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Coterra Energy Inc. - Quarter Report: 2014 June (Form 10-Q)

Table of Contents

 

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-Q

 


 

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

 

For the quarterly period ended June 30, 2014

 

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 21, 2014, there were 417,294,125 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, 2014 and December 31, 2013

3

 

 

 

Condensed Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2014 and 2013

4

 

 

 

Condensed Consolidated Statement of Comprehensive Income for the Three and Six Months Ended June 30, 2014 and 2013

5

 

 

 

Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2014 and 2013

6

 

 

 

Notes to the Condensed Consolidated Financial Statements

7

 

 

 

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

19

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

20

 

 

 

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

30

 

 

 

Item 4.

Controls and Procedures

31

 

 

 

Part II. Other Information

 

 

 

 

Item 1.

Legal Proceedings

31

 

 

 

Item 1A.

Risk Factors

31

 

 

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

31

 

 

 

Item 6.

Exhibits

32

 

 

Signatures

33

 

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)

 

2014

 

2013

 

ASSETS

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

45,610

 

$

23,400

 

Restricted cash

 

 

28,094

 

Accounts receivable, net

 

212,100

 

222,476

 

Inventories

 

11,914

 

17,468

 

Deferred income taxes

 

32,947

 

81,855

 

Other current assets

 

3,525

 

5,606

 

Total current assets

 

306,096

 

378,899

 

Properties and equipment, net (Successful efforts method)

 

4,825,524

 

4,546,227

 

Equity method investments

 

49,854

 

26,892

 

Other assets

 

27,448

 

29,062

 

 

 

$

5,208,922

 

$

4,981,080

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities

 

 

 

 

 

Accounts payable

 

$

255,681

 

$

288,801

 

Accrued liabilities

 

59,734

 

73,601

 

Derivative instruments

 

38,493

 

13,912

 

Income taxes payable

 

8,239

 

31,591

 

Total current liabilities

 

362,147

 

407,905

 

Postretirement benefits

 

35,212

 

33,554

 

Long-term debt

 

1,193,000

 

1,147,000

 

Deferred income taxes

 

1,101,326

 

1,067,912

 

Asset retirement obligation

 

77,459

 

73,853

 

Other liabilities

 

37,839

 

46,254

 

Total liabilities

 

2,806,983

 

2,776,478

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity

 

 

 

 

 

Common stock:

 

 

 

 

 

Authorized — 960,000,000 and 480,000,000 shares of $0.10 par value in 2014 and 2013, respectively

 

 

 

 

 

Issued — 422,911,309 and 422,014,681 shares in 2014 and 2013, respectively

 

42,291

 

42,201

 

Additional paid-in capital

 

723,218

 

710,940

 

Retained earnings

 

1,836,577

 

1,627,805

 

Accumulated other comprehensive income (loss)

 

(32,164

)

(8,361

)

Less treasury stock, at cost:

 

 

 

 

 

5,618,166 shares in 2014 and 2013

 

(167,983

)

(167,983

)

Total stockholders’ equity

 

2,401,939

 

2,204,602

 

 

 

$

5,208,922

 

$

4,981,080

 

 

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 OPERATIONS (Unaudited)

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

(In thousands, except per share amounts)

 

2014

 

2013

 

2014

 

2013

 

OPERATING REVENUES

 

 

 

 

 

 

 

 

 

Natural gas

 

$

437,761

 

$

368,391

 

$

870,571

 

$

662,184

 

Crude oil and condensate

 

86,341

 

70,226

 

145,485

 

135,881

 

Gain (loss) on derivative instruments

 

(2,329

)

 

(2,329

)

 

Brokered natural gas

 

8,140

 

8,244

 

21,293

 

19,137

 

Other

 

3,274

 

2,819

 

7,970

 

5,763

 

 

 

533,187

 

449,680

 

1,042,990

 

822,965

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

Direct operations

 

35,605

 

36,978

 

71,439

 

68,475

 

Transportation and gathering

 

83,976

 

52,648

 

161,741

 

98,869

 

Brokered natural gas

 

7,031

 

6,704

 

18,891

 

15,093

 

Taxes other than income

 

12,816

 

11,364

 

25,860

 

23,051

 

Exploration

 

4,676

 

4,529

 

11,150

 

8,553

 

Depreciation, depletion and amortization

 

157,563

 

151,389

 

304,981

 

300,042

 

General and administrative

 

20,127

 

21,608

 

41,763

 

57,312

 

 

 

321,794

 

285,220

 

635,825

 

571,395

 

Earnings (loss) on equity method investments

 

756

 

290

 

756

 

336

 

Gain (loss) on sale of assets

 

(1,496

)

276

 

(2,781

)

180

 

INCOME FROM OPERATIONS

 

210,653

 

165,026

 

405,140

 

252,086

 

Interest expense

 

16,334

 

16,991

 

32,891

 

33,292

 

Income before income taxes

 

194,319

 

148,035

 

372,249

 

218,794

 

Income tax expense

 

75,899

 

58,921

 

146,798

 

86,856

 

NET INCOME

 

$

118,420

 

$

89,114

 

$

225,451

 

$

131,938

 

 

 

 

 

 

 

 

 

 

 

Earnings per share

 

 

 

 

 

 

 

 

 

Basic

 

$

0.28

 

$

0.21

 

$

0.54

 

$

0.32

 

Diluted

 

$

0.28

 

$

0.21

 

$

0.54

 

$

0.31

 

 

 

 

 

 

 

 

 

 

 

Weighted-average common shares outstanding

 

 

 

 

 

 

 

 

 

Basic

 

417,291

 

420,698

 

417,097

 

420,500

 

Diluted

 

419,092

 

423,490

 

418,742

 

422,984

 

 

 

 

 

 

 

 

 

 

 

Dividends per common share

 

$

0.02

 

$

0.01

 

$

0.04

 

$

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
June 30,

 

Six Months Ended
June 30,

 

(In thousands)

 

2014

 

2013

 

2014

 

2013

 

Net income

 

$

118,420

 

$

89,114

 

$

225,451

 

$

131,938

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

 

 

 

 

Reclassification adjustment for settled cash flow hedge contracts(1)

 

13,807

 

(1,105

)

56,372

 

(10,430

)

Changes in fair value of cash flow hedge contracts(2) 

 

 

69,839

 

(80,175

)

32,864

 

Postretirement benefits:

 

 

 

 

 

 

 

 

 

Amortization of net loss(3) 

 

 

124

 

 

249

 

Total other comprehensive income (loss)

 

13,807

 

68,858

 

(23,803

)

22,683

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

132,227

 

$

157,972

 

$

201,648

 

$

154,621

 

 


(1)    Net of income taxes of $(9,149) and $717 for the three months ended June 30, 2014 and 2013, respectively, and $(37,359) and $6,762 for the six months ended June 30, 2014 and 2013, respectively.

(2)    Net of income taxes of $(45,274) for the three months ended June 30, 2013 and $53,135 and $(21,303) for the six months ended June 30, 2014 and 2013, respectively.

(3)    Net of income taxes of $(81) and $(161) for the three and six months ended June 30, 2013, respectively.

 

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 CASH FLOWS (Unaudited)

 

 

 

Six Months Ended
June 30,

 

(In thousands)

 

2014

 

2013

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

225,451

 

$

131,938

 

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

 

 

 

 

 

Depreciation, depletion and amortization

 

304,981

 

300,042

 

Deferred income tax expense

 

118,453

 

69,662

 

(Gain) loss on sale of assets

 

2,781

 

(180

)

Exploration expense

 

2,154

 

806

 

Unrealized (gain) loss on derivative instruments

 

(12,933

)

 

Amortization of debt issuance costs

 

2,252

 

1,842

 

Stock-based compensation and other

 

8,689

 

27,355

 

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable, net

 

9,588

 

(32,551

)

Income taxes

 

(23,352

)

(4,971

)

Inventories

 

5,554

 

(4,103

)

Other current assets

 

15

 

(2,733

)

Accounts payable and accrued liabilities

 

(39,084

)

9,661

 

Other assets and liabilities

 

753

 

547

 

Stock-based compensation tax benefit

 

(20,354

)

(7,348

)

Net cash provided by operating activities

 

584,948

 

489,967

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Capital expenditures

 

(617,613

)

(524,056

)

Proceeds from sale of assets

 

(755

)

906

 

Restricted cash

 

28,094

 

 

Investment in equity method investments

 

(22,230

)

(4,250

)

Net cash used in investing activities

 

(612,504

)

(527,400

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings from debt

 

611,000

 

325,000

 

Repayments of debt

 

(565,000

)

(270,000

)

Dividends paid

 

(16,679

)

(8,407

)

Stock-based compensation tax benefit

 

20,354

 

7,348

 

Other

 

91

 

33

 

Net cash provided by financing activities

 

49,766

 

53,974

 

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

22,210

 

16,541

 

Cash and cash equivalents, beginning of period

 

23,400

 

30,736

 

Cash and cash equivalents, end of period

 

$

45,610

 

$

47,277

 

 

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, 2013 (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 the 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 June 30, 2014 and for the three and six months ended June 30, 2014 and 2013, 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 25, 2014 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 a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

 

Recent Accounting Pronouncements

 

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. The Company does not expect the adoption of this guidance to have a material impact on its financial position or results of operations.

 

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective beginning in fiscal year 2017 and can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows.

 

2. Properties and Equipment, Net

 

Properties and equipment, net are comprised of the following:

 

 

 

June 30,

 

December 31,

 

(In thousands)

 

2014

 

2013

 

 

 

 

 

 

 

Proved oil and gas properties

 

$

6,954,493

 

$

6,362,570

 

Unproved oil and gas properties

 

352,182

 

375,428

 

Gathering and pipeline systems

 

240,201

 

239,958

 

Land, buildings and other equipment

 

101,026

 

94,243

 

 

 

7,647,902

 

7,072,199

 

Accumulated depreciation, depletion and amortization

 

(2,822,378

)

(2,525,972

)

 

 

$

4,825,524

 

$

4,546,227

 

 

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Table of Contents

 

At June 30, 2014, 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.

 

3. Equity Method Investments

 

For further information regarding the Company’s equity method investments, refer to Note 4 of the Notes to the Consolidated Financial Statements in the Form 10-K.

 

Meade Pipeline Co LLC

 

In February 2014, the Company acquired a 20% equity interest in Meade Pipeline Co LLC (Meade). Meade was formed to participate in the development and construction of a 177-mile pipeline (Central Penn Line) that will transport natural gas from Susquehanna County, Pennsylvania to an interconnect with Transcontinental Gas Pipe Line Company, LLC’s (Transco) mainline in Lancaster County, Pennsylvania. The new pipeline will be constructed and operated by Transco and will be owned by Transco and Meade in proportion to their respective ownership percentages of approximately 61% and 39%, respectively. Under the terms of the Meade LLC agreement, the Company agreed to invest its proportionate share of Meade’s anticipated costs associated with the new pipeline of $149 million, which is expected to occur over the next three to four years. The expected in-service date for the new pipeline is scheduled for the second half of 2017. During 2014, the Company made contributions of approximately $1.2 million to Meade.

 

4. Debt and Credit Agreements

 

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

 

 

 

June 30,

 

December 31,

 

(In thousands)

 

2014

 

2013

 

Long-Term Debt

 

 

 

 

 

7.33% weighted-average fixed rate notes

 

$

20,000

 

$

20,000

 

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

 

Revolving Credit facility

 

506,000

 

460,000

 

 

 

$

1,193,000

 

$

1,147,000

 

 

Effective April 15, 2014, the lenders under the Company’s revolving credit facility approved an increase in the Company’s borrowing base from $2.3 billion to $3.1 billion as part of the annual redetermination under the terms of the revolving credit facility agreement. The commitments under the revolving credit facility remain unchanged at $1.4 billion. At June 30, 2014, the Company had $506.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 1.9% and $893.0 million available for future borrowings.

 

The Company was in compliance with all restrictive financial covenants for both the revolving credit facility and fixed rate notes as of June 30, 2014.

 

5. Derivative Instruments and Hedging Activities

 

The Company periodically enters into commodity derivatives to manage 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 derivatives other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and where such derivatives do not subject the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes.

 

Effective April 1, 2014, the Company elected to discontinue hedge accounting for its commodity derivatives on a prospective basis. Through March 31, 2014, the Company elected to designate its commodity derivatives as cash flow hedges for accounting purposes. Accordingly, the change in the fair value of derivatives designated as hedges that are 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 the fair value of derivatives designated as hedges and the change in fair value of realized cash settlements of derivatives not designated as hedges are recorded as a component of operating revenues in gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

 

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Table of Contents

 

As a result of discontinuing hedge accounting, the unrealized loss included in accumulated other comprehensive income (loss) as of April 1, 2014 of $73.4 million ($44.2 million net of tax) was frozen and will be reclassified into natural gas and crude oil revenues in the Statement of Operations in future periods as the underlying hedge transactions occur. As of June 30, 2014, the Company  expects to reclassify $30.4 million in after-tax losses associated with its commodity derivatives from accumulated other comprehensive income (loss) to natural gas and crude oil revenues in the Condensed Consolidated Statement of Operations over the next six months.

 

As of June 30, 2014, the Company had the following outstanding commodity derivatives:

 

 

 

 

 

 

 

 

 

Collars

 

Swaps

 

 

 

 

 

 

 

 

 

Floor

 

Ceiling

 

 

 

Type of Contract

 

Volume

 

Contract Period

 

Range

 

Weighted-Average

 

Range

 

Weighted-Average

 

Weighted- Average

 

Natural gas

 

169.8

 

Bcf

 

Jul. 2014 - Dec. 2014

 

$3.60-$4.37

 

$

4.13

 

$4.22-$4.80

 

$

4.51

 

 

 

Natural gas

 

53.6

 

Bcf

 

Jul. 2014 - Dec. 2014

 

 

 

 

 

 

 

 

 

$

4.05

 

Crude oil

 

368.0

 

Mbbl

 

Jul. 2014 - Dec. 2014

 

 

 

 

 

 

 

 

 

$

97.00

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet

 

 

 

 

 

Fair Values of Derivative Instruments

 

 

 

 

 

Derivative Assets

 

Derivative Liabilities

 

 

 

 

 

June 30,

 

December 31,

 

June 30,

 

December 31,

 

(In thousands)

 

Balance Sheet Location

 

2014

 

2013

 

2014

 

2013

 

Derivatives Designated as Hedges

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Other current assets

 

$

 

$

3,019

 

$

 

$

 

Commodity contracts

 

Derivative instruments (current liabilites)

 

 

 

 

13,912

 

Derivatives Not Designated as Hedges

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Other current assets

 

954

 

 

 

 

Commodity contracts

 

Derivative instruments (current liabilites)

 

 

 

38,493

 

 

 

 

 

 

$

954

 

$

3,019

 

$

38,493

 

$

13,912

 

 

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

 

 

 

June 30,

 

December 31,

 

(In thousands)

 

2014

 

2013

 

Derivative Assets

 

 

 

 

 

Gross amounts of recognized assets

 

$

13,312

 

$

13,792

 

Gross amounts offset in the statement of financial position

 

(12,358

)

(10,773

)

Net amounts of assets presented in the statement of financial position

 

954

 

3,019

 

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

 

 

373

 

Net amount

 

$

954

 

$

3,392

 

 

 

 

 

 

 

Derivative Liabilities

 

 

 

 

 

Gross amounts of recognized liabilities

 

$

50,851

 

$

24,685

 

Gross amounts offset in the statement of financial position

 

(12,358

)

(10,773

)

Net amounts of liabilities presented in the statement of financial position

 

38,493

 

13,912

 

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

 

490

 

 

Net amount

 

$

38,983

 

$

13,912

 

 

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Table of Contents

 

Effect of Derivative Instruments on Accumulated Other Comprehensive Income (Loss)

 

The amount of gain (loss) recognized in accumulated other comprehensive income (loss) on derivatives (effective portion) is as follows:

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

(In thousands)

 

2014

 

2013

 

2014

 

2013

 

Commodity contracts

 

$

 

$

115,113

 

$

(133,310

)

$

54,167

 

 

The amount of gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion) is as follows:

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

(In thousands)

 

2014 (1)

 

2013

 

2014 (1)

 

2013

 

Natural gas revenues

 

$

(22,320

)

$

(272

)

$

(92,877

)

$

13,056

 

Crude oil and condensate revenues

 

(636

)

2,094

 

(854

)

4,136

 

 

 

$

(22,956

)

$

1,822

 

$

(93,731

)

$

17,192

 

 


(1)    The Company ceased hedge accounting effective April 1, 2014. For the three and six months ended June 30, 2014, approximately $23.0 million related to amounts previously frozen in accumulated other comprehensive income (loss) were reclassified into income.

 

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

 

The amount of gain (loss) recognized in the Condensed Consolidated Statement of Operations on derivative instruments is as follows:

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

(In thousands)

 

2014

 

2013

 

2014

 

2013

 

Derivatives Designated as Hedges

 

 

 

 

 

 

 

 

 

Realized

 

 

 

 

 

 

 

 

 

Natural gas

 

$

 

$

(272

)

$

(70,557

)

$

13,056

 

Crude oil and condensate

 

 

2,094

 

(218

)

4,136

 

 

 

$

 

$

1,822

 

$

(70,775

)

$

17,192

 

Derivatives Not Designated as Hedges

 

 

 

 

 

 

 

 

 

Realized

 

 

 

 

 

 

 

 

 

Natural gas

 

$

(22,320

)

$

 

$

(22,320

)

$

 

Crude oil and condensate

 

(636

)

 

(636

)

 

Gain (loss) on derivative instruments

 

(15,262

)

 

(15,262

)

 

Unrealized

 

 

 

 

 

 

 

 

 

Gain (loss) on derivative instruments

 

12,933

 

 

12,933

 

 

 

 

$

(25,285

)

$

 

$

(25,285

)

$

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(25,285

)

$

1,822

 

$

(96,060

)

$

17,192

 

 

For the three and six months ended June 30, 2014 and 2013, respectively, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations related to derivative instruments designated as hedges.

 

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 obligations under the agreements. 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.

 

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Table of Contents

 

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

 

6. Fair Value Measurements

 

The Company follows the authoritative guidance for measuring fair value of assets and liabilities in its financial statements. 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). This 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 7 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 oil and gas properties and other 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, 2014 and 2013 and no other assets or liabilities were required to be recognized at fair value on a non-recurring basis, additional disclosures were 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 was classified as Level 3 in the fair value hierarchy.

 

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)

 

June 30,
2014

 

Assets

 

 

 

 

 

 

 

 

 

Deferred compensation plan

 

$

13,152

 

$

 

$

 

$

13,152

 

Derivative contracts

 

 

 

13,312

 

13,312

 

Total assets

 

$

13,152

 

$

 

$

13,312

 

$

26,464

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Deferred compensation plan

 

$

31,388

 

$

 

$

 

$

31,388

 

Derivative contracts

 

 

10,624

 

40,227

 

50,851

 

Total liabilities

 

$

31,388

 

$

10,624

 

$

40,227

 

$

82,239

 

 

(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,
2013

 

Assets

 

 

 

 

 

 

 

 

 

Deferred compensation plan

 

$

12,507

 

$

 

$

 

$

12,507

 

Derivative contracts

 

 

 

13,792

 

13,792

 

Total assets

 

$

12,507

 

$

 

$

13,792

 

$

26,299

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Deferred compensation plan

 

$

33,211

 

$

 

$

 

$

33,211

 

Derivative contracts

 

 

6,983

 

17,702

 

24,685

 

Total liabilities

 

$

33,211

 

$

6,983

 

$

17,702

 

$

57,896

 

 

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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. Estimates are verified using relevant NYMEX futures contracts and/or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions with 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 most significant unobservable inputs relative to the Company’s Level 3 derivative contracts are 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 net financial assets (liabilities) classified as Level 3 in the fair value hierarchy:

 

 

 

Six Months Ended

 

 

 

June 30,

 

(In thousands)

 

2014

 

2013

 

Balance at beginning of period

 

$

(3,910

)

$

41,159

 

Total gains (losses) (realized or unrealized):

 

 

 

 

 

Realized and unrealized gains (losses) included in earnings

 

(77,935

)

13,056

 

Included in other comprehensive income

 

(38,412

)

42,719

 

Settlements

 

93,342

 

(13,056

)

Transfers in and/or out of level 3

 

 

 

Balance at end of period

 

$

(26,915

)

$

83,878

 

 

 

 

 

 

 

Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period

 

$

15,407

 

$

 

 

There were no transfers between Level 1 and Level 2 measurements for the three and six months ended June 30, 2014 and 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 Company uses available market data and valuation methodologies to estimate the fair value of debt. 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 revolving 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 revolving 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.

 

The carrying amounts and fair values of long-term debt are as follows:

 

 

 

June 30, 2014

 

December 31, 2013

 

(In thousands)

 

Carrying
Amount

 

Estimated Fair
Value

 

Carrying
Amount

 

Estimated Fair
Value

 

Long-term debt

 

$

1,193,000

 

$

1,297,569

 

$

1,147,000

 

$

1,224,273

 

 

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Table of Contents

 

7. Asset Retirement Obligation

 

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

 

(In thousands)

 

Six Months Ended
June 30, 2014

 

Balance at beginning of period

 

$

75,853

 

Liabilities incurred

 

2,517

 

Liabilities settled

 

(36

)

Liabilities divested

 

(899

)

Accretion expense

 

2,024

 

Balance at end of period

 

$

79,459

 

 

As of both June 30, 2014 and December 31, 2013, approximately $2.0 million is included in accrued liabilities in the Condensed Consolidated Balance Sheet, which represents the current portion of the Company’s asset retirement obligation.

 

8. Commitments and Contingencies

 

Contractual Obligations

 

The Company has various contractual obligations in the normal course of its operations. Except for certain new and amended transportation agreements described below, there have been no material changes to the Company’s contractual obligations described under “Transportation and Gathering Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 9 in the Notes to Consolidated Financial Statements included in the Form 10-K.

 

Transportation and Gathering Agreements

 

During the first six months of 2014, the Company entered into or amended certain natural gas transportation agreements associated with the Company’s production in Pennsylvania. These agreements increased the Company’s future aggregate obligations under its transportation commitments by approximately $184.3 million over the next 10 years compared to those amounts disclosed in Note 9 in the Notes to Consolidated Financial Statements included in the Form 10-K.

 

Legal Matters

 

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

 

Contingency Reserves

 

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

 

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Table of Contents

 

9. 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)

 

2014

 

2013

 

2014

 

2013

 

Service cost

 

$

456

 

$

415

 

$

912

 

$

830

 

Interest cost

 

407

 

395

 

814

 

790

 

Amortization of net loss

 

 

205

 

 

410

 

 

 

$

863

 

$

1,015

 

$

1,726

 

$

2,030

 

 

The guidance for retirement benefits provides that the net actuarial loss is not amortized if it is less than 10% of the postretirement obligation. Accordingly, the Company does not expect to amortize its net actuarial loss from accumulated other comprehensive income (loss) during 2014.

 

10. Stock-based Compensation

 

General

 

Stock-based compensation expense during the first six months of 2014 and 2013 was $9.4 million and $28.7 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 2014 and 2013 was $6.3 million and $10.0 million, respectively.

 

During the first six months of 2014 and 2013, the Company realized a $20.4 million and $7.3 million tax benefit, respectively, related to the federal tax deduction in excess of book compensation cost for employee stock-based compensation. The Company is able to recognize this tax benefit only to the extent it reduces the Company’s income taxes payable.

 

Restricted Stock Awards

 

During the first six months of 2014, 46,000 restricted stock awards were granted to employees with a weighted-average grant date per share value of $34.96. 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 5.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

 

Restricted Stock Units

 

During the first six months of 2014, 34,071 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date per unit value of $38.97. 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 are issued when the director ceases to be a director of the Company.

 

Performance Share Awards

 

The performance period for the awards granted in 2014 commenced on January 1, 2014 and ends on December 31, 2016.  The Company used an annual forfeiture rate assumption ranging from 0% to 5% for purposes of recognizing stock-based compensation expense for its performance share awards. Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of performance share awards and the applicable award terms.

 

Performance Share Awards Based on Internal Performance Metrics

 

The fair value of performance award grants based on internal performance metrics is based on the average of the high and low stock price on the grant date and represents the right to receive up to 100% of the award in shares of common stock.

 

Employee Performance Share Awards. During the first six months of 2014, 241,130 Employee Performance Share Awards were granted at a grant date per share value of $39.43. The performance metrics are set by the Company’s Compensation Committee and are based on the Company’s average production, average finding costs and average reserve replacement over a three-year performance period. Based on the Company’s probability assessment at June 30, 2014, it is considered probable that the criteria for the performance awards based on performance conditions will be met.

 

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Table of Contents

 

Hybrid Performance Share Awards. During the first six months of 2014, 123,257 Hybrid Performance Share Awards were granted at a grant date per share value of $39.43, which is based on the average of the high and low stock price on the grant date. The 2014 awards vest 25% on each of the first and second anniversary dates and 50% on the third anniversary, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date, as set by the Company’s Compensation Committee. If the Company does not meet the performance metric for the applicable period, then the portion of the performance shares that would have been issued on that anniversary date will be forfeited. Based on the Company’s probability assessment at June 30, 2014, it is considered probable that the criteria for the performance awards based on performance conditions will be met.

 

Performance Share Awards Based on Market Conditions

 

These awards have both an equity and liability component, with the right to receive up to the first 100% of the award in shares of common stock and the right to receive up to an additional 100% of the value of the award in excess of the equity component in cash. The equity portion of these awards is valued on the grant date and is not marked to market, while the liability portion of the awards is valued as of the end of each reporting period on a mark-to-market basis. The Company calculates the fair value of the equity and liability portions of the awards using a Monte Carlo simulation model.

 

TSR Performance Share Awards.  During the first six months of 2014, 184,885 TSR Performance Share Awards were granted and are earned, or not earned, based on the comparative performance of the Company’s common stock measured against fourteen other companies in the Company’s peer group over a three-year performance period.

 

The following assumptions were used to determine the grant date fair value of the equity component (February 20, 2014) and the period-end fair value of the liability component of the TSR Performance Share Awards:

 

 

 

Grant Date

 

June 30, 2014

 

Fair value per performance share award

 

$

32.04

 

$5.94 - $21.77

 

Assumptions:

 

 

 

 

 

Stock price volatility

 

41.3%

 

29.7% - 102.7%

 

Risk free rate of return

 

0.7%

 

0.1% - 0.7%

 

Expected dividend yield

 

0.2%

 

0.2%

 

 

Supplemental Employee Incentive Plan

 

The Company recognized stock-based compensation expense of $1.6 million and $1.7 million for the three months ended June 30, 2014 and 2013, respectively, and $3.1 million and $5.1 million for the six months ended June 30, 2014 and 2013, respectively, related to the Supplemental Employee Incentive Plan (the Plan), which is included in general and administrative expense in the Condensed Consolidated Statement of Operations. Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for additional information on the provisions of the Plan.

 

The following assumptions were used determine the period-end fair value of the Supplemental Employee Incentive Plan IV liability using a Monte Carlo model:

 

 

 

June 30,

 

 

 

2014

 

Stock price volatility

 

36.0%

 

Risk free rate of return

 

1.0%

 

Annual salary increase rate

 

4.0%

 

Annual turnover rate

 

4.6%

 

 

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Table of Contents

 

11. Earnings per Common Share

 

Basic EPS is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly calculated except that the common shares outstanding for the period 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

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

(In thousands)

 

2014

 

2013

 

2014

 

2013

 

Weighted-average shares - basic

 

417,291

 

420,698

 

417,097

 

420,500

 

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

 

1,801

 

2,792

 

1,645

 

2,484

 

Weighted-average shares - diluted

 

419,092

 

423,490

 

418,742

 

422,984

 

 

 

 

 

 

 

 

 

 

 

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

 

2

 

2

 

409

 

574

 

 

12. Accumulated Other Comprehensive Income (Loss)

 

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

 

(In thousands)

 

Net Gain
(Loss) on
Cash Flow
Hedges

 

Postretirement
Benefits

 

Total

 

Balance at December 31, 2013

 

$

(6,551

)

$

(1,810

)

$

(8,361

)

Other comprehensive income before reclassifications

 

(80,175

)

 

(80,175

)

Amounts reclassified from accumulated other comprehensive income

 

56,372

 

 

56,372

 

Net current-period other comprehensive income

 

(23,803

)

 

(23,803

)

Balance at June 30, 2014

 

$

(30,354

)

$

(1,810

)

$

(32,164

)

 

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

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

Affected Line Item in the Condensed

 

(In thousands)

 

2014

 

2013

 

2014

 

2013

 

Consolidated Statement of Operations

 

Net gain (loss) on cash flow hedges

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

(22,320

)

$

(272

)

$

(92,877

)

$

13,056

 

Natural gas revenues

 

Commodity contracts

 

(636

)

2,094

 

(854

)

4,136

 

Crude oil and condensate revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

Postretirement benefits

 

 

 

 

 

 

 

 

 

 

 

Amortization of net loss

 

 

(205

)

 

(410

)

General and administrative expense

 

 

 

(22,956

)

1,617

 

(93,731

)

16,782

 

Total before tax

 

 

 

9,149

 

(636

)

37,359

 

(6,601

)

Tax benefit (expense)

 

Total reclassifications for the period

 

$

(13,807

)

$

981

 

$

(56,372

)

$

10,181

 

Net of tax

 

 

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Table of Contents

 

13. ADDITIONAL BALANCE SHEET INFORMATION

 

Certain balance sheet amounts are comprised of the following:

 

 

 

June 30,

 

December 31,

 

(In thousands)

 

2014

 

2013

 

 

 

 

 

 

 

Accounts receivable, net

 

 

 

 

 

Trade accounts

 

$

211,559

 

$

215,361

 

Joint interest billing

 

1,886

 

7,261

 

Income taxes receivable

 

 

922

 

Other accounts

 

208

 

746

 

 

 

213,653

 

224,290

 

Allowance for doubtful accounts

 

(1,553

)

(1,814

)

 

 

$

212,100

 

$

222,476

 

Inventories

 

 

 

 

 

Natural gas in storage

 

$

2,810

 

$

9,056

 

Tubular goods and well equipment

 

8,889

 

8,396

 

Other accounts

 

215

 

16

 

 

 

$

11,914

 

$

17,468

 

Other current assets

 

 

 

 

 

Prepaid balances and other

 

2,571

 

2,587

 

Derivative instruments

 

954

 

3,019

 

 

 

$

3,525

 

$

5,606

 

Other assets

 

 

 

 

 

Deferred compensation plan

 

$

13,152

 

$

12,507

 

Debt issuance cost

 

14,225

 

16,476

 

Other accounts

 

71

 

79

 

 

 

$

27,448

 

$

29,062

 

Accounts payable

 

 

 

 

 

Trade accounts

 

$

43,789

 

$

26,023

 

Natural gas purchases

 

3,424

 

2,052

 

Royalty and other owners

 

79,274

 

79,150

 

Accrued capital costs

 

114,283

 

146,899

 

Taxes other than income

 

9,586

 

13,677

 

Drilling advances

 

107

 

14,093

 

Producer gas imbalances

 

69

 

69

 

Other accounts

 

5,149

 

6,838

 

 

 

$

255,681

 

$

288,801

 

Accrued liabilities

 

 

 

 

 

Employee benefits

 

$

26,699

 

$

43,599

 

Taxes other than income

 

10,013

 

6,894

 

Interest payable

 

20,049

 

20,211

 

Other accounts

 

2,973

 

2,897

 

 

 

$

59,734

 

$

73,601

 

Other liabilities

 

 

 

 

 

Deferred compensation plan

 

$

31,388

 

$

33,211

 

Other accounts

 

6,451

 

13,043

 

 

 

$

37,839

 

$

46,254

 

 

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14. CAPITAL STOCK

 

Incentive Plans

 

On May 1, 2014, the Company’s shareholders approved the 2014 Incentive Plan, which replaced the 2004 Incentive Plan that expired on April 29, 2014. Under the 2014 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2014 Incentive Plan consisting of stock options or stock awards. A total of 18 million shares of common stock may be issued under the 2014 Incentive Plan. Under the 2014 Incentive Plan, no more than 10 million shares may be issued pursuant to incentive stock options. No additional awards may be granted under the 2014 Incentive Plan on or after May 1, 2024.

 

No additional awards will be granted under any of the Company’s prior plans, including the 2004 Incentive Plan.  Awards outstanding under the 2004 Incentive Plan will remain outstanding in accordance with their original terms and conditions.

 

Increase in Authorized Shares

 

In May 2014, the Company’s shareholders approved an increase in the authorized number of shares of common stock from 480 million to 960 million shares.

 

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Report of Independent Registered Public Accounting Firm

 

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

 

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of June 30, 2014, and the related condensed consolidated statements of operations and of comprehensive income for the three and six month periods ended June 30, 2014 and 2013 and the condensed consolidated statement of cash flows for the six month periods ended June 30, 2014 and 2013. 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, 2013, 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, 2014, 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, 2013, 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 25, 2014

 

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

 

The following review of operations for the three and six month periods ended June 30, 2014 and 2013 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, 2013 (Form 10-K).

 

Overview

 

On an equivalent basis, our production for the six months ended June 30, 2014 increased by 34% compared to the six months ended June 30, 2013. For the six months ended June 30, 2014, we produced 247.5 Bcfe, or 1,367.3 Mmcfe per day, compared to 184.5 Bcfe, or 1,019.6 Mmcfe per day, for the six months ended June 30, 2013. Natural gas production increased by 61.8 Bcf, or 35%, to 237.6 Bcf for the first six months of 2014 compared to 175.8 Bcf for the first six months of 2013. This increase was primarily the result of higher production in the Marcellus Shale associated with our drilling program. Partially offsetting the production increase in the Marcellus Shale were decreases in production in west Texas and Oklahoma due to certain non-core asset dispositions in the fourth quarter of 2013 and normal production declines in Texas and West Virginia. Crude oil/condensate/NGL production increased by 193 Mbbls, or 13%, to 1,647 Mbbls in the first six months of 2014 from 1,454 Mbbls in the first six months of 2013. This increase was due to higher production resulting from our oil-focused drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013.

 

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 six months of 2014 was $3.60 per Mcf, 5% lower than the $3.77 per Mcf price realized in the first six months of 2013. Our average realized crude oil price for the first six months of 2014 was $98.39 per Bbl, 4% lower than the $102.65 per Bbl price realized in the first six months of 2013. 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, crude oil and NGL 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 natural gas and crude oil reserves at economical costs are critical to our long-term success.

 

Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments are accounted for on a mark-to-market basis with changes in fair value recognized currently in operating revenues in the Condensed Consolidated Statement of Operations. As a result of these mark-to-market adjustments, we will likely experience volatility in our earnings from time to time due to commodity price volatility. Refer to “Impact of Derivative Instruments on Operating Revenues” below and Note 5 to the Condensed Consolidated Financial Statements for more information.

 

During the first six months of 2014, we drilled 76 gross wells (62.0 net) with a success rate of 100% compared to 83 gross wells (69.7 net) with a success rate of 96% for the comparable period of the prior year. Our total capital and exploration expenditures were $594.0 million for the six months ended June 30, 2014 compared to $554.1 million for the six months ended June 30, 2013. The increase in capital spending was the result of our Marcellus Shale horizontal drilling program in northeast Pennsylvania and our drilling program in the Eagle Ford Shale in south Texas. We allocate our planned program for capital and exploration expenditures among our various operating areas based on return expectations, availability of services and human resources. Our 2014 drilling program includes $1.375 billion to $1.475 billion in capital and exploration expenditures and is expected to be funded by operating cash flow, existing cash and, if required, borrowings under our revolving 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 six months ended June 30, 2014 were from funds generated from the sale of natural gas and crude oil production and net borrowings under our revolving 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.

 

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

 

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

 

 

 

Six Months Ended

 

 

 

June 30,

 

(In thousands)

 

2014

 

2013

 

Cash flows provided by operating activities

 

$

584,948

 

$

489,967

 

Cash flows used in investing activities

 

(612,504

)

(527,400

)

Cash flows provided by financing activities

 

49,766

 

53,974

 

Net increase in cash and cash equivalents

 

$

22,210

 

$

16,541

 

 

Operating Activities.  Net cash provided by operating activities in the first six months of 2014 increased by $95.0 million over the first six months of 2013. This increase was primarily due to higher operating revenues partially offset by higher operating expenses (excluding non-cash expenses) and a decrease in working capital and other assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production, partially offset by the decrease in realized natural gas and crude oil prices. Equivalent production volumes increased by 34% for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 primarily as a result of higher natural gas production. Average realized natural gas prices decreased by 5% and average realized crude oil prices decreased by 4% for the first six months of 2014 compared to the first six months of 2013.

 

See “Results of Operations” for additional information relative to commodity price, production and operating expense fluctuations. 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 $85.1 million for the first six months of 2014 compared to the first six months of 2013. The increase was due to $93.6 million of higher capital expenditures and an increase of $18.0 million in capital contributions associated with our equity method investments. Partially offsetting the increases was a $28.1 million decrease in restricted cash related to the release of funds by our qualified intermediary due to a lapse in the statutory holding period and funding of oil and gas lease acquisitions during the first six months of 2014 associated with like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.

 

Financing Activities. Cash flows provided by financing activities decreased by $4.2 million for the first six months of 2014 compared to the first six months of 2013. This decrease was primarily due to $9.0 million of lower net borrowings and an $8.3 million increase in dividend payments, partially offset by an increase of $13.0 million in tax benefits associated with our stock-based compensation.

 

Effective April 15, 2014, the lenders under our revolving credit facility approved an increase in our borrowing base from $2.3 billion to $3.1 billion as part of the annual redetermination under the terms of the revolving credit facility agreement. The commitments under the revolving credit facility remain unchanged at $1.4 billion. At June 30, 2014, we had $506.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 1.9% and $893.0 million available for future borrowings. See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further details.

 

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, existing cash on hand and availability under our revolving credit facility, we have the capacity to finance our spending plans and maintain our strong financial position.

 

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Capitalization

 

Information about our capitalization is as follows:

 

 

 

June 30,

 

December 31,

 

(Dollars in thousands)

 

2014

 

2013

 

Debt (1)

 

$

1,193,000

 

$

1,147,000

 

Stockholders’ equity

 

2,401,939

 

2,204,602

 

Total capitalization

 

$

3,594,939

 

$

3,351,602

 

 

 

 

 

 

 

Debt to capitalization

 

33%

 

34%

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

45,610

 

$

23,400

 

 


(1)         Includes $506.0 million and $460.0 million of borrowings outstanding under our revolving credit facility at June 30, 2014 and December 31, 2013, respectively.

 

During the six months ended June 30, 2014, we paid dividends of $16.7 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 expenditures, excluding any significant property acquisitions, with cash generated from operations and, when necessary, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year.

 

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

 

 

 

Six Months Ended

 

 

 

June 30,

 

(In thousands)

 

2014

 

2013

 

Capital expenditures

 

 

 

 

 

Drilling and facilities

 

$

547,980

 

$

501,331

 

Leasehold acquisitions

 

26,584

 

39,047

 

Pipeline and gathering

 

227

 

263

 

Other

 

8,043

 

4,879

 

 

 

582,834

 

545,520

 

Exploration expense

 

11,150

 

8,553

 

Total

 

$

593,984

 

$

554,073

 

 

For the full year of 2014, we plan to drill approximately 155 to 175 gross wells (150 to 170 net). In 2014, we plan to spend between $1.375 billion and $1.475 billion in total capital and exploration expenditures (excluding expected contributions to our equity method investments of approximately $38.9 million). See “Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

 

Contractual Obligations

 

We have various contractual obligations in the normal course of our operations. Except for certain new and amended transportation agreements described in Note 8 to the Condensed Consolidated Financial Statements included in this Form 10-Q, there have been no material changes to our contractual obligations described under “Transportation and Gathering Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 9 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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Table of Contents

 

Critical Accounting Policies and Estimates

 

Our discussion and analysis of our financial condition and results of operations are based upon our Condensed Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted 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

 

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. We do not expect the adoption of this guidance to have a material impact on our financial position or results of operations.

 

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective beginning in fiscal year 2017 and can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations or cash flows.

 

Accounting for Derivative Instruments and Hedging Activities

 

Effective April 1, 2014, we elected to discontinue hedge accounting for our commodity derivatives on a prospective basis. Through March 31, 2014, we elected to designate our commodity derivatives as cash flow hedges for accounting purposes. Accordingly, the change in the fair value of derivatives designated as hedges that were effective was recorded to accumulated other comprehensive income (loss) in stockholders’ equity in the Condensed Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges and the change in fair value and realized cash settlements of derivatives not designated as hedges are recorded as a component of operating revenues in gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

 

Results of Operations

 

Second Quarters of 2014 and 2013 Compared

 

We reported net income in the second quarter of 2014 of $118.4 million, or $0.28 per share, compared to $89.1 million, or $0.21 per share, in the second quarter of 2013. The increase in net income was due to an increase in operating revenues, partially offset by higher operating expenses and income taxes.

 

Revenue, Price and Volume Variances

 

Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.

 

 

 

Three Months Ended June 30,

 

Variance

 

Revenue Variances (In thousands)

 

2014

 

2013

 

Amount

 

Percent

 

Natural gas

 

$

437,761

 

$

368,391

 

$

69,370

 

19%

 

Crude oil and condensate

 

86,341

 

70,226

 

16,115

 

23%

 

Gain (loss) on derivative instruments

 

(2,329

)

 

(2,329

)

(100%

)

Brokered natural gas

 

8,140

 

8,244

 

(104

)

(1%

)

Other

 

3,274

 

2,819

 

455

 

16%

 

 

 

$

533,187

 

$

449,680

 

$

83,507

 

19%

 

 

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Three Months Ended June 30,

 

Variance

 

Increase
(Decrease)

 

 

 

2014

 

2013

 

Amount

 

Percent

 

(In thousands)

 

Price Variances 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (1)

 

$

3.59

 

$

4.06

 

$

(0.47

)

(12%

)

$

(57,463

)

Crude oil and condensate (2)

 

$

99.36

 

$

101.39

 

$

(2.03

)

(2%

)

(1,770

)

Total

 

 

 

 

 

 

 

 

 

$

(59,233

)

Volume Variances

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

121.8

 

90.7

 

31.1

 

34%

 

$

126,833

 

Crude oil and condensate (Mbbl)

 

869

 

693

 

176

 

25%

 

17,885

 

Total

 

 

 

 

 

 

 

 

 

$

144,718

 

 


(1)        These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.18 per Mcf in 2014. There was no impact on the realized price from derivative instrument settlements in 2013.

(2)        These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.73 per Bbl in 2014 and increased the price by $3.02 per Bbl in 2013.

 

Natural Gas Revenues

 

The increase in natural gas revenues of $69.4 million is due to higher production, partially offset by lower realized natural gas prices. The increase in production was a result of our Marcellus Shale drilling program, partially offset by a decrease in production in Oklahoma and west Texas as a result of certain non-core asset dispositions in the fourth quarter of 2013 and lower production in Texas and West Virginia due to normal production declines.

 

Crude Oil and Condensate Revenues

 

The increase in crude oil and condensate revenues of $16.1 million is due to higher production associated with our oil-focused drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013 and lower realized crude oil prices.

 

Gain (Loss) on Derivative Instruments

 

Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments were accounted for on a mark-to-market basis with changes in fair value recognized currently in operating revenues in the Condensed Consolidated Statement of Operations. Gain (loss) on derivative instruments includes a $15.3 million loss related to the change in fair value of realized cash settlements of derivative instruments previously frozen in accumulated other comprehensive income (loss) and a $12.9 million unrealized mark-to-market gain on our commodity derivative instruments.

 

Impact of Derivative Instruments on Operating Revenues

 

The following table reflects the realized and unrealized impact of our derivative instruments:

 

 

 

Three Months Ended
June 30,

 

(In thousands)

 

2014

 

2013

 

Realized

 

 

 

 

 

Natural gas

 

$

(22,320

)

$

(272

)

Crude oil and condensate

 

(636

)

2,094

 

Gain (loss) on derivative instruments

 

(15,262

)

 

 

 

$

(38,218

)

$

1,822

 

Unrealized

 

 

 

 

 

Gain (loss) on derivative instruments

 

12,933

 

 

 

 

$

(25,285

)

$

1,822

 

 

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Brokered Natural Gas Revenue and Cost

 

 

 

Three Months Ended
June 30,

 

Variance

 

Price and
Volume
Variances

 

 

 

2014

 

2013

 

Amount

 

Percent

 

(In thousands)

 

Brokered Natural Gas Sales

 

 

 

 

 

 

 

 

 

 

 

Sales price ($/Mcf)

 

$

4.96

 

$

4.81

 

$

0.15

 

3%

 

$

242

 

Volume brokered (Mmcf)

 

x

1,642

 

x

1,714

 

(72

)

(4%

)

(346

)

Brokered natural gas (In thousands)

 

$

8,140

 

$

8,244

 

 

 

 

 

$

(104

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Purchases

 

 

 

 

 

 

 

 

 

 

 

Purchase price ($/Mcf)

 

$

4.28

 

$

3.91

 

$

0.37

 

9%

 

$

(609

)

Volume brokered (Mmcf)

 

x

1,642

 

x

1,714

 

(72

)

(4%

)

282

 

Brokered natural gas (In thousands)

 

$

7,031

 

$

6,704

 

 

 

 

 

$

(327

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered natural gas margin (In thousands)

 

$

1,109

 

$

1,540

 

 

 

 

 

$

(431

)

 

The $0.4 million decrease in brokered natural gas margin is a result of an increase in purchase price that outpaced the increase in sales price and lower brokered volumes.

 

Operating and Other Expenses

 

 

 

Three Months Ended June 30,

 

Variance

 

(In thousands)

 

2014

 

2013

 

Amount

 

Percent

 

Operating and Other Expenses

 

 

 

 

 

 

 

 

 

Direct operations

 

$

35,605

 

$

36,978

 

$

(1,373

)

(4%

)

Transportation and gathering

 

83,976

 

52,648

 

31,328

 

60%

 

Brokered natural gas

 

7,031

 

6,704

 

327

 

5%

 

Taxes other than income

 

12,816

 

11,364

 

1,452

 

13%

 

Exploration

 

4,676

 

4,529

 

147

 

3%

 

Depreciation, depletion and amortization

 

157,563

 

151,389

 

6,174

 

4%

 

General and administrative

 

20,127

 

21,608

 

(1,481

)

(7%

)

Total operating expense

 

$

321,794

 

$

285,220

 

$

36,574

 

13%

 

 

 

 

 

 

 

 

 

 

 

(Earnings) loss on equity method investments

 

$

(756

)

$

(290

)

$

466

 

161%

 

(Gain) loss on sale of assets

 

1,496

 

(276

)

(1,772

)

(642%

)

Interest expense

 

16,334

 

16,991

 

(657

)

(4%

)

Income tax expense

 

75,899

 

58,921

 

16,978

 

29%

 

 

Total costs and expenses from operations increased by $36.6 million, or 13%, in the second quarter of 2014 compared to the same period of 2013. The primary reasons for this fluctuation are as follows:

 

·                  Direct operations decreased $1.4 million largely due to lower costs associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013.  Partially offsetting these decreases were higher operating costs as a result of higher production and an increase in costs associated with oil processing and related fuel charges as a result of more stringent oil pipeline quality requirements in south Texas.

 

·                  Transportation and gathering increased $31.3 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements in late 2013 and during the first half of 2014.

 

·                  Brokered natural gas increased $0.3 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

·                  Taxes other than income increased $1.5 million due to $1.2 million higher production taxes and $0.6 million higher drilling impact fees associated with our Marcellus Shale drilling activities. Production taxes increased due to higher oil

 

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production in south Texas, partially offset by lower taxes associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013.

 

·                  Depreciation, depletion and amortization increased $6.2 million, of which $48.6 million was due to higher equivalent production volumes, offset by $38.5 million due to a lower DD&A rate of $1.20 per Mcfe for the second quarter of 2014 compared to $1.50 per Mcfe for the second quarter of 2013. The lower DD&A rate was primarily due to lower costs of reserve additions associated with our Marcellus drilling program and the impact of the disposition of higher rate fields in Oklahoma and west Texas in the fourth quarter of 2013. In addition, amortization of unproved properties decreased $4.0 million in the second quarter of 2014 due to a decrease in amortization rates as a result of favorable results from our drilling program in Pennsylvania.

 

·                  General and administrative decreased $1.5 million due to lower stock-based compensation expense of $3.7 million associated with the mark-to-market of our liability-based performance awards due to changes in our stock price during 2014 compared to 2013, partially offset by increases in professional fees and other expenses.

 

Gain (Loss) on Sale of Assets

 

An aggregate loss of $1.5 million was recognized in the second quarter of 2014, primarily due to certain post-closing adjustments related to the sale of certain of our proved oil and gas properties in Oklahoma and the sale of heavy-duty equipment. There were no significant gains or losses on sale of assets recognized in the second quarter of 2013.

 

Interest Expense

 

Interest expense decreased $0.7 million primarily due to the repayment of $75.0 million of our 7.33% weighted-average fixed rate notes in July 2013 and a slightly lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.1% during the second quarter of 2014 compared to approximately 2.2% during the second quarter of 2013. These decreases are partially offset by an increase in weighted-average borrowings under our revolving credit facility based on daily balances of approximately $574.2 million during the second quarter of 2014 compared to approximately $405.7 million during the second quarter of 2013.

 

Income Tax Expense

 

Income tax expense increased $17.0 million due to higher pretax income, partially offset by a lower effective tax rate. The effective tax rate for the second quarter of 2014 and 2013 was 39.1% and 39.8%, respectively.

 

First Six Months of 2014 and 2013 Compared

 

We reported net income in the first six months of 2014 of $225.5 million, or $0.54 per share, compared to $131.9 million, or $0.32 per share, in the first six months of 2013. The increase in net income was due to an increase in operating revenues, partially offset by higher operating expenses and income taxes.

 

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)

 

2014

 

2013

 

Amount

 

Percent

 

Natural gas

 

$

870,571

 

$

662,184

 

$

208,387

 

31%

 

Crude oil and condensate

 

145,485

 

135,881

 

9,604

 

7%

 

Gain (loss) on derivative instruments

 

(2,329

)

 

(2,329

)

(100%

)

Brokered natural gas

 

21,293

 

19,137

 

2,156

 

11%

 

Other

 

7,970

 

5,763

 

2,207

 

38%

 

 

 

$

1,042,990

 

$

822,965

 

$

220,025

 

27%

 

 

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Six Months Ended June 30,

 

Variance

 

Increase
(Decrease)

 

 

 

2014

 

2013

 

Amount

 

Percent

 

(In thousands)

 

Price Variances

 

 

 

 

 

 

 

 

 

 

 

Natural gas (1)

 

$

3.66

 

$

3.77

 

$

(0.11

)

(3%

)

$

(26,136

)

Crude oil and condensate (2)

 

$

98.70

 

$

102.65

 

$

(3.95

)

(4%

)

(5,819

)

Total

 

 

 

 

 

 

 

 

 

$

(31,955

)

Volume Variances

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

237.6

 

175.8

 

61.8

 

35%

 

$

234,523

 

Crude oil and condensate (Mbbl)

 

1,474

 

1,324

 

150

 

11%

 

15,423

 

Total

 

 

 

 

 

 

 

 

 

$

249,946

 

 


(1)        These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.39 per Mcf in 2014 and increased the price by $0.07 per Mcf in 2013.

(2)        These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.58 per Bbl in 2014 and increased the price by $3.12 per Bbl in 2013.

 

Natural Gas Revenues

 

The increase in natural gas revenues of $208.4 million is due to higher production, partially offset by lower realized natural gas prices. The increase in production was a result of our Marcellus Shale drilling program, partially offset by a decrease in production in Oklahoma and west Texas as a result of certain non-core asset dispositions in the fourth quarter of 2013 and lower production in Texas and West Virginia due to normal production declines.

 

Crude Oil and Condensate Revenues

 

The increase in crude oil and condensate revenues of $9.6 million is due to higher production associated with our oil-focused drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013 and lower realized crude oil prices.

 

Gain (Loss) on Derivative Instruments

 

Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments were accounted for on a mark-to-market basis with changes in fair value recognized currently in operating revenues in the Condensed Consolidated Statement of Operations. Gain (loss) on derivative instruments includes a $15.3 million loss related to the change in fair value of realized cash settlements of derivative instruments previously frozen in accumulated other comprehensive income (loss) and a $12.9 million unrealized mark-to-market gain on our commodity derivative instruments.

 

Impact of Derivative Instruments on Operating Revenues

 

The following table reflects the realized and unrealized impact of our derivative instruments:

 

 

 

Six Months Ended
June 30,

 

(In thousands)

 

2014

 

2013

 

Realized

 

 

 

 

 

Natural gas

 

$

(92,877

)

$

13,056

 

Crude oil and condensate

 

(854

)

4,136

 

Gain (loss) on derivative instruments

 

(15,262

)

 

 

 

$

(108,993

)

$

17,192

 

Unrealized

 

 

 

 

 

Gain (loss) on derivative instruments

 

12,933

 

 

 

 

$

(96,060

)

$

17,192

 

 

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Brokered Natural Gas Revenue and Cost

 

 

 

 

 

 

 

 

 

 

 

Price and

 

 

 

Six Months Ended
June 30,

 

Variance

 

Volume
Variances

 

 

 

2014

 

2013

 

Amount

 

Percent

 

(In thousands)

 

Brokered Natural Gas Sales

 

 

 

 

 

 

 

 

 

 

 

Sales price ($/Mcf)

 

$

4.92

 

$

4.00

 

$

0.92

 

23%

 

$

3,968

 

Volume brokered (Mmcf)

 

x

4,328

 

x

4,781

 

(453

)

(9%

)

(1,812

)

Brokered natural gas (In thousands)

 

$

21,293

 

$

19,137

 

 

 

 

 

$

2,156

 

 

 

 

 

 

 

 

 

 

 

 

 

Brokered Natural Gas Purchases

 

 

 

 

 

 

 

 

 

 

 

Purchase price ($/Mcf)

 

$

4.36

 

$

3.16

 

$

1.20

 

38%

 

$

(5,228

)

Volume brokered (Mmcf)

 

x

4,328

 

x

4,781

 

(453

)

(9%

)

1,430

 

Brokered natural gas (In thousands)

 

$

18,891

 

$

15,093

 

 

 

 

 

$

(3,798

)

 

 

 

 

 

 

 

 

 

 

 

 

Brokered natural gas margin (In thousands)

 

$

2,402

 

$

4,044

 

 

 

 

 

$

(1,642

)

 

The $1.6 million decrease in brokered natural gas margin is a result of an increase in purchase price that outpaced the increase in sales price and lower brokered volumes.

 

Operating and Other Expenses

 

 

 

Six Months Ended June 30,

 

Variance

 

(In thousands)

 

2014

 

2013

 

Amount

 

Percent

 

Operating and Other Expenses

 

 

 

 

 

 

 

 

 

Direct operations

 

$

71,439

 

$

68,475

 

$

2,964

 

4%

 

Transportation and gathering

 

161,741

 

98,869

 

62,872

 

64%

 

Brokered natural gas

 

18,891

 

15,093

 

3,798

 

25%

 

Taxes other than income

 

25,860

 

23,051

 

2,809

 

12%

 

Exploration

 

11,150

 

8,553

 

2,597

 

30%

 

Depreciation, depletion and amortization

 

304,981

 

300,042

 

4,939

 

2%

 

General and administrative

 

41,763

 

57,312

 

(15,549

)

(27%

)

Total operating expense

 

$

635,825

 

$

571,395

 

$

64,430

 

11%

 

 

 

 

 

 

 

 

 

 

 

(Earnings) loss on equity method investments

 

$

(756

)

$

(336

)

$

420

 

125%

 

(Gain) loss on sale of assets

 

2,781

 

(180

)

(2,961

)

(1,645%

)

Interest expense

 

32,891

 

33,292

 

(401

)

(1%

)

Income tax expense

 

146,798

 

86,856

 

59,942

 

69%

 

 

Total costs and expenses from operations increased by $64.4 million, or 11%, in the first six months of 2014 compared to the same period of 2013. The primary reasons for this fluctuation are as follows:

 

·                  Direct operations increased $3.0 million largely due to higher operating costs as a result of higher production and an increase in costs associated with oil processing and related fuel charges as a result of more stringent oil pipeline quality requirements in south Texas. Partially offsetting these increases were lower costs associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013.

 

·                  Transportation and gathering increased $62.9 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements in late 2013 and during the first half of 2014.

 

·                  Brokered natural gas increased $3.8 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

·                  Taxes other than income increased $2.8 million due to $2.6 million higher drilling impact fees associated with our Marcellus Shale drilling activities and $1.6 million higher production taxes. Production taxes increased due to higher oil

 

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production in south Texas, offset by lower taxes associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013. These increases are partially offset by a $1.2 million decrease in ad valorem taxes.

 

·                  Exploration expense increased $2.6 million as a result of higher exploratory dry hole costs of $1.4 million and higher geophysical and geological and other expenses.

 

·                  Depreciation, depletion and amortization increased $4.9 million, of which $96.3 million was due to higher equivalent production volumes, offset by $86.2 million due to a lower DD&A rate of $1.18 per Mcfe for the first six months of 2014 compared to $1.53 per Mcfe for the first six months of 2013. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our Marcellus drilling program and the impact of the disposition of higher rate fields in Oklahoma and west Texas in the fourth quarter of 2013. In addition, amortization of unproved properties decreased $5.5 million in the first six months in 2014 due to a decrease in amortization rates as a result of favorable results from our drilling program in Pennsylvania.

 

·                  General and administrative decreased $15.5 million due to lower stock-based compensation expense of $19.3 million 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 during 2014 compared to 2013 and lower professional fees. There were no material increases in general and administrative costs during the period.

 

Gain (Loss) on Sale of Assets

 

An aggregate loss of $2.8 million was recognized in the first six months of 2014, primarily due to certain post-closing adjustments related to the sale of our proved oil and gas properties in Oklahoma and the sale of heavy-duty equipment. There were no significant gains or losses on sale of assets recognized in the first six months of 2013.

 

Interest Expense

 

Interest expense decreased $0.4 million primarily due to the repayment of $75.0 million of our 7.33% weighted-average fixed rate notes in July 2013 and a slightly lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.2% during the first six months of 2014 compared to approximately 2.3% during the first six months of 2013. These decreases are partially offset by an increase in weighted-average borrowings under our revolving credit facility based on daily balances of approximately $565.2 million during the first six months of 2014 compared to approximately $383.8 million during the first six months of 2013.

 

Income Tax Expense

 

Income tax expense increased $59.9 million due to higher pretax income, partially offset by a slightly lower effective tax rate. The effective tax rate for the first six months of 2014 and 2013 was 39.4% and 39.7%, respectively.

 

Forward-Looking Information

 

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging and risk management 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.

 

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ITEM 3.                        Quantitative and Qualitative Disclosures about Market Risk

 

Market Risk

 

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

 

Derivative Instruments and Risk Management Activities

 

Our risk management strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets through the use of commodity derivatives. A committee that consists of members of senior management oversees our risk management activities. Our commodity derivatives generally cover a portion of our production and only provides partial price protection by limiting the benefit to us of increases in prices, while protecting us in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of our commodity derivatives. Please read the discussion below as well as Note 6 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our derivative and risk management activities.

 

Periodically, we enter into commodity derivatives, including collar and swap agreements, to protect against exposure to price declines related to our natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity derivatives 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.

 

As of June 30, 2014, we had the following outstanding commodity derivatives:

 

 

 

 

 

 

 

 

 

Collars

 

Swaps

 

Estimated Fair

 

 

 

 

 

 

 

 

 

Floor

 

Ceiling

 

 

 

Value Asset

 

Type of Contract

 

Volume

 

Contract Period

 

Range

 

Weighted-
Average

 

Range

 

Weighted-
Average

 

Weighted-
Average

 

(Liability)
(In thousands)

 

Natural gas

 

169.8

 

Bcf

 

Jul. 2014 - Dec. 2014

 

$3.60-$4.37

 

$

4.13

 

$4.22-$4.80

 

$

4.51

 

 

 

$

(34,607

)

Natural gas

 

53.6

 

Bcf

 

Jul. 2014 - Dec. 2014

 

 

 

 

 

 

 

 

 

$

4.05

 

(791

)

Crude oil

 

368.0

 

Mbbl

 

Jul. 2014 - Dec. 2014

 

 

 

 

 

 

 

 

 

$

97.00

 

(2,271

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(37,669

)

 

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

 

The amounts set forth under the estimated fair value asset (liability) column in the table above represent our total unrealized derivative position at June 30, 2014 and exclude the impact of non-performance risk. Non-performance risk is 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.

 

During the first six months of 2014, natural gas collars with floor prices ranging from $3.60 to $4.37 per Mcf and ceiling prices ranging from $4.22 to $4.80 per Mcf covered 167.0 Bcf, or 70%, of natural gas production at an average price of $4.38 per Mcf. Natural gas swaps covered 46.7 Mcf, or 20% of natural gas production at an average price of $4.08 per Mcf. Crude oil swaps covered 244 Mbbl, or 17% of crude oil production at an average price of $97.00 per Bbl.

 

We are exposed to market risk on commodity 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 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 primary derivative contract counterparties are Bank of America, Bank of Montreal, Goldman Sachs, ING Capital Markets, JPMorgan, 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 commodity prices. See “Forward-Looking Information” for further details.

 

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Table of Contents

 

Fair Market Value of Other Financial Instruments

 

The estimated fair value of other 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 revolving 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 the revolving 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:

 

 

 

June 30, 2014

 

December 31, 2013

 

(In thousands)

 

Carrying
Amount

 

Estimated Fair
Value

 

Carrying
Amount

 

Estimated Fair
Value

 

Long-term debt

 

$

1,193,000

 

$

1,297,569

 

$

1,147,000

 

$

1,224,273

 

 

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 second quarter of 2014 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 8 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

 

From time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions individually or in the aggregate in excess of $100,000.

 

ITEM 1A.                 Risk Factors

 

For additional information about the risk factors that affect us, see Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2013.

 

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

 

Issuer Purchases of Equity Securities

 

Our Board of Directors has authorized a share repurchase program under which we 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, 2014, we did not repurchase any shares of our common stock. All purchases executed to date have been through open

 

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Table of Contents

 

market transactions. The maximum number of remaining shares that may be purchased under the plan as of June 30, 2014 was 14,371,834.

 

ITEM 6.                                                Exhibits

 

Exhibit
Number

 

Description

 

 

 

3.1

 

Restated Certificate of Incorporation (incorporated by reference in the Current Report on Form 8-K of the Company filed January 21, 2010).

 

 

 

3.2

 

Certificate of Amendment to Restated Certificate of Incorporation (incorporated by reference to the Quarterly Report on Form 10-Q of the Company for the quarter ended June 30, 2012).

 

 

 

3.3

 

Certificate of Amendment of Restated Certificate of Incorporation, dated as of May 1, 2014.

 

 

 

10.1

 

2014 Incentive Plan.

 

 

 

10.2

 

Form of Award Agreements under the 2014 Incentive Plan.

 

 

 

 

 

(a) 2014 Form of Non-Employee Director Restricted Stock Unit Award Agreement.

 

 

 

15.1

 

Awareness letter of PricewaterhouseCoopers LLP.

 

 

 

31.1

 

302 Certification - Chairman, President and Chief Executive Officer.

 

 

 

31.2

 

302 Certification — Senior Vice President, Chief Financial Officer and Treasurer.

 

 

 

32.1

 

906 Certification.

 

 

 

101.INS

 

XBRL Instance Document.

 

 

 

101.SCH

 

XBRL Taxonomy Extension Schema Document.

 

 

 

101.CAL

 

XBRL Taxonomy Extension Calculation Linkbase Document.

 

 

 

101.DEF

 

XBRL Taxonomy Extension Definition Linkbase Document.

 

 

 

101.LAB

 

XBRL Taxonomy Extension Label Linkbase Document.

 

 

 

101.PRE

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 

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Table of Contents

 

SIGNATURES

 

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

 

 

CABOT OIL & GAS CORPORATION

 

(Registrant)

 

 

July 25, 2014

By:

/S/ DAN O. DINGES

 

 

Dan O. Dinges

 

 

Chairman, President and Chief Executive Officer

 

 

(Principal Executive Officer)

 

 

July 25, 2014

By:

/S/ SCOTT C. SCHROEDER

 

 

Scott C. Schroeder

 

 

Executive Vice President, Chief Financial Officer and Treasurer

 

 

(Principal Financial Officer)

 

 

July 25, 2014

By:

/S/ TODD M. ROEMER

 

 

Todd M. Roemer

 

 

Controller

 

 

(Principal Accounting Officer)

 

33