10-Q 1 a13-8283_110q.htm QUARTERLY REPORT PURSUANT TO SECTIONS 13 OR 15(D)

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 March 31, 2013

 

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

 

Commission file number 1-10447

 


 

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

 


 

DELAWARE

 

04-3072771

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification Number)

 

Three Memorial City Plaza

840 Gessner Road, Suite 1400, Houston, Texas 77024

(Address of principal executive offices including ZIP code)

 

(281) 589-4600

(Registrant’s telephone number, including area code)

 


 

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

 

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

 

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

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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

 

As of April 22, 2013, there were 210,750,374 shares of Common Stock, Par Value $.10 Per Share, outstanding.

 

 

 



Table of Contents

 

CABOT OIL & GAS CORPORATION

 

INDEX TO FINANCIAL STATEMENTS

 

 

Page

Part I. Financial Information

 

 

 

Item 1.      Financial Statements

 

 

 

Condensed Consolidated Balance Sheet at March 31, 2013 and December 31, 2012

3

 

 

Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2013 and 2012

4

 

 

Condensed Consolidated Statement of Comprehensive Income for the Three Months Ended March 31, 2013 and 2012

5

 

 

Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2013 and 2012

6

 

 

Notes to the Condensed Consolidated Financial Statements

7

 

 

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

18

 

 

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

19

 

 

Item 3.      Quantitative and Qualitative Disclosures about Market Risk

25

 

 

Item 4.      Controls and Procedures

27

 

 

Part II. Other Information

 

 

 

Item 1.      Legal Proceedings

27

 

 

Item 1A.   Risk Factors

28

 

 

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

28

 

 

Item 6.      Exhibits

28

 

 

Signatures

29

 

2



Table of Contents

 

PART I. FINANCIAL INFORMATION

 

ITEM  1.                      Financial Statements

 

CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

 

 

 

March 31,

 

December 31,

 

(In thousands, except share amounts)

 

2013

 

2012

 

ASSETS

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

20,457

 

$

30,736

 

Accounts receivable, net

 

172,661

 

172,419

 

Inventories

 

11,278

 

14,173

 

Deferred income taxes

 

29,095

 

 

Derivative instruments

 

4,215

 

50,824

 

Other current assets

 

1,174

 

2,158

 

Total current assets

 

238,880

 

270,310

 

Properties and equipment, net (Successful efforts method)

 

4,412,772

 

4,310,977

 

Other assets

 

36,184

 

35,026

 

 

 

$

4,687,836

 

$

4,616,313

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities

 

 

 

 

 

Accounts payable

 

$

299,733

 

$

312,480

 

Current portion of long-term debt

 

75,000

 

75,000

 

Accrued liabilities

 

42,553

 

49,597

 

Income taxes payable

 

3,878

 

1,667

 

Deferred income taxes

 

 

5,203

 

Derivative instruments

 

26,100

 

192

 

Total current liabilities

 

447,264

 

444,139

 

Postretirement benefits

 

39,636

 

38,864

 

Long-term debt

 

1,052,000

 

1,012,000

 

Deferred income taxes

 

910,608

 

882,672

 

Asset retirement obligation

 

69,093

 

67,016

 

Derivative instruments

 

3,799

 

 

Other liabilities

 

42,222

 

40,175

 

Total liabilities

 

2,564,622

 

2,484,866

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity

 

 

 

 

 

Common stock:

 

 

 

 

 

Authorized — 480,000,000 shares of $0.10 par value in 2013 and 2012, respectively

 

 

 

 

 

Issued—210,749,418 shares and 210,429,731 shares in 2013 and 2012, respectively

 

21,075

 

21,043

 

Additional paid-in capital

 

715,896

 

716,609

 

Retained earnings

 

1,411,887

 

1,373,264

 

Accumulated other comprehensive income / (loss)

 

(22,295

)

23,880

 

Less treasury stock, at cost:

 

 

 

 

 

404,400 shares in 2013 and 2012, respectively

 

(3,349

)

(3,349

)

Total stockholders’ equity

 

2,123,214

 

2,131,447

 

 

 

$

4,687,836

 

$

4,616,313

 

 

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

 

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CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

 

 

 

Three Months Ended

 

 

 

March 31,

 

(In thousands, except per share amounts)

 

2013

 

2012

 

 

 

 

 

 

 

OPERATING REVENUES

 

 

 

 

 

Natural gas

 

$

293,793

 

$

206,782

 

Crude oil and condensate

 

65,655

 

49,981

 

Brokered natural gas

 

10,893

 

13,444

 

Other

 

2,944

 

1,929

 

 

 

373,285

 

272,136

 

OPERATING EXPENSES

 

 

 

 

 

Direct operations

 

31,497

 

27,320

 

Transportation and gathering

 

46,221

 

30,258

 

Brokered natural gas cost

 

8,389

 

11,872

 

Taxes other than income

 

11,687

 

18,583

 

Exploration

 

4,024

 

4,001

 

Depreciation, depletion and amortization

 

148,653

 

110,357

 

General and administrative

 

35,704

 

22,549

 

 

 

286,175

 

224,940

 

Gain / (loss) on sale of assets

 

(96

)

(535

)

INCOME FROM OPERATIONS

 

87,014

 

46,661

 

Interest expense and other

 

16,255

 

16,917

 

Income before income taxes

 

70,759

 

29,744

 

Income tax expense

 

27,935

 

11,426

 

NET INCOME

 

$

42,824

 

$

18,318

 

 

 

 

 

 

 

Earnings per share

 

 

 

 

 

Basic

 

$

0.20

 

$

0.09

 

Diluted

 

$

0.20

 

$

0.09

 

 

 

 

 

 

 

Weighted-average shares outstanding

 

 

 

 

 

Basic

 

210,150

 

209,128

 

Diluted

 

211,376

 

210,813

 

 

 

 

 

 

 

Dividends per common share

 

$

0.02

 

$

0.02

 

 

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

 

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Table of Contents

 

CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Unaudited)

 

 

 

Three Months Ended

 

 

 

March 31,

 

(In thousands)

 

2013

 

2012

 

 

 

 

 

 

 

Net income

 

$

42,824

 

$

18,318

 

 

 

 

 

 

 

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

 

 

 

 

 

Reclassification adjustment for settled hedge contracts (1) 

 

(9,325

)

(34,070

)

Changes in fair value of hedge contracts (2) 

 

(36,975

)

43,205

 

Pension and postretirement benefits:

 

 

 

 

 

Amortization of prior service cost (3) 

 

 

68

 

Amortization of net loss (4) 

 

125

 

4,175

 

Total other comprehensive income / (loss)

 

(46,175

)

13,378

 

Comprehensive income / (loss)

 

$

(3,351

)

$

31,696

 

 


(1)    Net of income taxes of $6,045 and $21,600 for the three months ended March 31, 2013 and 2012, respectively.

(2)    Net of income taxes of $23,971 and $(27,523) for the three months ended March 31, 2013 and 2012, respectively.

(3)    Net of income taxes of $0 and $(43) for the three months ended March 31, 2013 and 2012, respectively.

(4)    Net of income taxes of $(80) and $(2,647) for the three months ended March 31, 2013 and 2012, respectively.

 

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

 

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CABOT OIL & GAS CORPORATION

 

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

 

 

 

Three Months Ended

 

 

 

March 31,

 

(In thousands)

 

2013

 

2012

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

42,824

 

$

18,318

 

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

 

 

 

 

 

Depreciation, depletion and amortization

 

148,653

 

110,357

 

Deferred income tax expense

 

23,574

 

9,724

 

(Gain) / loss on sale of assets

 

96

 

535

 

Exploration expense

 

666

 

49

 

Unrealized (gain) / loss on derivative instruments

 

 

(42

)

Amortization of debt issuance costs

 

897

 

1,064

 

Stock-based compensation, pension and other

 

17,655

 

(1,470

)

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable, net

 

(243

)

19,261

 

Inventories

 

2,896

 

9,048

 

Other current assets

 

983

 

518

 

Accounts payable and accrued liabilities

 

(27,885

)

(38,149

)

Income taxes

 

4,349

 

2,187

 

Other assets and liabilities

 

358

 

380

 

Stock-based compensation tax benefit

 

(2,138

)

 

Net cash provided by operating activities

 

212,685

 

131,780

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Capital expenditures

 

(260,169

)

(188,547

)

Proceeds from sale of assets

 

486

 

1,280

 

Investment in equity method investment

 

(1,250

)

 

Net cash used in investing activities

 

(260,933

)

(187,267

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings from debt

 

135,000

 

90,000

 

Repayments of debt

 

(95,000

)

(28,000

)

Stock-based compensation tax benefit

 

2,138

 

 

Dividends paid

 

(4,201

)

(4,177

)

Other

 

32

 

81

 

Net cash provided by financing activities

 

37,969

 

57,904

 

 

 

 

 

 

 

Net (decrease) / increase in cash and cash equivalents

 

(10,279

)

2,417

 

Cash and cash equivalents, beginning of period

 

30,736

 

29,911

 

Cash and cash equivalents, end of period

 

$

20,457

 

$

32,328

 

 

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

 

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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, 2012 (Form 10-K) filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the expected results for the entire year.

 

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

 

With respect to the unaudited financial information of the Company as of March 31, 2013 and for the three months ended March 31, 2013 and 2012, PricewaterhouseCoopers LLP reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated April 26, 2013 appearing herein states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

 

Recent Accounting Pronouncements

 

Effective January 1, 2013, the Company adopted the amended disclosure requirements prescribed in Accounting Standards Update (ASU) No. 2011-11,  “Disclosures about Offsetting Assets and Liabilities” and ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This guidance impacted the disclosures associated with the Company’s commodity derivatives (Note 7) and did not impact its consolidated financial position, results of operations or cash flows.

 

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

 

2. PROPERTIES AND EQUIPMENT, NET

 

Properties and equipment, net are comprised of the following:

 

 

 

March 31,

 

December 31,

 

(In thousands)

 

2013

 

2012

 

 

 

 

 

 

 

Proved oil and gas properties

 

$

5,969,544

 

$

5,724,940

 

Unproved oil and gas properties

 

463,455

 

467,483

 

Gathering and pipeline systems

 

239,791

 

239,656

 

Land, building and other equipment

 

88,484

 

86,137

 

 

 

6,761,274

 

6,518,216

 

Accumulated depreciation, depletion and amortization

 

(2,348,502

)

(2,207,239

)

 

 

$

4,412,772

 

$

4,310,977

 

 

At March 31, 2013, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

 

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Table of Contents

 

3. ADDITIONAL BALANCE SHEET INFORMATION

 

Certain balance sheet amounts are comprised of the following:

 

 

 

March 31,

 

December 31,

 

(In thousands)

 

2013

 

2012

 

 

 

 

 

 

 

Accounts receivable, net

 

 

 

 

 

Trade accounts

 

$

167,405

 

$

165,070

 

Joint interest accounts

 

4,826

 

5,659

 

Other accounts

 

1,555

 

2,817

 

 

 

173,786

 

173,546

 

Allowance for doubtful accounts

 

(1,125

)

(1,127

)

 

 

$

172,661

 

$

172,419

 

Inventories

 

 

 

 

 

Natural gas in storage

 

$

3,425

 

$

7,494

 

Tubular goods and well equipment

 

8,011

 

6,392

 

Other accounts

 

(158

)

287

 

 

 

$

11,278

 

$

14,173

 

Other current assets

 

 

 

 

 

Prepaid balances and other

 

1,174

 

2,158

 

 

 

$

1,174

 

$

2,158

 

Other assets

 

 

 

 

 

Deferred compensation plan

 

$

11,372

 

$

10,608

 

Debt issuance cost

 

16,523

 

17,420

 

Equity method investment

 

8,211

 

6,915

 

Other accounts

 

78

 

83

 

 

 

$

36,184

 

$

35,026

 

Accounts payable

 

 

 

 

 

Trade accounts

 

$

11,006

 

$

14,037

 

Natural gas purchases

 

2,331

 

4,892

 

Royalty and other owners

 

71,028

 

66,321

 

Accrued capital costs

 

154,498

 

164,862

 

Taxes other than income

 

13,504

 

10,224

 

Drilling advances

 

40,607

 

44,203

 

Producer gas imbalances

 

1,628

 

1,602

 

Other accounts

 

5,131

 

6,339

 

 

 

$

299,733

 

$

312,480

 

Accrued liabilities

 

 

 

 

 

Employee benefits

 

$

17,346

 

$

16,011

 

Postretirement benefits

 

1,304

 

1,304

 

Taxes other than income

 

8,959

 

8,735

 

Interest payable

 

12,650

 

22,329

 

Other accounts

 

2,294

 

1,218

 

 

 

$

42,553

 

$

49,597

 

Other liabilities

 

 

 

 

 

Deferred compensation plan

 

$

29,429

 

$

23,893

 

Other accounts

 

12,793

 

16,282

 

 

 

$

42,222

 

$

40,175

 

 

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Table of Contents

 

4. DEBT AND CREDIT AGREEMENTS

 

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

 

(In thousands)

 

March 31,
2013

 

December 31,
2012

 

Total debt

 

 

 

 

 

7.33% weighted-average fixed rate notes

 

$

95,000

 

$

95,000

 

6.51% weighted-average fixed rate notes

 

425,000

 

425,000

 

9.78% notes

 

67,000

 

67,000

 

5.58% weighted-average fixed rate notes

 

175,000

 

175,000

 

Credit facility

 

365,000

 

325,000

 

Current maturities

 

 

 

 

 

7.33% weighted-average fixed rate notes

 

(75,000

)

(75,000

)

Long-term debt, excluding current maturities

 

$

1,052,000

 

$

1,012,000

 

 

At March 31, 2013, the Company had $365.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 2.3% and $534.0 million available for future borrowings.

 

Effective April 17, 2013, the lenders under the Company’s revolving credit facility approved an increase in the Company’s borrowing base from $1.7 billion to $2.3 billion as part of the annual redetermination under the terms of the credit facility.

 

5. EARNINGS PER COMMON SHARE

 

Basic EPS is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock appreciation rights were exercised and stock awards were vested at the end of the applicable period.

 

 

 

Three Months Ended

 

 

 

March 31,

 

(In thousands)

 

2013

 

2012

 

Weighted-average shares - basic

 

210,150

 

209,128

 

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

 

1,226

 

1,685

 

Weighted-average shares - diluted  

 

211,376

 

210,813

 

 

 

 

 

 

 

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

 

184

 

82

 

 

6. COMMITMENTS AND CONTINGENCIES

 

Contractual Obligations

 

The Company has various contractual obligations in the normal course of its operations. There have been no material changes to our contractual obligations described under “Transportation Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 8 in the Notes to Consolidated Financial Statements included in the Form 10-K.

 

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Table of Contents

 

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 sought 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 alleged breach of a preferential purchase right regarding those properties contained in a 1969 joint operating agreement to which the plaintiff was a party. The Company initially obtained judgment as a matter of law as to all claims in a decision by the trial court in 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 was consolidated into the first lawsuit. In April 2013, the trial court ruled in the Company’s favor in both cases, holding that no preferential purchase right existed. The Company has been notified by the plaintiff that they will not appeal the trial court ruling.

 

Other

 

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

 

Contingency Reserves

 

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

 

Environmental Matters

 

Pennsylvania Department of Environmental Protection

 

On December 15, 2010, the Company entered into a consent order and settlement agreement (CO&SA) with the Pennsylvania Department of Environmental Protection (PaDEP), addressing a number of environmental issues originally identified in 2008 and 2009, including alleged releases of drilling mud and other substances, alleged record keeping violations at various wells and alleged natural gas contamination of water supplies to 14 households in Susquehanna County, Pennsylvania. During 2010 and 2011, the Company paid a total of $1.3 million in settlement of fines and penalties sought or claimed by the PaDEP related to this matter. On January 11, 2011, certain of the affected households appealed the CO&SA to the Pennsylvania Environmental Hearing Board (PEHB). On October 17, 2011, the Company requested PaDEP approval to resume hydraulic fracturing and new natural gas well drilling operations in the affected area, along with a request to cease temporary water deliveries to the affected households pursuant to prior consent orders with the PaDEP. The PaDEP concurred that temporary water deliveries to the property owners are no longer necessary. On November 18, 2011, certain of the affected households appealed this order to the PEHB, which appeal was later consolidated with the CO&SA appeal. All appellants have accepted their portion of the $2.2 million that was placed into escrow in 2011 for their benefit and on October 18, 2012 had dismissed their appeal to the PEHB. Subsequent to the withdrawal of the appeals, the PEHB allowed three groups of appellants to reinstate their appeal. A hearing related to the reinstated appeal is expected to occur in the first half 2013.

 

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

 

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

 

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations related to its natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and 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 March 31, 2013, the Company had the following outstanding commodity derivatives:

 

Commodity and Derivative Type

 

Weighted-Average Contract Price

 

Volume

 

Contract Period

 

Derivatives Designated as Hedging Instruments

 

 

 

 

 

 

 

Natural gas collars

 

$3.09 Floor / $4.12 Ceiling  per Mcf

 

26.7   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$3.35 Floor / $4.01 Ceiling  per Mcf

 

26.7   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$3.40 Floor / $4.12 Ceiling  per Mcf

 

13.4   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$3.60 Floor / $3.99 Ceiling  per Mcf

 

13.4   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$3.60 Floor / $4.17 Ceiling  per Mcf

 

13.4   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$3.76 Floor / $4.16 Ceiling  per Mcf

 

13.4   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$3.86 Floor / $4.34 Ceiling  per Mcf

 

13.4   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$3.96 Floor / $4.41 Ceiling  per Mcf

 

13.4   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$5.15 Floor / $6.20 Ceiling  per Mcf

 

13.4   Bcf   

 

Apr. 2013 - Dec. 2013

 

Natural gas collars

 

$3.60 Floor / $4.58 Ceiling  per Mcf

 

31.1   Bcf   

 

Apr. 2013 - Dec. 2014

 

Natural gas collars

 

$3.96 Floor / $4.56 Ceiling  per Mcf

 

31.1   Bcf   

 

Apr. 2013 - Dec. 2014

 

Natural gas collars

 

$3.86 Floor / $4.66 Ceiling  per Mcf

 

17.7   Bcf   

 

Jan. 2014 - Dec. 2014

 

Natural gas collars

 

$4.12 Floor / $4.64 Ceiling  per Mcf

 

35.5   Bcf   

 

Jan. 2014 - Dec. 2014

 

Crude oil swaps

 

$101.90  per Bbl 

 

825   Mbbl

 

Apr. 2013 - Dec. 2013

 

 

The changes in the fair value of derivatives designated as hedges that are effective are 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 in the Condensed Consolidated Statement of Operations.

 

The following disclosures reflect the impact of derivative instruments on the Company’s condensed consolidated financial statements:

 

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet

 

 

 

 

 

Fair Values of Derivative Instruments

 

 

 

 

 

Derivative Assets

 

Derivative Liabilities

 

(In thousands)

 

 

 

March 31,
2013

 

December 31,
2012

 

March 31,
2013

 

December 31,
2012

 

Derivatives Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative instruments (current assets)

 

$

4,215

 

$

50,824

 

$

 

$

 

Commodity contracts

 

Derivative instruments (current liabilities)

 

 

 

26,100

 

192

 

Commodity contracts

 

Derivative instruments (non-current liabilities)

 

 

 

3,799

 

 

 

 

 

 

$

4,215

 

$

50,824

 

$

29,899

 

$

192

 

 

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Table of Contents

 

At March 31, 2013 and December 31, 2012, unrealized losses of $25.7 million ($15.6 million, net of tax) and unrealized gains of $50.6 million ($30.7 million, net of tax), respectively, were recorded in accumulated other comprehensive income / (loss) in stockholder’s equity in the Condensed Consolidated Balance Sheet. Based upon estimates at March 31, 2013, the Company expects to reclassify $13.3 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.

 

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

 

(In thousands)

 

March 31,
2013

 

December 31,
2012

 

Derivative Assets

 

 

 

 

 

Gross amounts of recognized assets

 

$

18,353

 

$

54,454

 

Gross amounts offset in the statement of financial position

 

(14,138

)

(3,630

)

Net amounts of assets presented in the statement of financial position

 

4,215

 

50,824

 

Gross amounts of financial instruments not offset in the statement of financial position

 

832

 

1,892

 

Net amount

 

$

5,047

 

$

52,716

 

 

 

 

 

 

 

Derivative Liabilities

 

 

 

 

 

Gross amounts of recognized liabilities

 

$

44,037

 

$

3,822

 

Gross amounts offset in the statement of financial position

 

(14,138

)

(3,630

)

Net amounts of liabilities presented in the statement of financial position

 

29,899

 

192

 

Gross amounts of financial instruments not offset in the statement of financial position

 

 

 

Net amount

 

$

29,899

 

$

192

 

 

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

 

Derivatives Designated

 

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

 

Location of Gain (Loss)
Reclassified from
Accumulated OCI into

 

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

 

as Hedging Instruments

 

Three Months Ended March 31,

 

Income

 

Three Months Ended March 31,

 

(In thousands)

 

2013

 

2012

 

(In thousands)

 

2013

 

2012

 

Commodity Contracts

 

$

(60,946

)

$

70,728

 

Natural gas revenues

 

$

13,328

 

$

56,996

 

 

 

 

 

 

 

Crude oil and condensate revenues

 

2,042

 

(1,326

)

 

 

 

 

 

 

 

 

$

15,370

 

$

55,670

 

 

For the three months ended March 31, 2013 and 2012, respectively, there was no ineffectiveness recorded in our Condensed Consolidated Statement of Operations related to our derivative instruments.

 

Derivatives Not Designated as 

 

Location of Gain (Loss)

 

Three Months Ended

 

Hedging Instruments 

 

Recognized in Income on

 

March 31,

 

(In thousands)

 

Derivatives

 

2013

 

2012

 

Commodity Contracts

 

Natural gas revenues

 

$

 

$

42

 

 

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 each of its counterparties that allow it to offset assets and liabilities from separate derivative contracts with that counterparty.

 

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

 

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Table of Contents

 

8. FAIR VALUE MEASUREMENTS

 

The Company follows the authoritative guidance for measuring fair value of assets and liabilities in its financial statements. The authoritative guidance also established a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values. For further information regarding the fair value hierarchy, refer to Note 14 of the Notes to the Consolidated Financial Statements in the Form 10-K.

 

Non-Financial Assets and Liabilities

 

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of long-lived assets, at fair value on a nonrecurring basis. As none of the Company’s non-financial assets and liabilities were impaired as of March 31, 2013 and 2012 and no other assets or liabilities were required to be measured at fair value on a non-recurring basis, additional disclosures are not provided.

 

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

 

Financial Assets and Liabilities

 

The 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)

 

March 31,
2013

 

Assets

 

 

 

 

 

 

 

 

 

Deferred compensation plan

 

$

11,372

 

$

 

$

 

$

11,372

 

Derivative instruments

 

 

4,215

 

 

4,215

 

Total assets

 

$

11,372

 

$

4,215

 

$

 

$

15,587

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Deferred compensation plan

 

$

29,429

 

$

 

$

 

$

29,429

 

Derivative instruments

 

 

 

29,899

 

29,899

 

Total liabilities

 

$

29,429

 

$

 

$

29,899

 

$

59,328

 

 

(In thousands)

 

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

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

December 31,
2012

 

Assets

 

 

 

 

 

 

 

 

 

Deferred compensation plan

 

$

10,608

 

$

 

$

 

$

10,608

 

Derivative instruments

 

 

9,473

 

41,351

 

50,824

 

Total assets

 

$

10,608

 

$

9,473

 

$

41,351

 

$

61,432

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Deferred compensation plan

 

$

23,893

 

$

 

$

 

$

23,893

 

Derivative instruments

 

 

 

192

 

192

 

Total liabilities

 

$

23,893

 

$

 

$

192

 

$

24,085

 

 

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Table of Contents

 

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

 

The derivative instruments were measured based on quotes from the Company’s counterparties. Such quotes have been derived using an income approach that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, basis differentials, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates 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 nonperformance risk. The Company measured the nonperformance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions, while nonperformance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

 

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

 

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

 

 

 

Three Months Ended

 

 

 

March 31,

 

(In thousands)

 

2013

 

2012

 

Balance at beginning of period

 

$

41,159

 

$

195,127

 

Total gains / (losses) (realized or unrealized):

 

 

 

 

 

Included in earnings (1)

 

13,328

 

57,038

 

Included in other comprehensive income

 

(71,058

)

22,692

 

Settlements

 

(13,328

)

(56,300

)

Transfers in and/or out of level 3

 

 

385

 

Balance at end of period

 

$

(29,899

)

$

218,942

 

 


(1)       Unrealized gains of $42,000  for the three months ended March 31, 2012 were included in natural gas revenues in the Condensed Consolidated Statement of Operations. There were no unrealized gains or losses for the three months ended March 31, 2013.

 

Fair Value of Other Financial Instruments

 

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

 

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

 

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Table of Contents

 

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:

 

 

 

March 31, 2013

 

December 31, 2012

 

(In thousands)

 

Carrying
Amount

 

Estimated
Fair Value

 

Carrying
Amount

 

Estimated
Fair Value

 

Total debt

 

$

1,127,000

 

$

1,249,576

 

$

1,087,000

 

$

1,213,474

 

Current maturities

 

(75,000

)

(76,279

)

(75,000

)

(77,175

)

Long-term debt, excluding current maturities

 

$

1,052,000

 

$

1,173,297

 

$

1,012,000

 

$

1,136,299

 

 

9. ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

 

Changes in accumulated other comprehensive income / (loss) by component, net of tax, were as follows:

 

(In thousands)

 

Net Gains
(Losses) on
Cash Flow
Hedges

 

Postretirement
Benefits

 

Total

 

Balance at December 31, 2012

 

$

30,717

 

$

(6,837

)

$

23,880

 

Other comprehensive income before reclassifications

 

(36,975

)

 

(36,975

)

Amounts reclassified from accumulated other comprehensive income

 

(9,325

)

125

 

(9,200

)

New current-period other comprehensive income

 

(46,300

)

125

 

(46,175

)

Balance at March 31, 2013

 

$

(15,583

)

$

(6,712

)

$

(22,295

)

 

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

 

(In thousands)

 

Three Months Ended
March 31, 2013

 

Affected Line Item in the Statement
Where Net Income is Presented

 

Net gains / (losses) on cash flow hedges

 

 

 

 

 

Commodity contracts

 

$

13,328

 

Natural gas revenues

 

Commodity contracts

 

2,042

 

Crude oil and condensate revenues

 

 

 

 

 

 

 

Postretirement benefits

 

 

 

 

 

Amortization of net loss

 

(205

)

General and administrative expense

 

 

 

$

15,165

 

Total before tax

 

 

 

$

(5,965

)

Tax (expense) / benefit

 

Total reclassifications for the period

 

$

9,200

 

Net of tax

 

 

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Table of Contents

 

10. PENSION AND 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

 

 

 

March 31,

 

(In thousands)

 

2013

 

2012

 

Qualified Pension Plan

 

 

 

 

 

Interest cost

 

$

 

$

461

 

Expected return on plan assets

 

 

(874

)

Amortization of prior service cost

 

 

111

 

Amortization of net loss

 

 

6,542

 

Net periodic pension cost

 

$

 

$

6,240

 

 

 

 

 

 

 

Postretirement Benefits

 

 

 

 

 

Service cost

 

$

415

 

$

523

 

Interest cost

 

395

 

418

 

Amortization of net loss

 

205

 

280

 

Total postretirement benefit cost

 

$

1,015

 

$

1,221

 

 

11. STOCK-BASED COMPENSATION

 

Stock-based compensation expense during the first three months of 2013 and 2012 was $18.7 million and $1.7 million, respectively, and is included in general and administrative expense in the Condensed Consolidated Statement of Operations.

 

Restricted Stock Units

 

During the first three months of 2013, 22,560 restricted stock units were granted to non-employee directors of the Company with a grant date per unit value of $53.23. The fair value of these units is measured based on the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and will be issued when the director ceases to be a director of the Company.

 

Performance Share Awards

 

During the first three months of 2013, three types of performance share awards were granted to employees for a total of 402,250 performance shares, which included 274,760 performance share awards based on performance conditions measured against the Company’s internal performance metrics and 127,490 performance share awards based on market conditions. The Company used an annual forfeiture rate assumption ranging from 0% to 6% for purposes of recognizing stock-based compensation expense for all performance share awards. The performance period for the awards granted in 2013 commenced on January 1, 2013 and ends on December 31, 2015.  Refer to Note 12 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of performance share awards.

 

Awards Based on Performance Conditions. The performance awards based on internal metrics had a grant date per share value of $53.23, which is based on the average of the high and low stock price on the grant date. These awards represent the right to receive up to 100% of the award in shares of common stock.  Of the 274,760 performance awards based on internal metrics, 84,990 shares have a three-year graded performance period. For these shares, 25% of the shares vest on each of the first and second anniversary dates following the date of the grant and 50% of the shares vest on the third anniversary date following the date of the grant, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date. If the Company does not meet this metric for the applicable period, then the portion of the performance shares that would have been issued on that anniversary date will be forfeited.

 

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Table of Contents

 

For the remaining 189,770 performance awards, the actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the 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 March 31, 2013, it is considered probable that the criteria for the performance awards based on performance conditions will be met.

 

Awards Based on Market Conditions. The 127,490 performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen 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 2013 awards was valued on the grant date (February 21, 2013) and was not marked to market. The liability portion of the awards was valued as of March 31, 2013 on a mark-to-market basis.

 

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

 

 

 

Grant Date

 

March 31, 2013

 

Value per Share

 

$46.12

 

$40.86 - $67.51

 

Assumptions:

 

 

 

 

 

Stock Price Volatility

 

43.8

%

33.0% - 46.1%

 

Risk Free Rate of Return

 

0.4

%

0.1% - 0.3%

 

Expected Dividend Yield

 

0.2

%

0.1%

 

 

Supplemental Employee Incentive Plan

 

On May 1, 2012, the Company’s Board of Directors adopted a new Supplemental Employee Incentive Plan (“Plan”) to replace the previously adopted supplemental employee incentive plan that expired on June 30, 2012. For further information regarding the terms of the Plan, refer to Note 12 of the Notes to the Consolidated Financial Statements in the Form 10-K. The Company recognized stock-based compensation expense of $3.4 million for the three months ended March 31, 2013 and a benefit of $1.7 million for the three months ended March 31, 2012, which is included in general and administrative expense in the Condensed Consolidated Statement of Operations.

 

On February 11, 2013, the Company achieved the price goal of $50 per share prior to the interim trigger date. Accordingly, a total distribution of approximately $6.8 million was made to the Company’s eligible employees under the Plan, of which 25% of the total distribution, or $1.7 million, was paid in February 2013 and the remaining 75%, or $5.1 million, was deferred until August 2014 in accordance with the Plan.

 

12. ASSET RETIREMENT OBLIGATION

 

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

 

(In thousands)

 

 

 

Balance at December 31, 2012

 

$

67,016

 

Liabilities incurred

 

1,396

 

Liabilities settled

 

(195

)

Accretion expense

 

876

 

Balance at March 31, 2013

 

$

69,093

 

 

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Table of Contents

 

Report of Independent Registered Public Accounting Firm

 

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

 

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of March 31, 2013, and the related condensed consolidated statements of operations and of comprehensive income for the three-month periods ended March 31, 2013 and 2012 and the condensed consolidated statement of cash flows for the three-month periods ended March 31, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.

 

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

 

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

 

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and of cash flows for the year then ended (not presented herein), and in our report dated February 28, 2013, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet information as of December 31, 2012, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

 

/s/ PricewaterhouseCoopers LLP

 

Houston, Texas

April 26, 2013

 

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

 

The following review of operations for the three month periods ended March 31, 2013 and 2012 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Corporation Annual Report on Form 10-K for the year ended December 31, 2012 (Form 10-K).

 

Overview

 

On an equivalent basis, our production for the three months ended March 31, 2013 increased by 50% compared to the three months ended March 31, 2012. For the three months ended March 31, 2013, we produced 89.3 Bcfe, or 992.3 Mmcfe per day, compared to 59.7 Bcfe, or 655.7 Mmcfe per day, for three months ended March 31, 2012. Natural gas production increased by 28.8 Bcf, or 51%, to 85.2 Bcf for the first three months of 2013 compared to 56.4 Bcf for the first three months of 2012. This increase was primarily the result of increased production in the Marcellus Shale associated with our drilling program and continued expansion of infrastructure in the area. This increase was partially offset by decreases in production in Texas, Oklahoma and West Virginia due to reduced natural gas drilling  and normal production declines. Crude oil/condensate/NGL production increased by 153 Mbbls, or 28%, from 538 Mbbls in the first three months of 2012 to 691 Mbbls in the first three months of 2013. This increase was primarily the result of increased production resulting from our Eagle Ford Shale drilling program in south Texas and the Marmaton oil play in Oklahoma.

 

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Our average realized natural gas price for the first three months of 2013 was $3.45 per Mcf, 5% lower than the $3.65 per Mcf price realized in the first three months of 2012. Our average realized crude oil price for the first three months of 2013 was $104.03 per Bbl, 8% higher than the $96.67 per Bbl price realized in the first three months of 2012. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to “Results of Operations” below. Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes or future revenues. 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.

 

During the first three months of 2013, we drilled 32 gross wells (25.9 net) with a success rate of 97% compared to 31 gross wells (23.4 net) with a success rate of 100% for the comparable period of the prior year. For the three months ended March 31, 2013, our total capital and exploration spending was $253.5 million compared to $192.1 million for the three months ended March 31, 2012. The increase in capital spending was primarily due to our Marcellus Shale horizontal drilling program in northeast Pennsylvania, the Eagle Ford and Pearsall Shale in south Texas and the Marmaton oil play in Oklahoma. For the full year 2013, we plan to drill approximately 170 to 180 gross wells (130 to 145 net). Our 2013 drilling program includes between $950.0 million and $1.0 billion in capital and exploration expenditures and is expected to be funded by operating cash flow, existing cash and, if required, borrowings under our credit facility. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

 

Financial Condition

 

Capital Resources and Liquidity

 

Our primary sources of cash for the three months ended March 31, 2013 were funds generated from the sale of natural gas and crude oil production (including realizations from our derivative instruments) 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.

 

Operating cash flow fluctuations are substantially driven by commodity prices, changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been and continue to be volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of

 

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other risks and uncertainties, as described in our Form 10-K and other filings with the Securities and Exchange Commission, have also influenced prices throughout the recent years. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on revenues.

 

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

 

 

 

Three Months Ended

 

 

 

March 31,

 

(In thousands)

 

2013

 

2012

 

Cash flows provided by operating activities

 

$

212,685

 

$

131,780

 

Cash flows used in investing activities

 

(260,933

)

(187,267

)

Cash flows provided by financing activities

 

37,969

 

57,904

 

Net (decrease) / increase in cash and cash equivalents

 

$

(10,279

)

$

2,417

 

 

Operating Activities.  Net cash provided by operating activities in the first three months of 2013 increased by $80.9 million over the first three months of 2012. This increase was primarily due to higher operating revenues partially offset by higher operating expenses (excluding non-cash expenses) and unfavorable changes in working capital and long-term assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices. Equivalent production volumes increased by 50% for the three months ended March 31, 2013 compared to the three months ended March 31, 2012. Average realized crude oil prices increased by 8% while average realized natural gas prices decreased by 5% for the first three months of 2013 compared to the first three months of 2012.

 

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

 

Investing Activities. Cash flows used in investing activities increased by $73.7 million for the first three months of 2013 compared to the first three months of 2012. The increase was primarily due an increase of $71.6 million in capital expenditures and $1.3 million of capital contributions associated with our equity method investment in Constitution Pipeline Company, LLC (Constitution). This increase was partially offset by a decrease of $0.8 million in proceeds from sale of assets.

 

Financing Activities. Cash flows provided by financing activities decreased by $19.9 million for the first three months of 2013 compared to the first three months of 2012. This decrease was primarily due to $22.0 million of lower net borrowings ($67.0 million increase in repayments of debt offset by $45.0 million increase in borrowings), partially offset by an increase of $2.1 million in tax benefits associated with our stock-based compensation.

 

At March 31, 2013, we had $365.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 2.3% and $534.0 million available for future borrowings.  Effective April 17, 2013, the lenders under our revolving credit facility approved an increase in our borrowing base from $1.7 billion to $2.3 billion as part of the annual redetermination under the terms of the revolving credit facility.

 

We were in compliance with all restrictive financial covenants in both the revolving credit facility and senior notes as of March 31, 2013.

 

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

 

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Capitalization

 

Information about our capitalization is as follows:

 

 

 

March 31,

 

December 31,

 

(Dollars in thousands)

 

2013

 

2012

 

 

 

 

 

 

 

Debt (1)

 

$

1,127,000

 

$

1,087,000

 

Stockholders’ equity

 

2,123,214

 

2,131,447

 

Total capitalization

 

$

3,250,214

 

$

3,218,447

 

 

 

 

 

 

 

Debt to capitalization

 

35%

 

34%

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

20,457

 

$

30,736

 

 


(1)             Includes $75.0 million of current portion of long-term debt at March 31, 2013 and December 31, 2012 and $365.0 million and $325.0 million of borrowings outstanding under our revolving credit facility at March 31, 2013 and December 31, 2012, respectively.

 

During the three months ended March 31, 2013, we paid dividends of $4.2 million ($0.02 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

 

Capital and Exploration Expenditures

 

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

 

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

 

 

 

Three Months Ended

 

 

 

March 31,

 

(In thousands)

 

2013

 

2012

 

Capital expenditures

 

 

 

 

 

Drilling and facilities

 

$

233,143

 

$

173,368

 

Leasehold acquisitions

 

16,177

 

15,147

 

Pipeline and gathering

 

108

 

(428

)

 

 

249,428

 

188,087

 

Exploration expense

 

4,024

 

4,001

 

Total

 

$

253,452

 

$

192,088

 

 

For the full year of 2013, we plan to drill approximately 170 to 180 gross wells (130 to 145 net). Our 2013 drilling program includes between $950.0 million to $1.0 billion in total planned capital and exploration expenditures. See “Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

 

Contractual Obligations

 

We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations described under “Transportation Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 8 in the Notes to Consolidated Financial Statements and the obligations described under “Contractual Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K.

 

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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 in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Form 10-K for further discussion of our critical accounting policies.

 

Recent Accounting Pronouncements

 

Effective January 1, 2013, we adopted the amended disclosure requirements prescribed in Accounting Standards Update (ASU) No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” and ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This guidance impacted the disclosures associated with our commodity derivatives and did not impact our consolidated financial position, results of operations or cash flows.

 

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

 

Results of Operations

 

First Quarters of 2013 and 2012 Compared

 

We reported net income in the first quarter of 2013 of $42.8 million, or $0.20 per share, compared to $18.3 million, or $0.09 per share, in the first quarter of 2012. The increase in net income was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices and higher operating expenses.

 

Revenue, Price and Volume Variances

 

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

 

 

 

Three Months Ended March 31,

 

Variance

 

Revenue Variances (In thousands)

 

2013

 

2012

 

Amount

 

Percent

 

Natural gas (1)

 

$

293,793

 

$

206,740

 

$

87,053

 

42%

 

Crude oil and condensate

 

65,655

 

49,981

 

15,674

 

31%

 

Brokered natural gas

 

10,893

 

13,444

 

(2,551

)

(19%

)

Other

 

2,944

 

1,929

 

1,015

 

53%

 

 


(1)             Natural gas revenues exclude the unrealized gain of $42,000 from the change in fair value of our derivatives not designated as hedges in 2012. There were no unrealized gains or losses in 2013.

 

 

 

 

 

 

 

 

 

 

 

Increase

 

 

 

Three Months Ended March 31,

 

Variance

 

(Decrease)

 

 

 

2013

 

2012

 

Amount

 

Percent

 

(In thousands)

 

Price Variances

 

 

 

 

 

 

 

 

 

 

 

Natural gas (1)

 

$

3.45

 

$

3.65

 

$

(0.20

)

(5%

)

$

(17,142

)

Crude oil and condensate (2)

 

$

104.03

 

$

96.67

 

$

7.36

 

8%

 

4,643

 

Total

 

 

 

 

 

 

 

 

 

$

(12,499

)

Volume Variances

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

85.2

 

56.4

 

28.8

 

51%

 

$

104,195

 

Crude oil and condensate (Mbbl)

 

631

 

517

 

114

 

22%

 

11,031

 

Total

 

 

 

 

 

 

 

 

 

$

115,226

 

 


(1)             These prices include the realized impact of derivative instrument settlements, which increased the price by $0.16 per Mcf in 2013 and by $1.00 per Mcf in 2012.

(2)             These prices include the realized impact of derivative instrument settlements, which increased the price by $3.24 per Bbl in 2013 and decreased the price by $2.57 per Bbl in 2012.

 

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Natural Gas Revenues

 

The increase in natural gas revenues of $87.1 million, excluding the impact of the unrealized losses discussed above, is primarily due to increased production partially offset by lower realized natural gas prices. The increased production was primarily a result of higher production in the Marcellus Shale associated with our drilling program and expanded infrastructure, partially offset by decreases in production primarily in Texas, Oklahoma and West Virginia due reduced natural gas drilling and normal production declines.

 

Crude Oil and Condensate Revenues

 

The increase in crude oil and condensate revenues of $15.7 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

 

 

 

March 31,

 

Variance

 

Variances

 

 

 

2013

 

2012

 

Amount

 

Percent

 

(In thousands)

 

Brokered Natural Gas Sales

 

 

 

 

 

 

 

 

 

 

 

Sales price ($/Mcf)

 

$

3.55

 

$

4.06

 

$

(0.51

)

(13%

)

$

(1,560

)

Volume brokered (Mmcf)

 

x

3,067

 

x

3,311

 

(244

)

(7%

)

(991

)

Brokered natural gas (In thousands)

 

$

10,893

 

$

13,444

 

 

 

 

 

$

(2,551

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Purchases

 

 

 

 

 

 

 

 

 

 

 

Purchase price ($/Mcf)

 

$

2.74

 

$

3.59

 

$

(0.85

 

(24%

)

$

2,608

 

Volume brokered (Mmcf)

 

x

3,067

 

x

3,311

 

(244

 

(7%

)

875

 

Brokered natural gas (In thousands)

 

$

8,389

 

$

11,872

 

 

 

 

 

$

3,483

 

 

 

 

 

 

 

 

 

 

 

 

 

Brokered natural gas margin (In thousands)

 

$

2,504

 

$

1,572

 

 

 

 

 

$

932

 

 

The increased brokered natural gas margin of $0.9 million is primarily a result a decrease in purchase price that outpaced the decrease in sales price, partially offset by lower brokered volumes.

 

Impact of Derivative Instruments on Operating Revenues

 

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

 

 

 

Three Months Ended
March 31,

 

(In thousands)

 

2013

 

2012

 

 

 

 

 

 

 

Cash Flow Hedges

 

 

 

 

 

Natural gas

 

$

13,328

 

$

56,996

 

Crude oil

 

2,042

 

(1,326

)

Other Derivative Financial Instruments

 

 

 

 

 

Natural gas basis swaps

 

 

42

 

 

 

$

15,370

 

$

55,712

 

 

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Operating and Other Expenses

 

 

 

Three Months Ended March 31,

 

Variance

 

(In thousands)

 

2013

 

2012

 

Amount

 

Percent

 

Operating and Other Expenses

 

 

 

 

 

 

 

 

 

Direct operations

 

$

31,497

 

$

27,320

 

$

4,177

 

15%

 

Transportation and gathering

 

46,221

 

30,258

 

15,963

 

53%

 

Brokered natural gas

 

8,389

 

11,872

 

(3,483

)

(29%

)

Taxes other than income

 

11,687

 

18,583

 

(6,896

)

(37%

)

Exploration

 

4,024

 

4,001

 

23

 

1%

 

Depreciation, depletion and amortization

 

148,653

 

110,357

 

38,296

 

35%

 

General and administrative

 

35,704

 

22,549

 

13,155

 

58%

 

Total operating expense

 

$

286,175

 

$

224,940

 

$

61,235

 

27%

 

 

 

 

 

 

 

 

 

 

 

(Gain) / loss on sale of assets

 

$

96

 

$

535

 

$

(439

)

(82%

)

Interest expense and other

 

16,255

 

16,917

 

(662

)

(4%

)

Income tax expense

 

27,935

 

11,426

 

16,509

 

144%

 

 

Total costs and expenses from operations increased by $61.2 million, or 27%, in the first quarter of 2013 compared to the same period of 2012. The primary reasons for this fluctuation are as follows:

 

·                  Direct operations increased $4.2 million largely due to higher operating costs primarily driven by increased production. Contributing to the increase are higher employee related costs, partially offset by decreased workover activity.

 

·                  Transportation and gathering increased $16.0 million due to higher throughput due to an increase in production and higher transportation rates, coupled with the commencement of various transportation and gathering agreements throughout 2012 primarily in northeast Pennsylvania and south Texas.

 

·                  Brokered natural gas decreased $3.5 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

·                  Taxes other than income decreased $6.9 million primarily due to lower impact fees associated with our Marcellus Shale production. The first quarter of 2012 included the initial assessment of impact fees associated with 2011 and prior period wells.

 

·                  Depreciation, depletion and amortization increased $38.3 million, of which $49.9 million was due to higher equivalent production volumes for the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012, partially offset by a decrease of $10.7 million due to a lower DD&A rate of $1.56 per Mcfe for the quarter ended March 31, 2013 compared to $1.68 Mfce for the quarter ended March 31, 2012. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our 2013 and 2012 drilling programs. The increase in depreciation and depletion was partially offset by a decrease in amortization of unproved properties of $1.1 million.

 

·                  General and administrative increased $13.2 million primarily due to $17.0 million of higher stock-based compensation expense associated with the mark-to-market of our liability-based performance awards and our supplemental employee incentive plan due to changes in our stock price for the first quarter 2013 compared to the first quarter of 2012, partially offset by $6.2 million of lower pension expense associated with the liquidation of our pension plan that occurred in the second quarter of 2012.

 

Interest Expense and Other

 

Interest expense and other decreased $0.7 million primarily due a to lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.3% during the first quarter of 2013 compared to approximately 4.0% during the first quarter of 2012, partially offset by an increase in weighted-average borrowings under our revolving credit facility based

 

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on daily balances of approximately $361.6 million during the first quarter of 2013 compared to approximately $235.4 million during the first quarter of 2012.

 

Income Tax Expense

 

Income tax expense increased $16.5 million primarily due to higher pretax income and a slightly higher effective tax rate. The effective tax rate for the first quarter of 2013 and 2012 was 39.5% and 38.4%, respectively. The increase in the effective rate in 2013 was due to an increase in estimated state tax liabilities.

 

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. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A of the Form 10-K for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

 

ITEM  3.                     Quantitative and Qualitative Disclosures about Market Risk

 

Market Risk

 

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

 

Derivative Instruments and Hedging Activity

 

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 13 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our hedging arrangements.

 

Periodically, we enter into commodity derivative instruments, including collar and swap agreements, to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

 

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As of March 31, 2013, we had the following outstanding commodity derivatives:

 

Commodity and Derivative Type

 

Weighted-Average Contract Price

 

Volume

 

Contract Period

 

Net Unrealized
Gain / (Loss) 
(In thousands)

 

Natural gas collars

 

$3.09 Floor / $4.12 Ceiling

 

per Mcf

 

26.7

 

Bcf

 

Apr. 2013 - Dec. 2013

 

$

(8,177

)

Natural gas collars

 

$3.35 Floor / $4.01 Ceiling

 

per Mcf

 

26.7

 

Bcf

 

Apr. 2013 - Dec. 2013

 

(9,453

)

Natural gas collars

 

$3.40 Floor / $4.12 Ceiling

 

per Mcf

 

13.4

 

Bcf

 

Apr. 2013 - Dec. 2013

 

(3,826

)

Natural gas collars

 

$3.60 Floor / $3.99 Ceiling

 

per Mcf

 

13.4

 

Bcf

 

Apr. 2013 - Dec. 2013

 

(4,597

)

Natural gas collars

 

$3.60 Floor / $4.17 Ceiling

 

per Mcf

 

13.4

 

Bcf

 

Apr. 2013 - Dec. 2013

 

(3,189

)

Natural gas collars

 

$3.76 Floor / $4.16 Ceiling

 

per Mcf

 

13.4

 

Bcf

 

Apr. 2013 - Dec. 2013

 

(2,246

)

Natural gas collars

 

$3.86 Floor / $4.34 Ceiling

 

per Mcf

 

13.4

 

Bcf

 

Apr. 2013 - Dec. 2013

 

(996

)

Natural gas collars

 

$3.96 Floor / $4.41 Ceiling

 

per Mcf

 

13.4

 

Bcf

 

Apr. 2013 - Dec. 2013

 

(904

)

Natural gas collars

 

$5.15 Floor / $6.20 Ceiling

 

per Mcf

 

13.4

 

Bcf

 

Apr. 2013 - Dec. 2013

 

13,370

 

Natural gas collars

 

$3.60 Floor / $4.58 Ceiling

 

per Mcf

 

31.1

 

Bcf

 

Apr. 2013 - Dec. 2014

 

(5,391

)

Natural gas collars

 

$3.96 Floor / $4.56 Ceiling

 

per Mcf

 

31.1

 

Bcf

 

Apr. 2013 - Dec. 2014

 

(2,324

)

Natural gas collars

 

$3.86 Floor / $4.66 Ceiling

 

per Mcf

 

17.7

 

Bcf

 

Jan. 2014 - Dec. 2014

 

(2,071

)

Natural gas collars

 

$4.12 Floor / $4.64 Ceiling

 

per Mcf

 

35.5

 

Bcf

 

Jan. 2014 - Dec. 2014

 

(468

)

Crude oil swaps

 

$101.90

 

per Bbl

 

825

 

Mbbl

 

Apr. 2013 - Dec. 2013

 

4,218

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(26,054

)

 

The amounts set forth under the net unrealized gain / (loss) column in the table above represent our total unrealized gain position at March 31, 2013 and exclude the impact of nonperformance risk. Nonperformance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our nonperformance risk is evaluated using a market credit spread provided by one of our banks.

 

During the first three months of 2013, crude oil swaps covered 270 Mbbl, or 43% of crude oil production at an average price of $101.90 per Bbl. Natural gas collars with a floor prices ranging from $3.09 to $5.15 per Mcf and ceiling prices ranging from $3.98 to $6.23 per Mcf covered 43.7 Bcf, or 51%, of our natural gas production at an average price of $3.72 per Mcf.

 

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

 

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

 

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 amount we would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and credit facility is based on interest rates currently available to us.

 

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Table of Contents

 

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:

 

 

 

March 31, 2013

 

December 31, 2012

 

(In thousands)

 

Carrying
Amount

 

Estimated
Fair Value

 

Carrying
Amount

 

Estimated
Fair Value

 

Total debt

 

$

1,127,000

 

$

1,249,576

 

$

1,087,000

 

$

1,213,474

 

Current maturities

 

(75,000

)

(76,279

)

(75,000

)

(77,175

)

Long-term debt, excluding current maturities

 

$

1,052,000

 

$

1,173,297

 

$

1,012,000

 

$

1,136,299

 

 

ITEM  4.                      Controls and Procedures

 

As of the end of the current reported period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our 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 our disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

 

There were no changes in our internal control over financial reporting that occurred during the first quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II. OTHER INFORMATION

 

ITEM  1.                      Legal Proceedings

 

Legal Matters

 

The information set forth under the heading “Legal Matters” in Note 6 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this quarterly report is incorporated by reference in response to this item.

 

Environmental Matters

 

The information set forth under the heading “Environmental Matters” in Note 6 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this quarterly report is incorporated by reference in response to this item.

 

From time to time we receive notices of v