(Gain) / loss on sale of assets

$
(276
)
$
(67,703
)
$
(67,427
)
(100%
)
Interest expense and other

16,701

18,495

(1,794
)
(10%
)
Income tax expense

58,921

23,647

35,274

149%

Total costs and expenses from operations increased by ~~$20.2~~$29.9 million, or ~~10%~~12%, in the ~~third~~second quarter of ~~2012~~2013 compared to the same period of ~~2011.~~2012. The primary reasons for this fluctuation are as follows:

·                  Direct ~~Operations~~operations increased ~~$1.0~~$7.7 million largely due to higher operating costs primarily driven by increased ~~production. Contributing~~production, including higher treating and disposal costs associated with an increase in produced water and more stringent pipeline quality requirements. In addition, we experienced higher plugging and abandonment costs associated with certain wells in south Texas and a slight increase in outside-operated and employee-related costs due to ~~the~~an increase ~~are higher employee related costs, partially offset by decreased workover activity.~~in headcount.

·                  Transportation and ~~Gathering~~gathering increased ~~$14.7~~$19.5 million due to ~~an increase in~~higher throughput as a result of increased production, ~~and~~slightly higher transportation rates and the commencement of various transportation and gathering ~~arrangements~~agreements in the ~~fourth quarter of 2011 and the first nine months~~second half of 2012 primarily in northeast ~~Pennsylvania.~~Pennsylvania and south Texas.

·                  Brokered ~~Natural Gas decreased $4.0~~natural gas increased $2.5 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

·                  ~~Taxes Other Than Income increased $3.4~~Exploration expense decreased $11.7 million ~~primarily~~ due to ~~additional costs associated with the passage of~~ an ~~impact fee in Pennsylvania on Marcellus shale production that was imposed by the state legislature in February 2012.~~
·~~Exploration decreased $10.9 million primarily due to lower~~ exploratory dry hole ~~costs~~ associated with anour Brown Dense/Smackover exploratory well in ~~Montana that was expensed~~Union County, Arkansas recorded in ~~2011 partially offset by higher geological and geophysical costs due to increased processing~~the second quarter of ~~seismic data.~~2012. There were no dry holes recorded in the second quarter of 2013.

·                  Depreciation, ~~Depletion~~depletion and ~~Amortization~~amortization increased ~~$20.2~~$36.8 million, of which ~~$26.8~~$55.4 million was due to higher equivalent production volumes for the second quarter ~~ended September 30, 2012~~of 2013 compared to the second quarter ~~ended September 30, 2011. The increase in depreciation and depletion was~~of 2012, partially offset by a decrease ~~in amortization~~ of ~~unproved properties of $6.5~~$19.1 million ~~as the result of a decrease in amortization rates~~ due to a lower DD&A rate of $1.50 per Mcfe for the ~~success~~second quarter of ~~our drilling programs in Pennsylvania and south Texas and the sale of certain Pearsall shale undeveloped leaseholds in south Texas in~~2013 compared to $1.71 per Mcfe for the second quarter of 2012. ~~These decreases were partially offset by increased lease acquisition costs.~~The lower DD&A rate was primarily due to lower cost of reserve additions associated with our 2013 and 2012 drilling programs.

·                  General and ~~Administrative~~administrative decreased ~~$4.1~~$25.3 million primarily due to $13.3 million of lower pension expense associated with the liquidation of our pension plan that occurred in the second quarter of 2012, a $5.3 million decrease in ~~costs related~~legal and professional expenses and slightly lower stock-based compensation expense associated with the mark-to-market of our liability-based performance awards and supplemental employee incentive plan due to changes in our ~~terminated pension plan, which was fully settled~~stock price for the second quarter 2013 compared to the second quarter of 2012.
(Gain) / Loss on Sale of Assets
The decrease of $67.4 million is primarily due to the gain on sale of certain of our Pearsall Shale undeveloped leaseholds in south Texas recognized in the second quarter of 2012. There were no ~~pension costs incurred in the third quarter~~significant gains or losses on sale of ~~2012.~~
~~Gain / (Loss) on Sale of Assets~~
~~An aggregate loss of $0.1 million was~~assets recognized in the ~~third~~second quarter of ~~2012. During the third quarter of 2011, an aggregate gain of $3.9 million was recognized primarily due to the sale of non-core assets as part of our ongoing portfolio management program.~~2013.

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Table of Contents

Interest Expense and Other

Interest expense and other decreased ~~$2.3~~$1.8 million primarily due a to ~~a decrease~~lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.2% during the second quarter of 2013 compared to approximately 3.4% during the second quarter of 2012, partially offset by an increase in weighted-average borrowings under our revolving credit facility based on daily balances of approximately ~~$274.0~~$405.7 million during the ~~third~~second quarter of ~~2012~~2013 compared to approximately ~~$407.7~~$293.7 million during the ~~third~~second quarter of 2011 and a lower weighted-average effective interest rate on our credit facility borrowings of approximately 2.5% during the third quarter of 2012 compared to approximately 3.7% during the third quarter of 2011.2012.

Income Tax Expense

Income tax expense increased ~~$4.7~~$35.3 million primarily due to higher pretax ~~income, partially offset by a slightly lower effective tax rate.~~income. The effective tax rate for the ~~third~~second quarter of 2013 and 2012 was 39.8% and ~~2011 was 38.5% and 39.0%~~39.7%, respectively.

~~Nine~~First Six Months of ~~2012~~2013 and ~~2011~~2012 Compared

We reported net income in the first ~~nine~~six months of ~~2012~~2013 of ~~$90.9~~$131.9 million, or ~~$0.43~~$0.63 per share, compared to ~~net income~~$54.3 million, or $0.26 per share, in the first ~~nine~~six months of ~~2011 of $96.0 million, or $0.46 per share.~~2012. The ~~decrease~~increase in net income was primarily due to ~~lower realized natural gas prices and higher operating costs offset by increased~~an increase in equivalent production and higher realized natural gas and crude oil ~~prices. Net income was also affected by a~~prices partially offset higher ~~gain on sale of assets during the first nine months of 2012.~~operating expenses.

Revenue, Price and Volume Variances

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

Nine Months Ended September 30,

Variance

Revenue Variances (In thousands)

2012

2011

Amount

Percent

Natural Gas (1)

$
640,178

$
589,926

$
50,252

9%

Crude Oil and Condensate

165,317

79,792

85,525

107%

Brokered Natural Gas

23,831

38,947

(15,116
)
(39)%

Other

5,790

4,124

1,666

40%

Six Months Ended June 30,

Variance

Revenue Variances (In thousands)

2013

2012

Amount

Percent

Natural gas (1)

$
662,184

$
408,133

$
254,051

62%

Crude oil and condensate

135,881

107,447

28,434

26%

Brokered natural gas

19,137

18,593

544

3%

Other

5,763

3,920

1,843

47%

(1)Natural ~~Gas Revenues~~gas revenues exclude the unrealized ~~loss~~gain of ~~$0.4 million and $1.0~~$0.3 million from the change in fair value of our derivatives not designated as hedges in ~~2012 and 2011, respectively.~~2012. There were no unrealized gains or losses in 2013.

Increase

Increase

Nine Months Ended September 30,

Variance

(Decrease)

Six Months Ended June 30,

Variance

(Decrease)

2012

2011

Amount

Percent

(In thousands)

2013

2012

Amount

Percent

(In thousands)

Price Variances

Natural Gas (1)

$
3.57

$
4.64

$
(1.07
)
(23)%

$
(188,637
)
Crude Oil and Condensate (2)

$
100.30

$
89.69

$
10.61

12%

17,579

Natural gas (1)

$
3.77

$
3.52

$
0.25

7%

$
43,286

Crude oil and condensate (2)

$
102.65

$
99.76

$
2.89

3%

3,828

Total

$
(171,058
)

$
47,114

Volume Variances

Natural Gas (Mmcf)

178,351

127,206

51,145

40%

$
238,889

Crude Oil and Condensate (Mbbl)

1,648

890

758

85%

67,946

Natural gas (Bcf)

175.8

115.7

60.1

52%

$
210,765

Crude oil and condensate (Mbbl)

1,324

1,077

247

23%

24,606

Total

$
306,835

$
235,371

(1)These prices include the realized impact of derivative instrument settlements, which increased the price by ~~$1.03~~$0.07 per Mcf in ~~2012~~2013 and ~~$0.38~~by $1.10 per Mcf in ~~2011.~~2012.
(2)These prices include the realized impact of derivative instrument settlements, which increased the price by ~~$3.39~~$3.12 per Bbl in ~~2012~~2013 and ~~$0.64~~decreased the price by $1.66 per Bbl in ~~2011.~~2012.

Natural Gas Revenues

The increase in natural gas revenues of ~~$50.3~~$254.1 million, excluding the impact of the unrealized losses on derivative instruments discussed above, is primarily due to increased production during the first ~~nine~~six months of ~~2012, partially offset by lower~~2013 and higher realized natural gas prices. The ~~increase in~~increased production was primarily a result of higher production in the Marcellus ~~shale~~Shale associated with our drilling program and expanded infrastructure, ~~installation~~partially offset by decreases in production primarily in Texas, Oklahoma and ~~upgrades in Susquehanna County, Pennsylvania. Partially offsetting the~~West Virginia due reduced natural gas ~~production increase~~drilling in ~~the Marcellus shale were decreases in natural gas production in east Texas due to reduced drilling activity~~these areas and normal production ~~declines along with the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011.~~declines.

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Table of Contents

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of ~~$85.5~~$28.4 million is primarily due to ~~our focus on liquids projects~~increased production associated with our ~~Eagle Ford shale~~oil-focused 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

Nine Months Ended

Volume

September 30,

Variance

Variances

2012

2011

Amount

Percent

(In thousands)

Brokered Natural Gas Sales

Sales Price ($/Mcf)

$
3.54

$
5.15

$
(1.61
)
(31)%

$
(10,857
)
Volume Brokered (Mmcf)

x
6,733

x
7,560

(827
)
(11)%

(4,259
)
Brokered Natural Gas Revenues (In thousands)

$
23,831

$
38,947

$
(15,116
)

Brokered Natural Gas Purchases

Purchase Price ($/Mcf)

$
3.03

$
4.41

$
(1.38
)
(31)%

$
9,335

Volume Brokered (Mmcf)

x
6,733

x
7,560

(827
)
(11)%

3,647

Brokered Natural Gas Cost (In thousands)

$
20,380

$
33,362

$
12,982

Brokered Natural Gas Margin (In thousands)

$
3,451

$
5,585

$
(2,134
)

Price and

Six Months Ended

Volume

June 30,

Variance

Variances

2013

2012

Amount

Percent

(In thousands)

Brokered Natural Gas Sales

Sales price ($/Mcf)

$
4.00

$
3.62

$
0.38

11%

$
1,836

Volume brokered (Mmcf)

x
4,781

x
5,138

(357
)
(7%
)
(1,292
)

Brokered natural gas (In thousands)

$
19,137

$
18,593

$
544

Brokered Natural Gas Purchases

Purchase price ($/Mcf)

$
3.16

$
3.14

$
0.02

1%

$
(91
)
Volume brokered (Mmcf)

x
4,781

x
5,138

(357
)
(7%
)
1,120

Brokered natural gas (In thousands)

$
15,093

$
16,122

$
1,029

Brokered natural gas margin (In thousands)

$
4,044

$
2,471

$
1,573

The ~~decreased~~increased brokered natural gas margin of ~~$2.1~~$1.6 million is primarily a result of ~~a decrease~~an increase in sales price that outpaced ~~a decrease~~the increase in ~~the~~ purchase price, ~~and~~partially offset by lower brokered volumes.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the increase / (decrease) to revenue from the realized impact of cash settlements for derivative instruments designated as cash flow hedges and the net unrealized change in fair value of other financial derivative instruments:

Six Months Ended June 30,

Nine Months Ended September  30,

(In thousands)

2012

2011

2013

2012

Cash Flow Hedges

Natural Gas

$
183,867

$
48,318

$
13,056

$
126,728

Crude Oil

5,583

566

4,136

1,784

Other Financial Derivative Instruments

Natural Gas Basis Swaps

(449
)
(950
)

—

(300
)

$
189,001

$
47,934

$
17,192

$
128,212

3026

Table of Contents

Operating and Other Expenses

Nine Months Ended
September 30,

Variance

(In thousands)

2012

2011

Amount

Percent

Operating and Other Expenses

Direct Operations

$
84,895

$
76,878

$
8,017

10%

Transportation and Gathering

97,827

48,710

49,117

101%

Brokered Natural Gas

20,380

33,362

(12,982
)
(39)%

Taxes Other Than Income

39,873

21,070

18,803

89%

Exploration

29,548

31,090

(1,542
)
(5)%

Depreciation, Depletion and Amortization

335,421

250,642

84,779

34%

General and Administrative

93,249

78,254

14,995

19%

Total Operating Expense

$
701,193

$
540,006

$
161,187

30%

(Gain) / Loss on Sale of Assets

$
(67,042
)
$
(36,408
)
$
30,634

84%

Interest Expense and Other

51,631

53,928

(2,297
)
(4)%

Income Tax Expense

58,021

58,268

(247
)
(0)%

Six Months Ended June 30,

Variance

(In thousands)

2013

2012

Amount

Percent

Operating and Other Expenses

Direct operations

$
68,475

$
56,626

$
11,849

21%

Transportation and gathering

98,869

63,397

35,472

56%

Brokered natural gas

15,093

16,122

(1,029
)
(6%
)
Taxes other than income

23,051

29,437

(6,386
)
(22%
)
Exploration

8,553

20,245

(11,692
)
(58%
)
Depreciation, depletion and amortization

300,042

224,973

75,069

33%

General and administrative

57,312

69,421

(12,109
)
(17%
)

Total operating expense

$
571,395

$
480,221

$
91,174

19%

(Gain) / loss on sale of assets

$
(180
)
$
(67,168
)
$
(66,988
)
(100%
)
Interest expense and other

32,956

35,412

(2,456
)
(7%
)
Income tax expense

86,856

35,073

51,783

148%

Total costs and expenses from operations increased by ~~$161.2~~$91.2 million, or ~~30%~~19%, in the first ~~nine~~six months of ~~2012~~2013 compared to the same period of ~~2011.~~2012. The primary reasons for this fluctuation are as follows:

·                  Direct ~~Operations~~operations increased ~~$8.0~~$11.8 million largely due to higher operating costs primarily driven by increased ~~production. Contributing to the~~production, including higher treating and disposal costs associated with an increase ~~are~~in produced water and more stringent pipeline quality requirements. In addition, we experienced higher ~~employee related~~plugging and abandonment costs ~~leased production equipment,~~associated with certain wells in south Texas and ~~saltwater disposal~~an increase in outside-operated costs. ~~These~~Partially offsetting these increases ~~are partially offset by decreased~~was a decrease in workover activity.

·                  Transportation and ~~Gathering~~gathering increased ~~$49.1~~$35.5 million ~~primarily~~ due to ~~an increase in~~higher throughput as a result of increased production, ~~and~~slightly higher transportation rates and the commencement of various transportation and gathering ~~arrangements throughout 2011 and~~agreements in the ~~first nine months~~second half of 2012 primarily in northeast ~~Pennsylvania.~~Pennsylvania and south Texas.

·                  Brokered ~~Natural Gas~~natural gas decreased ~~$13.0~~$1.0 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

·                  Taxes ~~Other Than Income increased $18.8~~other than income decreased $6.4 million primarily due to ~~additional costs~~lower impact fees associated with ~~the passage of an “impact fee” in Pennsylvania on~~our Marcellus ~~shale~~Shale production ~~that was imposed~~partially offset by ~~state legislature in February 2012,~~ higher production ~~tax expense due to increased oil production in south Texas and Oklahoma and fewer production tax incentives received in the first nine month~~taxes. The second quarter of 2012 ~~compared to~~included the ~~first nine months~~initial assessment of ~~2011. Costs~~impact fees associated with ~~the impact fee in Pennsylvania includes approximately $8.3 million related to wells drilled~~2011 and prior ~~to 2012.~~period wells.

·                  Exploration expense decreased ~~$1.5~~$11.7 million ~~primarily~~ due to ~~lower~~an exploratory dry hole ~~costs and geological and geophysical costs as a result~~associated with our Brown Dense/Smackover exploratory well in Union County, Arkansas recorded in the first six months of ~~fewer acquisitions and purchases~~2012. There were no dry holes recorded in the first six months of ~~seismic data. These decreases were partially offset by higher employee related costs.~~2013.

·                  Depreciation, ~~Depletion~~depletion and ~~Amortization~~amortization increased ~~by $84.8~~$75.1 million, of which ~~$93.8~~$105.3 million was due to higher equivalent production volumes for the first six months of 2013 compared to the first six months of 2012, partially offset by a decrease ~~in amortization~~ of ~~unproved properties of $ 8.7~~$29.7 million ~~as a result of a decrease in amortization rates~~ due to a lower DD&A rate of $1.53 per Mcfe for the ~~success~~first six months of ~~our drilling programs in Pennsylvania and south Texas and~~2013 compared to $1.70 per Mcfe for the ~~sale of certain Pearsall shale undeveloped leaseholds in south Texas in the second quarter~~first six months of 2012. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our 2013 and 2012 drilling programs.

·                  General and ~~Administrative increased by $15.0~~administrative decreased $12.1 million primarily due ~~to $9.5~~$19.6 million ~~higher~~of lower pension expense associated with the ~~termination~~liquidation of our ~~qualified~~ pension plan ~~and the related settlement~~ that occurred in the ~~second quarter~~first six months of 2012 and ~~higher~~$5.1 million of lower legal ~~costs~~ and professional fees of $6.6 million. Also contributing to the increase was the accrual of $1.9 million associated with fines and penalties assessed in the second quarter of 2012 by the Office of Natural Resources Revenue for certain alleged reporting matters (which we are disputing) related to properties we no longer own. These increases wereexpenses, partially offset by ~~$5.9~~$15.6 million ~~lower~~of higher stock-based compensation expense ~~primarily~~ associated with the mark-to-market of our liability-based performance awards and our supplemental employee incentive plan due to changes in our stock price for the ~~nine~~first six months ~~ended September 30, 2012~~of 2013 compared to the ~~nine~~first six months ~~ended September 30, 2011, partially offset by an increase~~ of ~~our supplemental employee incentive plan liability.~~2012.

3127

Table of Contents

~~Gain~~(Gain) / ~~(Loss)~~Loss on Sale of Assets

~~An aggregate gain~~The decrease of $67.0 million ~~was recognized in the first nine month of 2012~~is primarily due to the gain on sale of certain of our Pearsall ~~shale~~Shale undeveloped leaseholds in south ~~Texas. During~~Texas recognized in the first ~~nine~~six months of ~~2011, an aggregate gain of $36.4 million was recognized primarily due to the~~2012. There were no significant gains or losses on sale of assets recognized in the ~~undeveloped leaseholds in east Texas and the sale~~first six months of ~~non-core assets as part of our ongoing portfolio management program.~~2013.

Interest Expense and Other

Interest expense and other decreased ~~by $2.3~~$2.5 million primarily due a to ~~a decrease~~lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.3% during the first six months of 2013 compared to approximately 3.7% during the first six months of 2012, partially offset by an increase in weighted-average borrowings under our revolving credit facility based on daily balances of approximately ~~$266.5~~$383.8 million during the first ~~nine~~six months of ~~2012~~2013 compared to approximately ~~$340.2~~$263.2 million during the first nine months of 2011 coupled with a lower weighted-average effective interest rate on our credit facility borrowings of approximately 3.2% during the first nine months of 2012 compared to approximately 4.0% during the first nine months of 2011. These decreases were partially offset by an increase of $1.3 million of debt extinguishment costs associated with our credit facility amendment in the first ninesix months of 2012.

Income Tax Expense

Income tax expense ~~decreased by $0.2~~increased $51.8 million primarily due to ~~lower~~higher pretax income ~~offset by~~and a slightly higher effective tax rate. The effective tax rate for the first ~~nine~~six months of ~~2012~~2013 and ~~2011 was 39.0% and 37.7%, respectively. The effective tax rate in~~ 2012 was ~~higher due to an increase in estimated state tax liabilities~~39.7% and ~~non-deductible expenses.~~39.3%, respectively.

Forward-Looking Information

The statements regarding future financial and operating performance and results, strategic pursuits and goals, 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. ~~These~~Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed ~~in this document~~herein and in our other Securities and Exchange Commission filings. IfSee “Risk Factors” in Item 1A of the Form 10-K for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or ifshould underlying assumptions prove incorrect, actual outcomes may vary materially from those ~~included in this document.~~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~~increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 813 of the Notes to the ~~Condensed~~ Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our hedging arrangements.

Periodically, we enter into commodity derivative ~~commodity~~ instruments, including collar and swap agreements, to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our derivatives are used for risk management purposes and are not held for trading purposes. Under ~~our~~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. Under the swap agreements, 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 our 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.~~

3228

Table of Contents

As of ~~September~~June 30, ~~2012,~~2013, we had the following outstanding commodity derivatives:

Commodity and Derivative Type

Weighted-Average Contract Price

Volume

Contract Period

Net Unrealized
Gain / (Loss)
(In thousands)

Derivatives Designated as Hedging Instruments

Natural Gas Swaps

$5.22  per Mcf

24,131  Mmcf

Oct. 2012 - Dec. 2012

43,456

Natural Gas Collars

$3.60 Floor / $4.17 Ceiling  per Mcf

2,963  Mmcf

Nov. 2012 - Dec. 2012

517

Natural Gas Collars

$5.15 Floor / $6.18 Ceiling  per Mcf

10,637  Mmcf

Jan. 2013 - Dec. 2013

13,694

Natural Gas Collars

$5.15 Floor / $6.23 Ceiling  per Mcf

7,092  Mmcf

Jan. 2013 - Dec. 2013

9,140

Natural Gas Collars

$3.09 Floor / $4.12 Ceiling  per Mcf

35,458  Mmcf

Jan. 2013 - Dec. 2013

(8,780
)
Natural Gas Collars

$3.40 Floor / $4.12 Ceiling  per Mcf

17,729  Mmcf

Jan. 2013 - Dec. 2013

(3,028
)
Natural Gas Collars

$3.35 Floor / $4.01 Ceiling  per Mcf

35,458  Mmcf

Jan. 2013 - Dec. 2013

(8,100
)
Natural Gas Collars

$3.60 Floor / $4.17 Ceiling  per Mcf

17,729  Mmcf

Jan. 2013 - Dec. 2013

(1,397
)
Crude Oil Swaps

$100.45  per Bbl

460  Mbbl

Oct. 2012 - Dec. 2012

3,547

Crude Oil Swaps

$101.90  per Bbl

1,095  Mbbl

Jan. 2013 - Dec. 2013

8,947

$
57,996

Derivatives Not Designated as Hedging Instruments

Natural Gas Basis Swaps

$(0.25)  per Mcf

4,284   Mmcf

Oct. 2012 - Dec. 2012

(809
)

$
57,187

Collars

Estimated Fair

Floor

Ceiling

Swaps

Value Asset

Weighted

Weighted

(Weighted

(Liability)

Period and Type of Contract

Volume

Contract Period

Range (1)

Average (1)

Range (1)

Average (1)

Average) (1)
��
(In thousands)

Natural gas collars

8.9

Bcf

Jul. 2013 - Dec. 2013

$
—

$
5.15

$
6.18-$6.23

$
6.20

$
16,790

Natural gas collars

109.0

Bcf

Jul. 2013 - Dec. 2013

$
3.09-$4.37

$
3.63

$
3.98-$5.02

$
4.27

21,444

Natural gas collars

53.3

Bcf

Jul. 2013 - Dec. 2014

$
3.60-$3.96

$
3.78

$
4.55-$4.59

$
4.57

6,320

Natural gas collars

124.1

Bcf

Jan. 2014 - Dec. 2014

$
3.86-$4.37

$
4.19

$
4.63-$4.80

$
4.70

39,568

Crude oil swaps

552

Mbbl

Jul. 2013 - Dec. 2013

$
101.90

3,733

$
87,855

(1)Natural gas prices are stated per Mcf and crude oil prices are stated per barrel.

The amounts set forth under the ~~net unrealized gain / (loss)~~estimated fair value column in the table above represent our total unrealized net gain position at ~~September~~June 30, ~~2012~~2013 and exclude the impact of ~~non-performance~~nonperformance risk. ~~Non-performance~~Nonperformance risk ~~was~~is primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our ~~non-performance~~nonperformance risk is evaluated using a market credit spread provided by one of our banks.

~~We had natural gas swaps covering 71.9 Bcf, or 40%, of our natural gas production for~~During the first ~~nine~~six months of ~~2012~~2013, crude oil swaps covered 543 Mbbl, or 41% of crude oil production at an average price of ~~$5.22~~$101.90 per ~~Mcf.~~
~~We had natural~~Bbl. Natural gas ~~basis swaps covering 12.8 Bcf, or 7%, of our natural gas production for the first nine months of 2012 at an average price of $(0.25) per Mcf.~~
~~We had crude oil swaps covering 1,249 Mbbl, or 76%, of our crude oil production for the first nine months of 2012 at an average price of $100.00 per Bbl.~~
~~In October 2012, we entered into additional natural gas collar arrangements~~collars with a floor prices ranging from ~~$3.76~~$3.09 to ~~$3.86~~$5.15 per Mcf and ceiling prices ranging from ~~$4.14~~$3.98 to ~~$4.36~~$6.23 per Mcf ~~covering 35,458 Mmcf~~covered 105.9 Bcf, or 60.2%, of our ~~anticipated~~ natural gas production ~~for 2013.~~at an average price of $4.01 per Mcf.

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~~nonperformance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to ~~non-performance~~nonperformance by third parties. Our derivative contract counterparties are Bank of America, Bank of Montreal, ~~BNP Paribas,~~ Goldman Sachs, JPMorgan Chase, and Morgan Stanley.

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.
33

~~Table of Contents~~

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~~amount we would have to ~~acquire~~pay a third party to assume 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 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 fixed-rate notes and credit facility is based on interest rates currently available to us.

We use 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

34

~~Table of Contents~~

June 30, 2013

December 31, 2012

(In thousands)

Carrying
Amount

Estimated Fair
Value

Carrying
Amount

Estimated
Fair Value

Total debt

$
1,142,000

$
1,235,176

$
1,087,000

$
1,213,474

Current maturities

(75,000
)
(75,301
)
(75,000
)
(77,175
)

Long-term debt, excluding current maturities

$
1,067,000

$
1,159,875

$
1,012,000

$
1,136,299

ITEM 4.                         Controls and Procedures

As of the end of the current reported period covered by this report, ~~the Company~~we carried out an evaluation, under the supervision and with the participation of ~~the Company’s~~our management, including ~~the Company’s~~our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of ~~the Company’s~~our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange
29

Table of Contents
Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that ~~the Company’s~~our disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by ~~the Company~~us in the reports that ~~it files~~we file or ~~submits~~submit under the Exchange Act.

There were no changes in ~~the Company’s~~our internal control over financial reporting that occurred during the ~~third~~second quarter of ~~2012~~2013 that have materially affected, or are reasonably likely to materially affect, ~~the Company’s~~our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.                         Legal Proceedings

Legal Matters

The information set forth under the heading “Legal Matters” in Note 76 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.

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 has provided documents and information to the Attorney General’s Office responsive to the request.
Environmental Matters

The information set forth under the heading “Environmental Matters” in Note 76 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.

~~The Company has received a number~~From time to time we receive notices of ~~Notices of Violation~~violation from ~~the Pennsylvania Department of Environmental Protection (PaDEP)~~governmental and regulatory authorities in areas in which we operate 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~~of environmental statutes or the rules and regulations promulgated thereunder. ~~The Company has responded to these Notices of Violation, has remediated the areas in question and is actively cooperating with the PaDEP.~~ While ~~the Company~~we cannot predict with certainty whether these ~~Notices~~notices of ~~Violation~~violation will result in fines and/or penalties, if fines and/or penalties are imposed, ~~the aggregate of these fines and/or penalties could~~they may result in monetary sanctions individually or in the aggregate in excess of $100,000.
On June 27, 2012, the Company received a letter from the United States Army Corps of Engineers (USACE) regarding the Company’s construction of 60,000 linear feet of a natural gas pipeline in Susquehanna County, Pennsylvania in 2008. The USACE is investigating whether construction of certain sections of the pipeline was in compliance with the Clean Water Act. This pipeline was sold to a third party in 2010. We are actively cooperating with the USACE’s investigation regarding this matter.

ITEM 1A.     Risk Factors

For additional information about the risk factors ~~facing the Company,~~that affect us, see Item 1A of Part I of ~~the Company’s~~our Annual Report on Form 10-K for the year ended December 31, ~~2011.~~2012.

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~~we may purchase shares of our common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During the ~~nine~~six months ended ~~September~~June 30, ~~2012, the Company~~2013, we did not repurchase any shares of our common stock. All purchases executed to date have been through open market transactions. The maximum number of remaining shares that may be purchased under the plan as of ~~September~~June 30, ~~2012~~2013 was 9,590,600.

35Item 5.         Other Information
On July 23, 2013, the Board of Directors declared a 2-for-1 stock split of our common stock in the form of a stock dividend. The stock dividend will be distributed on August 14, 2013 to shareholders of record on August 6, 2013.
30

Table of Contents

ITEM 6.                          Exhibits

Exhibit
Number

Description

~~10.1~~
Second Amendment to Amended and Restated Credit Agreement, dated as of July 18, 2012, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities and Bank of Montreal as Co-Syndication Agents, BNP Paribas and Wells Fargo as Co-Documentation Agents, and the Lenders party thereto.
15.1

Awareness letter of PricewaterhouseCoopers LLP

31.1

302 Certification - Chairman, President and Chief Executive Officer

31.2

302 Certification - Vice President, Chief Financial Officer and Treasurer

32.1

906 Certification

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

3631

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~~July 26, ~~2012~~2013
By:
/S/    DAN O. DINGES

Dan O. Dinges

Chairman, President and Chief Executive Officer

~~Chief Executive Officer~~

(Principal Executive Officer)
~~October~~July 26, ~~2012~~2013
By:
/S/    SCOTT C. SCHROEDER

Scott C. Schroeder

Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)
~~October~~July 26, ~~2012~~2013
By:
/S/    TODD M. ROEMER

Todd M. Roemer

Controller

(Principal Accounting Officer)

3732

	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands, except per share amounts)	2013		2012		2013		2012

OPERATING REVENUES
Natural gas	$	368,391	$	201,051	$	662,184	$	407,833
Crude oil and condensate	70,226		57,466		135,881		107,447
Brokered natural gas	8,244		5,149		19,137		18,593
Other	2,819		1,991		5,763		3,920
	449,680		265,657		822,965		537,793
OPERATING EXPENSES
Direct operations	36,978		29,306		68,475		56,626
Transportation and gathering	52,648		33,139		98,869		63,397
Brokered natural gas cost	6,704		4,250		15,093		16,122
Taxes other than income	11,364		10,854		23,051		29,437
Exploration	4,529		16,244		8,553		20,245
Depreciation, depletion and amortization	151,389		114,616		300,042		224,973
General and administrative	21,608		46,872		57,312		69,421
	285,220		255,281		571,395		480,221
Gain / (loss) on sale of assets	276		67,703		180		67,168
INCOME FROM OPERATIONS	164,736		78,079		251,750		124,740
Interest expense and other	16,701		18,495		32,956		35,412
Income before income taxes	148,035		59,584		218,794		89,328
Income tax expense	58,921		23,647		86,856		35,073
NET INCOME	$	89,114	$	35,937	$	131,938	$	54,255

Earnings per share
Basic	$	0.42	$	0.17	$	0.63	$	0.26
Diluted	$	0.42	$	0.17	$	0.62	$	0.26

Weighted-average shares outstanding
Basic	210,349		209,512		210,250		209,320
Diluted	211,745		211,158		211,492		210,974

Dividends per common share	$	0.02	$	0.02	$	0.04	$	0.04

(1)Net of income taxes of $717 and $28,263 for the three months ended June 30, 2013 and 2012, respectively, and $6,762 and $49,863 for the six months ended June 30, 2013 and 2012, respectively. (2) Net of income taxes of $(45,274) and $(7,130) for the three months ended June 30, 2013 and 2012, respectively, and $(21,303) and $(34,653) for the six months ended June 30, 2013 and 2012, respectively. (3) Net of income taxes of $0 and $(43) for the three months ended June 30, 2013 and 2012, respectively, and $0 and $(86) for the six months ended June 30, 2013 and 2012, respectively. (4) Net of income taxes of $(81) and $(2,647) for the three months ended June 30, 2013 and 2012, respectively, and $(161) and $(5,294) for the six months ended June 30, 2013 and 2012, respectively.	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.~~

(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

	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%

(In thousands)
2012	$	28,117
2013	121,920
2014	127,620
2015	127,698
2016	128,071
Thereafter	1,289,626
	$	1,823,052

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

		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

	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

(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)	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

	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%

	Three Months Ended June 30,				Variance

Revenue Variances (In thousands)	2013		2012		Amount		Percent
Natural gas (1)	$	368,391	$	201,393	$	166,998	83%
Crude oil and condensate	70,226		57,466		12,760		22%
Brokered natural gas	8,244		5,149		3,095		60%
Other	2,819		1,991		828		42%

												Three Months Ended June 30,				Variance					Increase (Decrease)
	Three Months Ended September 30,				Variance				Increase (Decrease)
	2012		2011		Amount			Percent	(In thousands)			2013		2012		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
Natural gas (1)												$	4.06	$	3.39	$	0.67		20%		$	61,075
Crude oil and condensate (2)												$	101.39	$	102.61	$	(1.22	)	(1%	)	(840		)

Total									$	(46,887	)										$	60,235
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
Natural gas (Bcf)												90.7		59.2		31.5			53%		$	105,923
Crude oil and condensate (Mbbl)												693		560		133			24%		13,600

Total									$	85,059											$	119,523

									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)	x	1,595	x	1,899	(304		)	(16)%	1,313
Brokered Natural Gas Cost (In thousands)	$	4,258	$	8,204					$	3,946

Brokered Natural Gas Margin (In thousands)	$	980	$	1,263					$	(283	)

	Nine Months Ended September 30,				Variance
Revenue Variances (In thousands)	2012		2011		Amount			Percent
Natural Gas (1)	$	640,178	$	589,926	$	50,252		9%
Crude Oil and Condensate	165,317		79,792		85,525			107%
Brokered Natural Gas	23,831		38,947		(15,116		)	(39)%
Other	5,790		4,124		1,666			40%

	Six Months Ended June 30,				Variance
Revenue Variances (In thousands)	2013		2012		Amount		Percent
Natural gas (1)	$	662,184	$	408,133	$	254,051	62%
Crude oil and condensate	135,881		107,447		28,434		26%
Brokered natural gas	19,137		18,593		544		3%
Other	5,763		3,920		1,843		47%

									Increase										Increase
	Nine Months Ended September 30,				Variance				(Decrease)			Six Months Ended June 30,				Variance			(Decrease)
	2012		2011		Amount			Percent	(In thousands)			2013		2012		Amount		Percent	(In thousands)
Price Variances
Natural Gas (1)	$	3.57	$	4.64	$	(1.07	)	(23)%	$	(188,637	)
Crude Oil and Condensate (2)	$	100.30	$	89.69	$	10.61		12%	17,579
Natural gas (1)												$	3.77	$	3.52	$	0.25	7%	$	43,286
Crude oil and condensate (2)												$	102.65	$	99.76	$	2.89	3%	3,828
Total									$	(171,058	)								$	47,114
Volume Variances
Natural Gas (Mmcf)	178,351		127,206		51,145			40%	$	238,889
Crude Oil and Condensate (Mbbl)	1,648		890		758			85%	67,946
Natural gas (Bcf)												175.8		115.7		60.1		52%	$	210,765
Crude oil and condensate (Mbbl)												1,324		1,077		247		23%	24,606
Total									$	306,835									$	235,371

				Collars											Estimated Fair
				Floor				Ceiling				Swaps			Value Asset
						Weighted				Weighted		(Weighted			(Liability)
Period and Type of Contract	Volume		Contract Period	Range *(1)*		Average *(1)*		Range *(1)*		Average *(1)*		Average) *(1)*		��	(In thousands)
Natural gas collars	8.9	Bcf	Jul. 2013 - Dec. 2013	$	—	$	5.15	$	6.18-$6.23	$	6.20				$	16,790
Natural gas collars	109.0	Bcf	Jul. 2013 - Dec. 2013	$	3.09-$4.37	$	3.63	$	3.98-$5.02	$	4.27				21,444
Natural gas collars	53.3	Bcf	Jul. 2013 - Dec. 2014	$	3.60-$3.96	$	3.78	$	4.55-$4.59	$	4.57				6,320
Natural gas collars	124.1	Bcf	Jan. 2014 - Dec. 2014	$	3.86-$4.37	$	4.19	$	4.63-$4.80	$	4.70				39,568
Crude oil swaps	552	Mbbl	Jul. 2013 - Dec. 2013									$	101.90		3,733

															$	87,855

Exhibit Number		Description


~~10.1~~		Second Amendment to Amended and Restated Credit Agreement, dated as of July 18, 2012, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities and Bank of Montreal as Co-Syndication Agents, BNP Paribas and Wells Fargo as Co-Documentation Agents, and the Lenders party thereto.

15.1		Awareness letter of PricewaterhouseCoopers LLP

31.1		302 Certification - Chairman, President and Chief Executive Officer

31.2		302 Certification - Vice President, Chief Financial Officer and Treasurer

32.1		906 Certification

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

	CABOT OIL & GAS CORPORATION
	(Registrant)

~~October~~July 26, ~~2012~~2013	By:	/S/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
	~~Chief Executive Officer~~
	(Principal Executive Officer)

~~October~~July 26, ~~2012~~2013	By:	/S/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

~~October~~July 26, ~~2012~~2013	By:	/S/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)