Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-Q

 


 

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

 

For the quarterly period ended June 30, 2012

 

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

 

Commission file number 1-10447

 


 

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

 


 

DELAWARE

 

04-3072771

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification Number)

 

Three Memorial City Plaza

840 Gessner Road, Suite 1400, Houston, Texas 77024

(Address of principal executive offices including ZIP code)

 

(281) 589-4600

(Registrant’s telephone number, including area code)

 


 

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

 

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

 

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

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

 

As of July 23, 2012, there were 209,988,641 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 June 30, 2012 and December 31, 2011

3

 

 

Condensed Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2012 and 2011

4

 

 

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

5

 

 

Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2012 and 2011

6

 

 

Notes to the Condensed Consolidated Financial Statements

7

 

 

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

21

 

 

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

22

 

 

Item 3.      Quantitative and Qualitative Disclosures about Market Risk

32

 

 

Item 4.      Controls and Procedures

34

 

 

Part II. Other Information

 

 

 

Item 1.      Legal Proceedings

34

 

 

Item 1A.   Risk Factors

34

 

 

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

35

 

 

Item 6.      Exhibits

36

 

 

Signatures

37

 

2



Table of Contents

 

PART I. FINANCIAL INFORMATION

 

ITEM  1.                           Financial Statements

 

CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

 

 

 

June 30,

 

December 31,

 

(In thousands, except share amounts)

 

2012

 

2011

 

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and Cash Equivalents

 

$

48,641

 

$

29,911

 

Accounts Receivable, Net

 

89,167

 

114,381

 

Income Taxes Receivable

 

 

1,388

 

Inventories

 

11,985

 

21,278

 

Derivative Instruments

 

139,346

 

174,263

 

Other Current Assets

 

6,728

 

4,579

 

Total Current Assets

 

295,867

 

345,800

 

Properties and Equipment, Net (Successful Efforts Method)

 

4,061,674

 

3,934,584

 

Derivative Instruments

 

18,759

 

21,249

 

Other Assets

 

33,892

 

29,860

 

 

 

$

4,410,192

 

$

4,331,493

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Accounts Payable

 

$

237,417

 

$

217,294

 

Income Taxes Payable

 

3,387

 

 

Deferred Income Taxes

 

45,939

 

55,132

 

Accrued Liabilities

 

54,116

 

70,918

 

Total Current Liabilities

 

340,859

 

343,344

 

Postretirement Benefits

 

40,474

 

38,708

 

Long-Term Debt

 

972,000

 

950,000

 

Deferred Income Taxes

 

829,027

 

802,592

 

Asset Retirement Obligation

 

61,952

 

60,142

 

Other Liabilities

 

34,550

 

31,939

 

Total Liabilities

 

2,278,862

 

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 — 209,975,716 Shares and 209,019,458 Shares in 2012 and 2011, respectively

 

20,998

 

20,902

 

Additional Paid-in Capital

 

720,670

 

724,377

 

Retained Earnings

 

1,304,178

 

1,258,291

 

Accumulated Other Comprehensive Income

 

88,833

 

104,547

 

Less Treasury Stock, at Cost:

 

 

 

 

 

404,400 Shares in 2012 and 2011, respectively

 

(3,349

)

(3,349

)

Total Stockholders’ Equity

 

2,131,330

 

2,104,768

 

 

 

$

4,410,192

 

$

4,331,493

 

 

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

 

3



Table of Contents

 

 CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

(In thousands, except per share amounts)

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

OPERATING REVENUES

 

 

 

 

 

 

 

 

 

Natural Gas

 

$

201,051

 

$

200,357

 

$

407,833

 

$

370,455

 

Brokered Natural Gas

 

5,149

 

11,072

 

18,593

 

29,480

 

Crude Oil and Condensate

 

57,466

 

28,042

 

107,447

 

46,634

 

Other

 

1,991

 

1,225

 

3,920

 

3,153

 

 

 

265,657

 

240,696

 

537,793

 

449,722

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Cost

 

4,250

 

9,796

 

16,122

 

25,158

 

Direct Operations

 

29,306

 

22,579

 

56,626

 

49,586

 

Transportation and Gathering

 

33,139

 

16,074

 

63,397

 

28,942

 

Taxes Other Than Income

 

10,854

 

5,877

 

29,437

 

14,028

 

Exploration

 

16,244

 

4,592

 

20,245

 

10,900

 

Depreciation, Depletion and Amortization

 

114,616

 

83,225

 

224,973

 

160,349

 

General and Administrative

 

46,872

 

26,006

 

69,421

 

50,305

 

 

 

255,281

 

168,149

 

480,221

 

339,268

 

Gain / (Loss) on Sale of Assets

 

67,703

 

34,071

 

67,168

 

32,554

 

INCOME FROM OPERATIONS

 

78,079

 

106,618

 

124,740

 

143,008

 

Interest Expense and Other

 

18,495

 

18,044

 

35,412

 

35,411

 

Income Before Income Taxes

 

59,584

 

88,574

 

89,328

 

107,597

 

Income Tax Expense

 

23,647

 

33,897

 

35,073

 

40,034

 

NET INCOME

 

$

35,937

 

$

54,677

 

$

54,255

 

$

67,563

 

 

 

 

 

 

 

 

 

 

 

Earnings Per Share

 

 

 

 

 

 

 

 

 

Basic

 

$

0.17

 

$

0.26

 

$

0.26

 

$

0.32

 

Diluted

 

$

0.17

 

$

0.26

 

$

0.26

 

$

0.32

 

 

 

 

 

 

 

 

 

 

 

Weighted-Average Shares Outstanding

 

 

 

 

 

 

 

 

 

Basic

 

209,512

 

208,528

 

209,320

 

208,408

 

Diluted

 

211,158

 

210,674

 

210,974

 

210,176

 

 

 

 

 

 

 

 

 

 

 

Dividends per common share

 

$

0.02

 

$

0.02

 

$

0.04

 

$

0.03

 

 

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

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

(In thousands)

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

$

35,937

 

$

54,677

 

$

54,255

 

$

67,563

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Reclassification Adjustment for Settled Contracts (1)

 

(44,579

)

(8,155

)

(78,649

)

(16,326

)

Changes in Fair Value of Hedge Positions (2)

 

11,246

 

29,983

 

54,451

 

37,778

 

Defined Benefit Pension and Postretirement Plans:

 

 

 

 

 

 

 

 

 

Amortization of Net Obligation at Transition (3)

 

 

99

 

 

198

 

Amortization of Prior Service Cost (4)

 

67

 

199

 

135

 

398

 

Amortization of Net Loss (5)

 

4,174

 

2,009

 

8,349

 

4,018

 

Foreign Currency Translation Adjustment (6)

 

 

(6

)

 

(8

)

Total Other Comprehensive Income / (Loss)

 

(29,092

)

24,129

 

(15,714

)

26,058

 

Comprehensive Income / (Loss)

 

$

6,845

 

$

78,806

 

$

38,541

 

$

93,621

 

 


(1)            Net of income taxes of $28,263 and $4,998 for the three months ended June 30, 2012 and 2011, respectively, and $49,863 and $10,006 for the six months ended June 30, 2012 and 2011, respectively.

(2)            Net of income taxes of $(7,130) and $(18,331) for the three months ended June 30, 2012 and 2011, respectively, and $(34,653) and $(23,109) for the six months ended June 30, 2012 and 2011, respectively.

(3)            Net of income taxes of $0 and $(59) for the three months ended June 30, 2012 and 2011, respectively, and $0 and $(118) for the six months ended June 30, 2012 and 2011, respectively.

(4)            Net of income taxes of $(43) and $(117) for the three months ended June 30, 2012 and 2011, respectively and $(86) and $(235) for the six months ended June 30, 2012 and 2011, respectively.

(5)            Net of income taxes of $(2,647) and $(1,194) for the three months ended June 30, 2012 and 2011, respectively and $(5,294) and $(2,388) for the six months ended June 30, 2012 and 2011, respectively.

(6)            Net of income taxes of $0 and $3 for the three months ended June 30, 2012 and 2011, respectively and $0 and $3 for the six months ended June 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)

 

 

 

Six Months Ended

 

 

 

June 30,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net Income

 

$

54,255

 

$

67,563

 

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

 

 

 

 

 

Depreciation, Depletion and Amortization

 

224,973

 

160,349

 

Deferred Income Tax Expense

 

27,073

 

36,886

 

(Gain) / Loss on Sale of Assets

 

(67,168

)

(32,554

)

Exploration Expense

 

10,925

 

504

 

Unrealized (Gain) / Loss on Derivative Instruments

 

300

 

886

 

Amortization of Debt Issuance Costs

 

3,334

 

2,253

 

Stock-Based Compensation, Pension and Other

 

26,987

 

26,932

 

Changes in Assets and Liabilities:

 

 

 

 

 

Accounts Receivable, Net

 

25,214

 

(22,826

)

Income Taxes

 

4,775

 

(33,850

)

Inventories

 

9,293

 

5,623

 

Other Current Assets

 

(3,691

)

(1,208

)

Accounts Payable and Accrued Liabilities

 

(28,675

)

10,821

 

Other Assets and Liabilities

 

3,547

 

(678

)

Net Cash Provided by Operating Activities

 

291,142

 

220,701

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Capital Expenditures

 

(411,327

)

(404,214

)

Proceeds from Sale of Assets

 

132,715

 

54,336

 

Investment in Equity Method Investment

 

(2,088

)

 

Net Cash Used in Investing Activities

 

(280,700

)

(349,878

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings from Debt

 

170,000

 

220,000

 

Repayments of Debt

 

(148,000

)

(100,000

)

Dividends Paid

 

(8,368

)

(6,250

)

Capitalized Debt Issuance Costs

 

(5,005

)

(1,025

)

Other

 

(339

)

(183

)

Net Cash Provided by Financing Activities

 

8,288

 

112,542

 

 

 

 

 

 

 

Net Increase / (Decrease) in Cash and Cash Equivalents

 

18,730

 

(16,635

)

Cash and Cash Equivalents, Beginning of Period

 

29,911

 

55,949

 

Cash and Cash Equivalents, End of Period

 

$

48,641

 

$

39,314

 

 

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

 

6



Table of Contents

 

CABOT OIL & GAS CORPORATION

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

 

1. FINANCIAL STATEMENT PRESENTATION

 

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2011 (Form 10-K) filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the expected results for the entire year.

 

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

 

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

 

With respect to the unaudited financial information of the Company as of June 30, 2012 and for the three and six months ended June 30, 2012 and 2011, PricewaterhouseCoopers LLP reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated July 27, 2012 appearing herein states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

 

Recent Accounting Pronouncements

 

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

 

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

 

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

 

7



Table of Contents

 

2. PROPERTIES AND EQUIPMENT, NET

 

Properties and equipment, net are comprised of the following:

 

 

 

June 30,

 

December 31,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

Proved Oil and Gas Properties

 

$

5,376,987

 

$

5,006,846

 

Unproved Oil and Gas Properties

 

456,548

 

478,942

 

Gathering and Pipeline Systems

 

238,802

 

238,660

 

Land, Building and Other Equipment

 

82,464

 

80,908

 

 

 

6,154,801

 

5,805,356

 

Accumulated Depreciation, Depletion and Amortization

 

(2,093,127

)

(1,870,772

)

 

 

$

4,061,674

 

$

3,934,584

 

 

At June 30, 2012, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

 

Divestitures

 

In June 2012, the Company sold a 35% non-operated working interest associated with certain of its Pearsall shale undeveloped leaseholds in south Texas to a wholly-owned subsidiary of Osaka Gas Co., Ltd. (Osaka) for total consideration of approximately $251.1 million, subject to post-closing adjustments.  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 $126.1 million in accordance with a joint development agreement entered into at the closing. The drilling and completion carry will terminate two years after the closing of the transaction. The Company recognized a $67.0 million gain on sale of assets associated with this sale.

 

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

 

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

 

8



Table of Contents

 

3. ADDITIONAL BALANCE SHEET INFORMATION

 

Certain balance sheet amounts are comprised of the following:

 

 

 

June 30,

 

December 31,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

ACCOUNTS RECEIVABLE, NET

 

 

 

 

 

Trade Accounts

 

$

82,915

 

$

111,306

 

Joint Interest Accounts

 

3,703

 

5,417

 

Other Accounts

 

3,561

 

1,003

 

 

 

90,179

 

117,726

 

Allowance for Doubtful Accounts

 

(1,012

)

(3,345

)

 

 

$

89,167

 

$

114,381

 

INVENTORIES

 

 

 

 

 

Natural Gas in Storage

 

$

5,466

 

$

13,513

 

Tubular Goods and Well Equipment

 

6,247

 

7,146

 

Other Accounts

 

272

 

619

 

 

 

$

11,985

 

$

21,278

 

OTHER CURRENT ASSETS

 

 

 

 

 

Prepaid Balances and Other

 

4,821

 

2,345

 

Restricted Cash

 

1,907

 

2,234

 

 

 

$

6,728

 

$

4,579

 

OTHER ASSETS

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

11,146

 

$

10,838

 

Debt Issuance Cost

 

19,351

 

17,680

 

Equity Method Investment

 

2,078

 

 

Other Accounts

 

1,317

 

1,342

 

 

 

$

33,892

 

$

29,860

 

ACCOUNTS PAYABLE

 

 

 

 

 

Trade Accounts

 

$

25,406

 

$

18,253

 

Natural Gas Purchases

 

3,062

 

3,012

 

Royalty and Other Owners

 

47,094

 

48,113

 

Accrued Capital Costs

 

153,061

 

138,122

 

Taxes Other Than Income

 

791

 

2,076

 

Drilling Advances

 

344

 

1,489

 

Wellhead Gas Imbalances

 

2,375

 

2,312

 

Other Accounts

 

5,284

 

3,917

 

 

 

$

237,417

 

$

217,294

 

ACCRUED LIABILITIES

 

 

 

 

 

Employee Benefits

 

$

11,375

 

$

26,035

 

Pension and Postretirement Benefits

 

4,838

 

6,331

 

Taxes Other Than Income

 

12,647

 

12,297

 

Interest Payable

 

23,557

 

24,701

 

Derivative Contracts

 

193

 

385

 

Other Accounts

 

1,506

 

1,169

 

 

 

$

54,116

 

$

70,918

 

OTHER LIABILITIES

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

20,883

 

$

20,187

 

Derivative Contracts

 

951

 

 

Other Accounts

 

12,716

 

11,752

 

 

 

$

34,550

 

$

31,939

 

 

9


 


Table of Contents

 

4. DEBT AND CREDIT AGREEMENTS

 

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

 

(In thousands)

 

June 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

 

210,000

 

188,000

 

 

 

$

972,000

 

$

950,000

 

 

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

 

 

 

Debt Percentage

 

 

 

<25%

 

>25% <50%

 

>50% <75%

 

>75% <90%

 

>90%

 

Eurodollar Loans

 

1.50

%

1.75

%

2.00

%

2.25

%

2.50

%

ABR Loans

 

0.50

%

0.75

%

1.00

%

1.25

%

1.50

%

 

The amended credit facility currently provides 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 June 30, 2012, the Company had $210.0 million of borrowings outstanding under the amended credit facility at a weighted-average interest rate of 3.3% and $689.0 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 partnerships 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 and the right to acquire a 25% equity interest in the project, 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 25% equity interest and agreed to

 

10



Table of Contents

 

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 six months of 2012, the Company made an initial contribution of $2.1 million to fund the initial costs associated with the project. The Company’s net book value in this equity investment was $2.1 million as of June 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 six 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 options and stock appreciation rights were exercised and stock awards were vested at the end of the applicable period.

 

The following is a calculation of basic and diluted weighted-average shares outstanding:

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

(In thousands)

 

2012

 

2011

 

2012

 

2011

 

Weighted-Average Shares - Basic

 

209,512

 

208,528

 

209,320

 

208,408

 

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

 

1,646

 

2,146

 

1,654

 

1,768

 

Weighted-Average Shares - Diluted

 

211,158

 

210,674

 

210,974

 

210,176

 

 

 

 

 

 

 

 

 

 

 

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

 

122

 

2

 

179

 

144

 

 

7. COMMITMENTS AND CONTINGENCIES

 

Transportation Agreements

 

During the first six months of 2012, the Company entered into a liquids transportation agreement that is expected to commence in the fourth quarter of 2012. The Company’s total future minimum transportation commitments as of June 30, 2012 are as follows:

 

(In thousands)

 

 

 

2012

 

$

47,341

 

2013

 

120,765

 

2014

 

127,620

 

2015

 

127,698

 

2016

 

128,071

 

Thereafter

 

1,289,641

 

 

 

$

1,841,136

 

 

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

 

Legal Matters

 

Preferential Purchase Right Litigation

 

In September 2005, the Company and Linn Energy, LLC were sued by Power Gas Marketing & Transmission, Inc. in the Court of Common Pleas of Indiana County, Pennsylvania. The lawsuit seeks unspecified damages arising out of the Company’s 2003 sale of oil and gas properties located in Indiana County, Pennsylvania, to Linn Energy, LLC. The plaintiff alleges breach of a preferential

 

11



Table of Contents

 

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

 

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

 

Other

 

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

 

Contingency Reserves

 

When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters in which reserves have been established. The Company believes that any such amount above the amounts accrued is not material to the Condensed Consolidated Financial Statements. Future changes in facts and circumstances 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. Prior to this settlement, the Company and PaDEP had entered into a number of consent orders, beginning in November 2009, requiring the Company to pay civil penalties and to undertake various remedial actions, including at various times making available potable water to the 14 households, plugging and abandoning three vertical natural gas wells in a nine square mile area in Susquehanna County and postponing the drilling of new natural gas wells in the area of concern until certain terms of the consent orders were fulfilled. Under the CO&SA, among other things, the Company agreed to place a total of $4.2 million into escrow accounts for the benefit of each of the identified households, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, perform remedial measures for two natural gas wells in the area of concern, provide pressure, water quality and water well headspace data to the PaDEP and offer water treatment to the households. The CO&SA settled all outstanding issues and claims that are known and that could have been brought against the Company by the PaDEP relating to the natural gas wells in the affected area and all prior consent orders. It also allows the Company to seek to begin hydraulic fracturing and to commence drilling new wells in the affected areas after providing the PaDEP with certain data and information. Under the CO&SA, the Company has no obligation to connect the impacted water supplies to a community public water system.

 

On January 11, 2011, certain of the affected households appealed the CO&SA to the Pennsylvania Environmental Hearing Board (PEHB).

 

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. The Company requested PaDEP approval to resume hydraulic fracturing and new natural gas well drilling operations in the affected area, along with a request to cease temporary water deliveries to the affected households. On October 18, 2011, the PaDEP concurred that temporary water deliveries to the property owners are no longer necessary.

 

12



Table of Contents

 

On November 18, 2011, certain of the affected households appealed to the PEHB the PaDEP’s October 18, 2011 determination that temporary water deliveries were no longer necessary to the property owners and on November 23, 2011 filed a Petition for Supersedeas in the appeal. On December 9, 2011, the PEHB denied the Petition for Supersedeas and consolidated the appeal of the CO&SA with the appeal of the October 18, 2011 determination. A hearing on the consolidated matter is expected to occur in the second half of 2012.

 

As of June 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, paid $2.3 million (through the escrow process) to ten of the affected households and accrued a $1.9 million settlement liability that represents the unpaid escrow balance, which is included in Other Liabilities in the Condensed Consolidated Balance Sheet.

 

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

 

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

 

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

 

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and not subjecting the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. As of June 30, 2012, the Company had 49 derivative contracts open: 23 natural gas price swap arrangements, six natural gas basis swap arrangements, 14 natural gas collar arrangements and six crude oil swap arrangements. During the first six months of 2012, the Company entered into 12 new derivative contracts covering anticipated crude oil production for 2012 and 2013 and natural gas production for 2013.

 

As of June 30, 2012, the Company had the following outstanding commodity derivatives:

 

Commodity and Derivative Type

 

Weighted-Average Contract Price

 

Volume

 

Contract Period

 

Derivatives Designated as Hedging Instruments

 

 

 

 

 

 

 

Natural Gas Swaps

 

$5.22  per Mcf

 

48,261 Mmcf

 

Jul. 2012 - Dec. 2012

 

Natural Gas Collars

 

$3.09 Floor / $4.12 Ceiling  per Mcf

 

35,457 Mmcf

 

Jan. 2013 - Dec. 2013

 

Natural Gas Collars

 

$5.15 Floor / $6.20 Ceiling  per Mcf

 

17,729 Mmcf

 

Jan. 2013 - Dec. 2013

 

Crude Oil Swaps

 

$100.45   per Bbl

 

1,041  Mbbl

 

Jul. 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

 

8,568 Mmcf

 

Jul. 2012 - Dec. 2012

 

 

The change in fair value of derivatives designated as hedges that is effective is recorded to Accumulated Other Comprehensive Income / (Loss) in Stockholders’ Equity in the Condensed Consolidated Balance Sheet. The ineffective portion of the change in fair value of derivatives designated as hedges, if any, and the change in fair value of derivatives not designated as hedges are recorded currently in earnings as a component of Natural Gas Revenue and Crude Oil and Condensate Revenue, as appropriate, in the Condensed Consolidated Statement of Operations.

 

13



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

 

June 30, 2012

 

December 31, 2011

 

Derivatives Designated as Hedging Instruments

 

 

 

 

 

 

 

Commodity Contracts

 

Derivative Instruments (current assets)

 

$

141,230

 

$

177,389

 

Commodity Contracts

 

Accrued Liabilities

 

(193

)

(385

)

Commodity Contracts

 

Derivative Instruments (non-current assets)

 

18,759

 

21,249

 

Commodity Contracts

 

Other Liabilities

 

(951

)

 

 

 

 

 

158,845

 

198,253

 

Derivatives Not Designated as Hedging Instruments

 

 

 

 

 

 

 

Commodity Contracts

 

Derivative Instruments (current assets)

 

(1,884

)

(3,126

)

 

 

 

 

$

156,961

 

$

195,127

 

 

At June 30, 2012 and December 31, 2011, unrealized gains of $158.9 million ($97.2 million, net of tax) and $198.3 million ($121.4 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income / (Loss). Based upon estimates at June 30, 2012, the Company expects to reclassify $86.3 million in after-tax income associated with its commodity hedges from Accumulated Other Comprehensive Income / (Loss) to the Condensed Consolidated Statement of Operations over the next 12 months.

 

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

 

 

 

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

 

Location of Gain (Loss)

 

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

 

Derivatives Designated as
Hedging Instruments

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

Reclassified from
Accumulated OCI into

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

(In thousands)

 

2012

 

2011

 

2012

 

2011

 

Income

 

2012

 

2011

 

2012

 

2011

 

Commodity Contracts

 

$

18,376

 

$

48,314

 

$

89,104

 

$

60,887

 

Natural Gas Revenues

 

$

69,732

 

$

13,667

 

$

126,728

 

$

27,148

 

 

 

 

 

 

 

 

 

 

 

Crude Oil and Condensate Revenues

 

3,110

 

(514

)

1,784

 

(816

)

 

 

 

 

 

 

 

 

 

 

 

 

$

72,842

 

$

13,153

 

$

128,512

 

$

26,332

 

 

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

 

Derivatives Not Designated as
Hedging Instruments

 

Location of Gain (Loss) Recognized

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

(In thousands)

 

in Income on Derivative

 

2012

 

2011

 

2012

 

2011

 

Commodity Contracts

 

Natural Gas Revenues

 

$

(342

)

$

(903

)

$

(300

)

$

(886

)

 

Additional Disclosures about Derivative Instruments and Hedging Activities

 

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

 

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

 

14


 


Table of Contents

 

9. FAIR VALUE MEASUREMENTS

 

ASC 820, “Fair Value Measurements and Disclosures,” established a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by generally accepted accounting principles (GAAP) to be measured at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

 

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. ASC 820 establishes formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.

 

The Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values. For further information regarding the fair value hierarchy, refer to Note 13 of the Notes to the Consolidated Financial Statements in the 2011 Form 10-K.

 

Non-Financial Assets and Liabilities

 

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of long-lived assets, at fair value on a nonrecurring basis. As none of the Company’s non-financial assets and liabilities were impaired as of June 30, 2012 and 2011 and no other assets or liabilities were required to be measured at fair value on a non-recurring basis, additional disclosures are not provided.

 

Financial Assets and Liabilities

 

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis:

 

(In thousands)

 

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

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

Balance as of
June 30, 2012

 

Assets

 

 

 

 

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

11,146

 

$

 

$

 

$

11,146

 

Derivative Contracts

 

 

27,748

 

130,357

 

158,105

 

Total Assets

 

$

11,146

 

$

27,748

 

$

130,357

 

$

169,251

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

20,883

 

$

 

$

 

$

20,883

 

Derivative Contracts

 

 

 

 

1,144

 

1,144

 

Total Liabilities

 

$

20,883

 

$

 

$

1,144

 

$

22,027

 

 

15



Table of Contents

 

(In thousands)

 

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

 

Significant Other
Observable Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

Balance as of
December 31,
2011

 

Assets

 

 

 

 

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

10,838

 

$

 

$

 

$

10,838

 

Derivative Contracts

 

 

 

195,512

 

195,512

 

Total Assets

 

$

10,838

 

$

 

$

195,512

 

$

206,350

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Rabbi Trust Deferred Compensation Plan

 

$

20,187

 

$

 

$

 

$

20,187

 

Derivative Contracts

 

 

 

385

 

385

 

Total Liabilities

 

$

20,187

 

$

 

$

385

 

$

20,572

 

 

The Company’s investments associated with its Rabbi Trust Deferred Compensation Plan consist of mutual funds and deferred shares of the Company’s common stock that are publicly traded and for which market prices are readily available.

 

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using an income approach that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, basis differentials, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term, as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions, while non-performance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

 

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors.  An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

 

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

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

(In thousands)

 

2012

 

2011

 

2012

 

2011

 

Balance at beginning of period

 

$

218,942

 

$

14,158

 

$

195,127

 

$

14,746

 

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

 

 

 

 

 

 

 

 

 

Included in Earnings (1)

 

69,390

 

12,249

 

126,428

 

25,446

 

Included in Other Comprehensive Income

 

(90,234

)

35,161

 

(67,541

)

34,555

 

Settlements

 

(68,885

)

(13,153

)

(125,186

)

(26,332

)

Transfers In and/or Out of Level 3

 

 

 

385

 

 

Balance at end of period

 

$

129,213

 

$

48,415

 

$

129,213

 

$

48,415

 

 


(1) Unrealized losses of $0.3 million and $0.9 for the three months ended June 30, 2012 and 2011, respectively, and unrealized losses of $0.3 million and $0.9 million for the six months ended June 30, 2012 and 2011, respectively, were included in Natural Gas Revenues in the Condensed Consolidated Statement of Operations.

 

There were no transfers between Level 1 and Level 2 measurements for the six months ended June 30, 2012 and 2011.

 

Fair Value of Other Financial Instruments

 

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

 

16



Table of Contents

 

The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all fixed-rate notes and the credit facility is based on interest rates currently available to the Company.  The Company’s long-term debt is valued using an income approach and classified as Level 3 in the fair value hierarchy.

 

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

 

 

 

June 30, 2012

 

December 31, 2011

 

(In thousands)

 

Carrying
Amount

 

Estimated Fair
Value

 

Carrying
Amount

 

Estimated Fair
Value

 

Long-Term Debt

 

$

972,000

 

$

1,115,085

 

$

950,000

 

$

1,082,531

 

 

10. ACCUMULATED COMPREHENSIVE INCOME / (LOSS)

 

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

 

(In thousands)

 

Net Gains /
(Losses) on Cash
Flow Hedges

 

Defined Benefit
Pension and
Postretirement
Plans

 

Total

 

Balance at December 31, 2011

 

$

121,358

 

$

(16,811

)

$

104,547

 

Net change in unrealized gain on cash flow hedges, net of taxes of $15,210

 

(24,198

)

 

(24,198

)

Net change in defined benefit pension and postretirement plans, net of taxes of $(5,380)

 

 

8,484

 

8,484

 

Balance at June 30, 2012

 

$

97,160

 

$

(8,327

)

$

88,833

 

 

11. PENSION AND OTHER POSTRETIREMENT BENEFITS

 

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

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

(In thousands)

 

2012

 

2011

 

2012

 

2011

 

Qualified and Non-Qualified Pension Plans

 

 

 

 

 

 

 

 

 

Interest Cost

 

$

461

 

$

800

 

$

922

 

$

1,601

 

Expected Return on Plan Assets

 

(874

)

(1,160

)

(1,748

)

(2,320

)

Settlement

 

7,111

 

 

7,111

 

 

Amortization of Prior Service Cost

 

110

 

316

 

221

 

633

 

Amortization of Net Loss

 

6,541

 

3,062

 

13,083

 

6,124

 

Net Periodic Pension Cost

 

$

13,349

 

$

3,018

 

$

19,589

 

$

6,038

 

 

 

 

 

 

 

 

 

 

 

Postretirement Benefits Other than Pension Plans

 

 

 

 

 

 

 

 

 

Current Period Service Cost

 

$

523

 

$

334

 

$

1,046

 

$

669

 

Interest Cost

 

418

 

468

 

836

 

935

 

Amortization of Net Loss

 

280

 

141

 

560

 

282

 

Amortization of Net Obligation at Transition

 

 

158

 

 

316

 

Total Postretirement Benefit Cost

 

$

1,221

 

$

1,101

 

$

2,442

 

$

2,202

 

 

Termination and Amendment of Qualified Pension Plan

 

In July 2010, the Company notified its employees of its plan to terminate its qualified pension plan, with the plan and its related trust to be liquidated following appropriate filings with the Pension Benefit Guaranty Corporation and Internal Revenue Service, effective

 

17



Table of Contents

 

September 30, 2010. The Company then amended and restated the qualified pension plan to freeze benefit accruals, to provide for termination of the plan, to allow for an early retirement enhancement to be available to all active participants as of September 30, 2010 regardless of their age and years of service as of that date, and to make certain changes that were required or made desirable as a result of developments in the law.

 

On March 14, 2012, the Internal Revenue Service provided the Company with a favorable determination letter for the termination of the Company’s qualified pension plan. In June and July 2012, the Company made final contributions of $9.6 million and $3.6 million, respectively, to fund the liquidation of the trust under the qualified pension plan. As of July 13, 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.

 

12. STOCK-BASED COMPENSATION

 

Stock-based compensation expense (including the supplemental employee incentive plan) during the first six months of 2012 and 2011 was $13.1 million and $19.3 million, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations. Stock-based compensation expense in the second quarter of 2012 and 2011 was $11.4 million and $11.2 million, respectively.

 

Restricted Stock Awards

 

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

 

Restricted Stock Units

 

During the first six months of 2012, 38,304 restricted stock units were granted to non-employee directors of the Company with a grant date per share value of $36.55. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and will be issued when the director ceases to be a director of the Company.

 

Stock Appreciation Rights

 

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

 

18



Table of Contents

 

Awards Based on Performance Conditions. The performance awards based on internal metrics had a grant date per share value of $35.18, which is based on the average of the high and low stock price on the grant date. These awards represent the right to receive up to 100% of the award in shares of common stock.  Of the 401,141 performance awards based on internal metrics, 117,461 shares have a three-year graded performance period. For these shares, one-third of the shares are issued on each anniversary date following the date of grant, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date. If the Company does not meet this metric for the applicable period, then the portion of the performance shares that would have been issued on that date will be forfeited.

 

For the remaining 283,680 performance awards, the actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the 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 June 30, 2012, it is considered probable that criteria for these awards will be met.

 

Awards Based on Market Conditions. The 117,461 performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three-year performance period. These performance shares have both an equity and liability component. The equity portion of the 2012 awards was valued on the grant date (February 16, 2012) and was not marked to market. The liability portion of the awards was valued as of June 30, 2012 on a mark-to-market basis.

 

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

 

 

 

Grant Date

 

June 30, 2012

 

Value per Share

 

$

28.31

 

$23.53 - $38.39

 

Assumptions:

 

 

 

 

 

Stock Price Volatility

 

46.7

%

45.8% - 49.3

%

Risk Free Rate of Return

 

0.4

%

0.2% - 0.4

%

Expected Dividend Yield

 

0.2

%

0.2

%

 

Supplemental Employee Incentive Plan

 

On May 1, 2012, the Company’s Board of Directors adopted a new Supplemental Employee Incentive Plan (“Plan”) to replace the previously adopted supplemental employee incentive plan that expired on June 30, 2012.  There were no amounts paid under the expired plan. The Plan commenced on July 1, 2012 and is intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time, non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price. The Plan will be accounted for as liability awards under ASC 718, “Compensation — Stock Compensation.”

 

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

 

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

 

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

 

19



Table of Contents

 

13. ASSET RETIREMENT OBLIGATION

 

Activity related to the Company’s asset retirement obligation during the six months ended June 30, 2012 is as follows:

 

(In thousands)

 

 

 

Carrying amount of asset retirement obligations at beginning of period

 

$

60,142

 

Liabilities incurred

 

1,054

 

Liabilities settled

 

(748

)

Accretion expense

 

1,504

 

Carrying amount of asset retirement obligations at end of period

 

$

61,952

 

 

14. INCREASE IN AUTHORIZED SHARES

 

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

 

20



Table of Contents

 

Report of Independent Registered Public Accounting Firm

 

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

 

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of June 30, 2012, and the related condensed consolidated statements of operations and comprehensive income for the three and six month periods ended June 30, 2012 and 2011, and the condensed consolidated statement of cash flows for the six month periods ended June 30, 2012 and 2011. These interim financial statements are the responsibility of the Company’s management.

 

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

 

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

 

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2011, and the related consolidated statements of operations, stockholders’ equity, comprehensive income and of cash flows for the year then ended (not presented herein), and in our report dated February 28, 2012, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet information as of December 31, 2011, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

 

/s/ PricewaterhouseCoopers LLP

 

Houston, Texas

July 27, 2012

 

21



Table of Contents

 

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

 

The following review of operations for the three and six month periods ended June 30, 2012 and 2011 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Corporation Annual Report on Form 10-K for the year ended December 31, 2011 (Form 10-K).

 

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

 

Overview

 

On an equivalent basis, our production for the six months ended June 30, 2012 increased by 48% compared to the six months ended June 30, 2011. For the six months ended June 30, 2012, we produced 122.4 Bcfe compared to 82.7 Bcfe for the six months ended June 30, 2011. Natural gas production was 115.7 Bcf and crude oil/condensate/NGL production was 1,131 Mbbls for the first six months of 2012. Natural gas production increased by 45% when compared to the first six months of 2011, which had production of 79.5 Bcf. This increase was primarily a result of increased production in the Marcellus shale associated with our drilling program and upgrades to the Lathrop compressor station in Susquehanna County, Pennsylvania, which included the commissioning of new compression during the latter part of the first quarter in 2011. Partially offsetting the production increase in Marcellus shale were decreases in production primarily in east Texas due to reduced drilling activity and normal production declines, the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011 and a continued shift from gas to oil projects outside of the Marcellus shale. Crude oil/condensate/NGL production increased by 114%, to 1,131 Mbbls, when compared to the first six months of 2011, which had production of 529 Mbbls. This increase was primarily the result of increased production associated with our Eagle Ford shale drilling program in south Texas and the Marmaton oil play in Oklahoma.

 

Our average realized natural gas price for the first six months of 2012 was $3.52 per Mcf, 25% lower than the $4.67 per Mcf price realized in the first six months of 2011. Our average realized crude oil price for the first six months of 2012 was $99.76 per Bbl, 9% higher than the $91.80 per Bbl price realized in the first six months of 2011. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to “Results of Operations” below. Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes or future revenues.

 

Natural gas commodity prices have decreased from an average price of $4.04 per Mmbtu in 2011 to an average price of $2.47 per Mmbtu for the first six months of 2012 based on the first of the month Henry Hub index price per Mmbtu. Natural gas commodity prices were $3.36 per Mmbtu in December 2011 and have continued to decline to $2.77 per Mmbtu in July 2012. Although natural gas prices have increased since the first quarter of 2012, future declines in natural gas commodity prices or quantities could have a negative impact on our financial results.

 

Operating revenues for the six months ended June 30, 2012 increased by $88.1 million, or 20%, from the six months ended June 30, 2011. Natural gas revenues, excluding unrealized gains/losses from the change in fair value of our derivatives not designated as hedges, increased by $36.8 million, or 10%, for the six months ended June 30, 2012 as compared to the six months ended June 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 $60.8 million, or 130%, for the first six months of 2012 as compared to the first six months of 2011, due to increased crude oil production and realized crude oil prices. Brokered natural gas revenues decreased by $10.9 million, or 37%, due to a decreased sales price and decreased brokered volumes.

 

In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. For 2012, we expect to spend approximately $900 to $950 million in capital and exploration expenditures, using proceeds from the sale of assets to supplement our cash flows from operations in order to fund incremental capital and exploration expenditures above previously budgeted amounts. We believe our existing cash on hand, operating cash flows, borrowings under our credit facility, if required, and proceeds from the sale of assets will be more than sufficient to fund our capital and exploration spending in the current year. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly. For the six months ended June 30, 2012, we invested approximately $436.5 million in our exploration and development efforts.

 

22



Table of Contents

 

During the first six months of 2012, we drilled 66 gross wells (62 development, one exploratory and three extension wells) with a success rate of 99% compared to 52 gross wells (45 development, four exploratory and three extension wells) with a success rate of 100% for the comparable period of the prior year. For the full year of 2012, we plan to drill approximately 150 to 170 gross wells.

 

Our 2012 strategy will remain consistent with 2011. While we consider acquisitions from time to time, 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, to a lesser extent, 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.

 

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 six months ended June 30, 2012 were funds generated from the sale of natural gas and crude oil production (including realizations from our derivative instruments), proceeds from the sale of assets and net borrowings under our credit facility. These cash flows were primarily used to fund our capital and exploration expenditures and payment of dividends. See below for additional discussion and analysis of cash flow.

 

We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices, changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, as described in our Form 10-K and other filings with the Securities and Exchange Commission, have also influenced prices throughout the recent years. Commodity prices continue to experience increased volatility. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on revenues.

 

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

 

 

 

Six Months Ended

 

 

 

June 30,

 

(In thousands)

 

2012

 

2011

 

Cash Flows Provided by Operating Activities

 

$

291,142

 

$

220,701

 

Cash Flows Used in Investing Activities

 

(280,700

)

(349,878

)

Cash Flows Provided by Financing Activities

 

8,288

 

112,542

 

Net Increase / (Decrease) in Cash and Cash Equivalents

 

$

18,730

 

$

(16,635

)

 

Operating Activities.  Net cash provided by operating activities in the first six months of 2012 increased by $70.4 million over the first six months of 2011. This increase was primarily due to higher operating revenues that outpaced the increase in operating expenses (excluding non-cash expenses) coupled with favorable 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 crude oil prices partially offset by lower realized natural gas prices. Equivalent production volumes increased by 48% for the six months ended June 30, 2012 compared to the six months ended June 30, 2011 as a result of higher natural gas and crude oil production. Average realized natural gas prices decreased by 25% for the first six months of 2012 compared to the first six months of 2011. Average realized crude oil prices increased by 9% compared to the same period.

 

See “Results of Operations” for additional information relative to commodity price, production and operating expense movements. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Realized prices may decline in future periods.

 

Investing Activities. Cash flows used in investing activities decreased by $69.2 million for the first six months of 2012 compared to the first six months of 2011. The decrease was primarily due an increase of $78.4 million in proceeds from sale of assets, partially

 

23



Table of Contents

 

offset by increases of $7.1 million in capital and exploration expenditures and $2.1 million of capital contributions associated with our equity method investment.

 

Financing Activities. Cash flows provided by financing activities decreased by $104.3 million from the first six months of 2011 to the first six months of 2012. This decrease was primarily due to $98.0 million lower net borrowings ($50.0 million decrease in borrowings and $48.0 million increase in repayments of debt), $4.0 million higher debt issuance costs associated with our amended credit facility and $2.1 million higher dividend payments.

 

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

 

At June 30, 2012, we had $210.0 million of borrowings outstanding under the amended credit facility at a weighted-average interest rate of 3.3% and $689.0 million available for future borrowings.

 

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

 

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

 

Capitalization

 

Information about our capitalization is as follows:

 

 

 

June 30,

 

December 31,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

Debt (1)  

 

$

972,000

 

$

950,000

 

Stockholders’ Equity

 

2,131,330

 

2,104,768

 

Total Capitalization

 

$

3,103,330

 

$

3,054,768

 

 

 

 

 

 

 

Debt to Capitalization

 

31

%

31

%

 

 

 

 

 

 

Cash and Cash Equivalents

 

$

48,641

 

$

29,911

 

 


(1) Includes $210.0 million and $188.0 million of borrowings outstanding under our revolving credit facility at June 30, 2012 and December 31, 2011, respectively.

 

During the six months ended June 30, 2012, we paid dividends of $8.4 million ($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, when necessary, borrowings under our revolving credit facility. We budget these capital expenditures based on our current estimate of future commodity prices and projected cash flows for the year.

 

24



Table of Contents

 

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

 

 

 

Six Months Ended

 

 

 

June 30,

 

(In thousands)

 

2012

 

2011

 

Capital Expenditures

 

 

 

 

 

Drilling and Facilities

 

$

363,756

 

$

345,818

 

Leasehold Acquisitions

 

47,399

 

30,016

 

Pipeline and Gathering

 

(466

)

5,747

 

Other

 

5,562

 

4,967

 

 

 

416,251

 

386,548

 

Exploration Expense

 

20,245

 

10,900

 

Total

 

$

436,496

 

$

397,448

 

 

For the full year of 2012, we plan to drill approximately 150 to 170 gross wells. This 2012 drilling program includes between $900 to $950 million in total planned capital and exploration expenditures, using proceeds from the sale of assets to supplement our cash flows from operations in order to fund incremental capital and exploration expenditures above previously budgeted amounts. See “Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease the capital and exploration expenditures accordingly.

 

Contractual Obligations

 

We have various contractual obligations in the normal course of our operations. For further information, please refer to “Transportation Agreements” under Note 7 in the Notes to the Condensed Consolidated Financial Statements for changes in our commitments in the first six months of 2012. There have been no other material changes to our contractual obligations described under “Gas Transportation Agreements”, “Drilling Rig Commitments”, “Hydraulic Fracturing Services Commitments” and “Lease Commitments” as disclosed in Note 7 in the Notes to Consolidated Financial Statements included in our 2011 Form 10-K.

 

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

 

Critical Accounting Policies and Estimates

 

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted and adopted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our 2011 Form 10-K for further discussion of our critical accounting policies.

 

Recent Accounting Pronouncements

 

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

 

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income.” ASU No. 2011-05 was amended in December 2011 by ASU No. 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU No. 2011-05.”  ASU No. 2011-12 defers only those changes in ASU No. 2011-05 that relate to the presentation of reclassification adjustments. All other requirements in ASU No. 2011-05 are not affected by ASU No. 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or

 

25



Table of Contents

 

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

 

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

 

Results of Operations

 

Second Quarters of 2012 and 2011 Compared

 

We reported net income in the second quarter of 2012 of $35.9 million, or $0.17 per share, compared to net income in the second quarter of 2011 of $54.7 million, or $0.26 per share, for a decrease of $18.8 million. Operating revenues increased by $25.0 million due to increased natural gas and crude oil and condensate revenues, partially offset by decreased brokered natural gas revenues. Operating expenses increased by $87.1 million primarily due to an increase in depreciation, depletion, and amortization, transportation and gathering expenses, general and administrative expense, exploration expense, direct operating expenses and taxes other than income, partially offset by decreased brokered natural gas cost. In addition, net income was impacted during the second quarter by an increase in gain on sale of assets and lower income tax expense.

 

Revenue, Price and Volume Variances

 

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

 

 

 

Three Months Ended June 30,

 

Variance

 

Revenue Variances (In thousands)

 

2012

 

2011

 

Amount

 

Percent

 

Natural Gas (1)

 

$

201,393

 

$

201,260

 

$

133

 

0

%

Brokered Natural Gas

 

5,149

 

11,072

 

(5,923

)

(53

)%

Crude Oil and Condensate

 

57,466

 

28,042

 

29,424

 

105

%

Other

 

1,991

 

1,225

 

766

 

63

%

 


(1) Natural Gas Revenues exclude the unrealized loss of $0.3 million and $0.9 million from the change in fair value of our derivatives not designated as hedges in 2012 and 2011, respectively.

 

 

 

 

 

 

 

 

 

 

 

Increase

 

 

 

Three Months Ended June 30,

 

Variance

 

(Decrease)

 

 

 

2012

 

2011

 

Amount

 

Percent

 

(In thousands)

 

Price Variances

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (1)

 

$

3.39

 

$

4.67

 

$

(1.28

)

(27

)%

$

(75,042

)

Crude Oil and Condensate (2)

 

$

102.61

 

$

95.17

 

$

7.44

 

8

%

4,197

 

Total

 

 

 

 

 

 

 

 

 

$

(70,845

)

Volume Variances

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Mmcf)

 

59,225

 

43,128

 

16,097

 

37

%

$

75,175

 

Crude Oil and Condensate (Mbbl)

 

560

 

295

 

265

 

90

%

25,227

 

Total

 

 

 

 

 

 

 

 

 

$

100,402

 

 


(1) These prices include the realized impact of derivative instrument settlements, which increased the price by $1.18 per Mcf in 2012 and $0.32 per Mcf in 2011.

(2) These prices include the realized impact of derivative instrument settlements, which increased the price by $5.55 per Bbl in 2012 and decreased the price by $1.74 per Bbl in 2011.

 

26



Table of Contents

 

Natural Gas Revenues

 

The increase in natural gas revenues of $0.1 million, excluding the impact of unrealized losses, is due to increased production during the second quarter of 2012, partially offset by lower realized natural gas prices. The increased production was primarily a result of increased production in the Marcellus shale associated with our drilling program, partially offset by decreases in production primarily in east Texas due to reduced drilling activity and normal production declines, the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011 and a continued shift from gas to oil projects outside of the Marcellus shale. The previously reported fire at the Lathrop compressor station in late March 2012 had no material impact on our natural gas revenues.

 

Crude Oil and Condensate Revenues

 

The increase in crude oil and condensate revenues of $29.4 million is primarily due to increased production associated with our Eagle Ford shale drilling program in south Texas and the Marmaton oil play in Oklahoma, coupled with higher realized oil prices.

 

Brokered Natural Gas Revenue and Cost

 

 

 

 

 

 

 

 

 

 

 

Price and

 

 

 

Three Months Ended

 

 

 

Volume

 

 

 

June 30,

 

Variance

 

Variances

 

 

 

2012

 

2011

 

Amount

 

Percent

 

(In thousands)

 

Brokered Natural Gas Sales

 

 

 

 

 

 

 

 

 

 

 

Sales Price ($/Mcf)

 

$

2.82

 

$

5.10

 

$

(2.28

)

(45

)%

$

(4,158

)

Volume Brokered (Mmcf)

 

x

1,827

 

x

2,173

 

(346

)

(16

)%

(1,765

)

Brokered Natural Gas Revenues (In thousands)

 

$

5,149

 

$

11,072

 

 

 

 

 

$

(5,923

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Purchases

 

 

 

 

 

 

 

 

 

 

 

Purchase Price ($/Mcf)

 

$

2.33

 

$

4.51

 

$

(2.18

)

(48

)%

$

3,986

 

Volume Brokered (Mmcf)

 

x

1,827

 

x

2,173

 

(346

)

(16

)%

1,560

 

Brokered Natural Gas Cost (In thousands)

 

$

4,250

 

$

9,796

 

 

 

 

 

$

5,546

 

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Margin (In thousands)

 

$

899

 

$

1,276

 

 

 

 

 

$

(377

)

 

The decreased brokered natural gas margin of $0.4 million is primarily a result of a decrease in brokered volumes coupled by a decrease in sales price that outpaced the decrease in purchase price.

 

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 June 30,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

Cash Flow Hedges

 

 

 

 

 

Natural Gas

 

$

69,732

 

$

13,667

 

Crude Oil

 

3,110

 

(514

)

 

 

 

 

 

 

Other Financial Derivative Instruments

 

 

 

 

 

Natural Gas Basis Swaps

 

(342

)

(903

)

 

 

$

72,500

 

$

12,250

 

 

27



Table of Contents

 

Operating and Other Expenses

 

 

 

Three Months Ended June 30,

 

Variance

 

(In thousands)

 

2012

 

2011

 

Amount

 

Percent

 

Operating and Other Expenses

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Cost

 

$

4,250

 

$

9,796

 

$

(5,546

)

(57

)%

Direct Operations

 

29,306

 

22,579

 

6,727

 

30

%

Transportation and Gathering

 

33,139

 

16,074

 

17,065

 

106

%

Taxes Other Than Income

 

10,854

 

5,877

 

4,977

 

85

%

Exploration

 

16,244

 

4,592

 

11,652

 

254

%

Depreciation, Depletion and Amortization

 

114,616

 

83,225

 

31,391

 

38

%

General and Administrative

 

46,872

 

26,006

 

20,866

 

80

%

Total Operating Expense

 

$

255,281

 

$

168,149

 

$

87,132

 

52

%

 

 

 

 

 

 

 

 

 

 

(Gain) / Loss on Sale of Assets

 

$

(67,703

)

$

(34,071

)

$

(33,632

)

99

%

Interest Expense and Other

 

18,495

 

18,044

 

451

 

2

%

Income Tax Expense

 

23,647

 

33,897

 

(10,250

)

(30

)%

 

Total costs and expenses from operations increased by $87.1 million, or 52%, in the second quarter of 2012 compared to the same period of 2011. The primary reasons for this fluctuation are as follows:

 

·                  Brokered Natural Gas Costs decreased $5.5 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

·                  Direct Operations increased $6.7 million largely due to increased operating costs primarily driven by increased production. Contributing to the increase are higher leased surface equipment and higher produced water disposal costs.

 

·                  Transportation and Gathering increased $17.1 million primarily due to an increase in production and higher transportation rates, coupled with the commencement of various transportation and gathering arrangements in the second half of 2011 and the first half of 2012, primarily in northeast Pennsylvania.

 

·                  Taxes Other Than Income increased $5.0 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 increased $11.7 million primarily due to an exploratory dry hole associated with our initial Brown Dense/Smackover exploratory well in Union County, Arkansas.

 

·                  Depreciation, Depletion and Amortization increased by $31.4 million, of which $29.1 million was due to higher equivalent production volumes and to $4.7 million was due to a higher DD&A rate of $1.71 per Mcfe for the quarter ended June 30, 2012 compared to $1.63 per Mcfe for the quarter ended June 30, 2011. The higher rate was due to the higher cost oil reserve additions in the second quarter associated with our 2012 drilling program. The increase in depreciation and depletion was partially offset by a decrease in amortization of unproved properties of $2.3 million.

 

·                  General and Administrative increased by $20.9 million primarily due to $10.8 million higher pension expense associated with the acceleration of amortization of the net actuarial loss and prior service cost as a result of the termination of our qualified pension plan and related settlement that occurred in the second quarter 2012, increased legal costs and professional fees of $6.8 million and the accrual of $1.9 million associated with fines and penalties assessed by the Office of Natural Resources Revenue for certain alleged volume reporting matters (which we are currently disputing) related to properties we no longer own.

 

Gain / (Loss) on Sale of Assets

 

An aggregate gain of $67.7 million was recognized in the second quarter of 2012 primarily due to the sale of certain of our Pearsall shale undeveloped leaseholds in south Texas. During the second quarter of 2011, an aggregate gain of $34.1 million was recognized primarily due to the sale of the undeveloped leaseholds in east Texas.

 

28



Table of Contents

 

Interest Expense and Other

 

Interest expense and other increased by $0.5 million primarily due to $1.3 million of debt extinguishment costs associated with our credit facility amendment partially offset by a decrease in weighted-average borrowings under our credit facility based on daily balances of approximately $293.7 million during the second quarter of 2012 compared to approximately $342.0 million during the second quarter of 2011 and a lower weighted-average effective interest rate on our credit facility borrowings of approximately 3.4% during the second quarter of 2012 compared to approximately 3.8% during the second quarter of 2011.

 

Income Tax Expense

 

Income tax expense decreased by $10.3 million primarily due to decreased pretax income, partially offset by a slightly higher effective tax rate. The effective tax rate for the second quarter of 2012 and 2011 was 39.7% and 38.3%, respectively. The effective tax rate in 2012 was higher due to an increase in non-deductible expenses.

 

Six Months of 2012 and 2011 Compared

 

We reported net income in the first six months of 2012 of $54.3 million, or $0.26 per share, compared to net income in the first six months of 2011 of $67.6 million, or $0.32 per share, for a decrease of $13.3 million. Operating revenues increased by $88.1 million due to increased natural gas and crude oil and condensate revenues, partially offset by decreased brokered natural gas revenues. Operating expenses increased by $141.0 million primarily due to an increase in depreciation, depletion, and amortization, transportation and gathering expenses, general and administration expense, taxes other than income, exploration expenses and direct operating expenses, partially offset by lower brokered natural gas costs. In addition, net income was impacted during the first six months of 2012 by lower income tax expense and higher gain on sale of assets.

 

Revenue, Price and Volume Variances

 

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

 

 

 

Six Months Ended June 30,

 

Variance

 

Revenue Variances (In thousands)

 

2012

 

2011

 

Amount

 

Percent

 

Natural Gas (1)

 

$

408,133

 

$

371,341

 

$

36,792

 

10

%

Brokered Natural Gas

 

18,593

 

29,480

 

(10,887

)

(37

)%

Crude Oil and Condensate

 

107,447

 

46,634

 

60,813

 

130

%

Other

 

3,920

 

3,153

 

767

 

24

%

 


(1) Natural Gas Revenues exclude the unrealized losses of $0.3 million and $0.9 million from the change in fair value of our derivatives not designated as hedges in 2012 and 2011, respectively.

 

 

 

 

 

 

 

 

 

 

 

Increase

 

 

 

Six Months Ended June 30,

 

Variance

 

(Decrease)

 

 

 

2012

 

2011

 

Amount

 

Percent

 

(In thousands)

 

Price Variances

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (1)

 

$

3.52

 

$

4.67

 

$

(1.15

)

(25

)%

$

(132,077

)

Crude Oil and Condensate (2)

 

$

99.76

 

$

91.80

 

$

7.96

 

9

%

8,570

 

Total

 

 

 

 

 

 

 

 

 

$

(123,507

)

Volume Variances

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Mmcf)

 

115,659

 

79,499

 

36,160

 

45

%

$

168,869

 

Crude Oil and Condensate (Mbbl)

 

1,077

 

508

 

569

 

112

%

52,243

 

Total

 

 

 

 

 

 

 

 

 

$

221,112

 

 


(1) These prices include the realized impact of derivative instrument settlements, which increased the price by $1.10 per Mcf in 2012 and $0.34 per Mcf in 2011.

(2) These prices include the realized impact of derivative instrument settlements, which increased the price by $1.66 per Bbl in 2012 and decreased the price by $1.61 per Bbl in 2011.

 

Natural Gas Revenues

 

The increase in natural gas revenues of $36.8 million, excluding the impact of unrealized losses discussed above, is due to increased production during the first six months of 2012, partially offset by lower realized natural gas prices. The increased production was primarily a result of increased production in the Marcellus shale associated with our drilling program and upgrades to the Lathrop

 

29



Table of Contents

 

compressor station in Susquehanna County, Pennsylvania, which included the commissioning of new compression during the latter part of the first quarter in 2011. Partially offsetting the production increase in Marcellus shale were decreases in production primarily in east Texas due to reduced drilling activity and normal production declines, the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011 and a continued shift from gas to oil projects outside of the Marcellus shale. The previously reported fire at the Lathrop compressor station in late March 2012 had no material impact on our natural gas revenues.

 

Crude Oil and Condensate Revenues

 

The increase in crude oil and condensate revenues of $60.8 million is primarily due to increased production associated with our Eagle Ford shale drilling program in south Texas and the Marmaton oil play in Oklahoma coupled with higher realized oil prices.

 

Brokered Natural Gas Revenue and Cost

 

 

 

 

 

 

 

 

 

 

 

Price and

 

 

 

Six Months Ended

 

 

 

 

 

Volume

 

 

 

June 30,

 

Variance

 

Variances

 

 

 

2012

 

2011

 

Amount

 

Percent

 

(In thousands)

 

Brokered Natural Gas Sales

 

 

 

 

 

 

 

 

 

 

 

Sales Price ($/Mcf)

 

$

3.62

 

$

5.21

 

$

(1.59

)

(31

)%

$

(8,162

)

Volume Brokered (Mmcf)

 

x

5,138

 

x

5,661

 

(523

)

(9

)%

(2,725

)

Brokered Natural Gas Revenues (In thousands)

 

$

18,593

 

$

29,480

 

 

 

 

 

$

(10,887

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Purchases

 

 

 

 

 

 

 

 

 

 

 

Purchase Price ($/Mcf)

 

$

3.14

 

$

4.44

 

$

(1.30

)

(29

)%

$

6,714

 

Volume Brokered (Mmcf)

 

x

5,138

 

x

5,661

 

(523

)

(9

)%

2,322

 

Brokered Natural Gas Cost (In thousands)

 

$

16,122

 

$

25,158

 

 

 

 

 

$

9,036

 

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Margin (In thousands)

 

$

2,471

 

$

4,322

 

 

 

 

 

$

(1,851

)

 

The decreased brokered natural gas margin of $1.9 million is primarily a result of a decrease in sales price that outpaced a decrease in the purchase price coupled with a decrease in 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,

 

(In thousands)

 

2012

 

2011

 

 

 

 

 

 

 

Cash Flow Hedges

 

 

 

 

 

Natural Gas

 

$

126,728

 

$

27,148

 

Crude Oil

 

1,784

 

(816

)

 

 

 

 

 

 

Other Financial Derivative Instruments

 

 

 

 

 

Natural Gas Basis Swaps

 

(300

)

(886

)

 

 

$

128,212

 

$

25,446

 

 

30



Table of Contents

 

Operating and Other Expenses

 

 

 

Six Months Ended June 30,

 

Variance

 

(In thousands)

 

2012

 

2011

 

Amount

 

Percent

 

Operating and Other Expenses

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Cost

 

$

16,122

 

$

25,158

 

$

(9,036

)

(36

)%

Direct Operations

 

56,626

 

49,586

 

7,040

 

14

%

Transportation and Gathering

 

63,397

 

28,942

 

34,455

 

119

%

Taxes Other Than Income

 

29,437

 

14,028

 

15,409

 

110

%

Exploration

 

20,245

 

10,900

 

9,345

 

86

%

Depreciation, Depletion and Amortization

 

224,973

 

160,349

 

64,624

 

40

%

General and Administrative

 

69,421

 

50,305

 

19,116

 

38

%

Total Operating Expense

 

$

480,221

 

$

339,268

 

$

140,953

 

42

%

 

 

 

 

 

 

 

 

 

 

(Gain) / Loss on Sale of Assets

 

$

(67,168

)

$

(32,554

)

$

(34,614

)

106

%

Interest Expense and Other

 

35,412

 

35,411

 

1

 

0

%

Income Tax Expense

 

35,073

 

40,034

 

(4,961

)

(12

)%

 

Total costs and expenses from operations increased by $141.0 million, or 42%, in the first six months of 2012 compared to the same period of 2011. The primary reasons for this fluctuation are as follows:

 

·                  Brokered Natural Gas Costs decreased $9.0 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

·                  Direct Operations increased $7.0 million largely due to increased operating costs primarily driven by increased production. Contributing to the increase are higher leased surface equipment costs, produced water disposal costs and plugging and abandonment costs. These increases are partially offset by lower workover costs.

 

·                  Transportation and Gathering increased by $34.5 million primarily due to an increase in production and higher transportation rates, coupled with the commencement of various transportation and gathering arrangements in the second half of 2011 and the first half of 2012, primarily in northeast Pennsylvania.

 

·                  Taxes Other Than Income increased $15.4 million primarily due to additional costs associated with the passage of an “impact fee” in Pennsylvania on Marcellus shale production that was imposed by state legislature in February 2012 and higher production tax expense due to fewer production tax refunds and credits received in the first half of 2012 compared to the first half of 2011.

 

·                  Exploration increased $9.3 million primarily due to an exploratory dry hole associated with our initial Brown Dense/Smackover exploratory well in Union County, Arkansas, partially offset by lower geophysical and geological costs due to fewer acquisitions and purchases of seismic data.

 

·                  Depreciation, Depletion and Amortization increased by $64.6 million, of which $67.6 million was due to higher equivalent production volumes, partially offset by a decrease in amortization of unproved properties of $2.2 million.

 

·                  General and Administrative increased by $19.1 million primarily due to $14.0 million higher pension expense associated with the acceleration of amortization of the net actuarial loss and prior service costs as a result of the termination of our qualified pension plan and the related settlement that occurred in the second quarter 2012 and higher legal costs and professional fees of $5.9 million. Also contributing to the increase was the accrual of $1.9 million associated with fines and penalties assessed by the Office of Natural Resources Revenue for certain alleged volume reporting matters (which we are currently disputing) related to properties we no longer own.  These increases are partially offset by $6.2 million lower stock-based compensation expense primarily associated with the mark-to-market of our liability-based performance awards due to changes in our stock price for the six months ended June 30, 2012 compared to the six months ended June 30, 2011 and a reduction of our supplemental incentive compensation liability.

 

31



Table of Contents

 

Gain / (Loss) on Sale of Assets

 

An aggregate gain of $67.2 million was recognized in the first half of 2012 primarily due to the sale of certain of our Pearsall shale undeveloped leaseholds in south Texas. During the first half of 2011, an aggregate gain of $32.6 million was recognized primarily due to the sale of the undeveloped leaseholds in east Texas.

 

Interest Expense and Other

 

Interest expense and other increased by $0.1 million primarily due to $1.3 million of debt extinguishment costs associated with our credit facility amendment in the second quarter 2012, offset by decrease in weighted-average borrowings under our credit facility based on daily balances of approximately $263.2 million during the first half of 2012 compared to approximately $305.9 million during the first half of 2011 coupled with a lower weighted-average effective interest rate on our credit facility borrowings of approximately 3.7% during the first half of 2012 compared to approximately 4.3% during the first half of 2011.

 

Income Tax Expense

 

Income tax expense decreased by $5.0 million primarily due to lower pretax income offset by a higher effective tax rate. The effective tax rate for the first half of 2012 and 2011 was 39.3% and 37.2%, respectively. The effective tax rate in 2012 was higher due to an increase in estimated state tax liabilities and non-deductible expenses.

 

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 statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and 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 and in our other Securities and Exchange Commission filings. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document.

 

ITEM  3.                           Quantitative and Qualitative Disclosures about Market Risk

 

Market Risk

 

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

 

Derivative Instruments and Hedging Activity

 

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us in periods of increasing prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 8 of the Notes to the Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

 

Periodically, we enter into derivative commodity instruments 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 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.

 

32



Table of Contents

 

As of June 30, 2012, we had 49 derivative contracts open: 23 natural gas price swap arrangements, six natural gas basis swap arrangements, 14 natural gas collar arrangements and six crude oil swap arrangements. During the first six months of 2012, we entered into 12 new derivative contracts covering anticipated crude oil production for 2012 and 2013 and natural gas production for 2013.

 

As of June 30, 2012, 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

 

48,261 Mmcf

 

Jul. 2012 - Dec. 2012

 

107,008

 

Natural Gas Collars

 

$3.09 Floor / $4.12 Ceiling  per Mcf

 

35,457 Mmcf

 

Jan. 2013 - Dec. 2013

 

(3,856

)

Natural Gas Collars

 

$5.15 Floor / $6.20 Ceiling  per Mcf

 

17,729 Mmcf

 

Jan. 2013 - Dec. 2013

 

28,155

 

Crude Oil Swaps

 

$100.45   per Bbl

 

1,041  Mbbl

 

Jul. 2012 - Dec. 2012

 

13,122

 

Crude Oil Swaps

 

$101.90   per Bbl

 

1,095  Mbbl

 

Jan. 2013 - Dec. 2013

 

14,691

 

 

 

 

 

 

 

 

 

$

159,120

 

Derivatives Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

Natural Gas Basis Swaps

 

$(0.25)  per Mcf

 

8,568 Mmcf

 

Jul. 2012 - Dec. 2012

 

(1,881

)

 

 

 

 

 

 

 

 

$

157,239

 

 

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

 

We had natural gas swaps covering 47.7 Bcf, or 41%, of our natural gas production for the first six months of 2012 at an average price of $5.22 per Mcf.

 

We had natural gas basis swaps covering 8.5 Bcf, or 7%, of our natural gas production for the first six months of 2012 at an average price of $(0.18) per Mcf.

 

We had crude oil swaps covering 789 Mbbl, or 73%, of our crude oil production for the first six months of 2012 at an average price of $99.74 per Bbl.

 

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

 

Fair Market Value of Financial Instruments

 

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

 

The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and credit facility to new 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:

 

33



Table of Contents

 

 

 

June 30, 2012

 

December 31, 2011

 

(In thousands)

 

Carrying
Amount

 

Estimated Fair
Value

 

Carrying
Amount

 

Estimated Fair
Value

 

Long-Term Debt

 

$

972,000

 

$

1,115,085

 

$

950,000

 

$

1,082,531

 

 

ITEM  4.                           Controls and Procedures

 

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

 

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

 

PART II. OTHER INFORMATION

 

ITEM  1.                           Legal Proceedings

 

Legal Matters

 

The information set forth under the heading “Legal Matters” in Note 7 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 responsive to the request and is cooperating with the Attorney General’s Office in the matter.

 

Environmental Matters

 

The information set forth under the heading “Environmental Matters” in Note 7 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 of Notices of Violation from the Pennsylvania Department of Environmental Protection (PaDEP) relating to alleged violations, primarily with respect to the Pennsylvania Clean Streams Law, the Pennsylvania Oil and Gas Act and the Pennsylvania Solid Waste Management Act and the rules and regulations promulgated thereunder. 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 cannot predict with certainty whether these Notices of Violation will result in fines and/or penalties, if fines and/or penalties are imposed, the aggregate of these fines and/or penalties could result in monetary sanctions in excess of $100,000.

 

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, see Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

 

34



Table of Contents

 

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

 

Issuer Purchases of Equity Securities

 

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

 

35



Table of Contents

 

ITEM 6.                               Exhibits

 

Exhibit
Number

 

Description

 

 

 

3.1

 

Certificate of Share Purchase (Form 8-K for January 21, 2010).

 

 

 

3.2

 

Amended and Restated Bylaws, effective as of February 17, 2012.

 

 

 

3.3

 

Certificate of Amendment of Restated Certificate of Incorporation, dated as of May 1, 2012.

 

 

 

10.1

 

First Amendment to Amended and Restated Credit Agreement, dated as of May 4, 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

 

36



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)

 

 

 

July 27, 2012

By:

/S/    DAN O. DINGES

 

 

Dan O. Dinges

 

 

Chairman, President and

 

 

Chief Executive Officer

 

 

(Principal Executive Officer)

 

 

 

July 27, 2012

By:

/S/    SCOTT C. SCHROEDER

 

 

Scott C. Schroeder

 

 

Vice President, Chief Financial Officer and Treasurer

 

 

(Principal Financial Officer)

 

 

 

July 27, 2012

By:

/S/    TODD M. ROEMER

 

 

Todd M. Roemer

 

 

Controller

 

 

(Principal Accounting Officer)

 

37