10-Q 1 cog-06302015x10q.htm 10-Q
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the quarterly period ended June 30, 2015
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 ý 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 ý 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 ý
As of July 20, 2015, there were 413,807,968 shares of Common Stock, Par Value $.10 Per Share, outstanding.

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CABOT OIL & GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS

|  | Page
Part I. Financial Information |
Item 1. | Financial Statements |
Condensed Consolidated Balance Sheet (Unaudited) at June 30, 2015 and December 31, 2014 | 3
Condensed Consolidated Statement of Operations (Unaudited) for the Three and Six Months Ended June 30, 2015 and 2014 | 4
Condensed Consolidated Statement of Comprehensive Income (Unaudited) for the Three and Six Months Ended June 30, 2015 and 2014 | 5
Condensed Consolidated Statement of Cash Flows (Unaudited) for the Six Months Ended June 30, 2015 and 2014 | 6
Notes to the Condensed Consolidated Financial Statements | 7
Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information | 18
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 19
Item 3. | Quantitative and Qualitative Disclosures about Market Risk | 29
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

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PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

(In thousands, except share amounts) |  | June 30, 2015 |  | December 31, 2014
ASSETS |  |  |  |  |  |
Current assets |  |  |  |  |  |
Cash and cash equivalents |  | $ | 15,231 |  |  | $ | 20,954 |
Accounts receivable, net |  | 138,354 |  |  | 239,009 |
Inventories |  | 20,423 |  |  | 14,026 |
Derivative instruments |  | 76,178 |  |  | 137,603 |
Other current assets |  | 4,807 |  |  | 1,855 |
Total current assets |  | 254,993 |  |  | 413,447 |
Properties and equipment, net (Successful efforts method) |  | 5,132,655 |  |  | 4,925,711 |
Equity method investments |  | 81,075 |  |  | 68,029 |
Other assets |  | 36,197 |  |  | 30,529 |
|  | $ | 5,504,920 |  |  | $ | 5,437,716 |
LIABILITIES AND STOCKHOLDERS' EQUITY |  |  |  |  |  |
Current liabilities |  |  |  |  |  |
Accounts payable |  | $ | 218,633 |  |  | $ | 400,076 |
Accrued liabilities |  | 57,465 |  |  | 63,669 |
Deferred income taxes |  | 2,754 |  |  | 35,273 |
Total current liabilities |  | 278,852 |  |  | 499,018 |
Postretirement benefits |  | 37,314 |  |  | 35,827 |
Long-term debt |  | 1,995,000 |  |  | 1,752,000 |
Deferred income taxes |  | 878,069 |  |  | 843,876 |
Asset retirement obligations |  | 134,763 |  |  | 124,655 |
Other liabilities |  | 35,006 |  |  | 39,607 |
Total liabilities |  | 3,359,004 |  |  | 3,294,983 |
Commitments and contingencies |  |  |  |
Stockholders' equity |  |  |  |  |  |
Common stock: |  |  |  |  |  |
Authorized — 960,000,000 shares of $0.10 par value in 2015 and 2014, respectively |  |  |  |  |  |
Issued — 423,700,648 shares and 422,915,258 shares in 2015 and 2014, respectively |  | 42,370 |  |  | 42,292 |
Additional paid-in capital |  | 717,327 |  |  | 710,432 |
Retained earnings |  | 1,695,205 |  |  | 1,698,995 |
Accumulated other comprehensive income (loss) |  | (2,151 | ) |  | (2,151 | )
Less treasury stock, at cost: |  |  |  |  |  |
9,892,680 shares in 2015 and 2014, respectively |  | (306,835 | ) |  | (306,835 | )
Total stockholders' equity |  | 2,145,916 |  |  | 2,142,733 |
|  | $ | 5,504,920 |  |  | $ | 5,437,716 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
(In thousands, except per share amounts) |  | 2015 |  | 2014 |  | 2015 |  | 2014
OPERATING REVENUES |  |  |  |  |  |  |  |  |  |  |  |
Natural gas |  | $ | 224,806 |  |  | $ | 437,761 |  |  | $ | 584,997 |  |  | $ | 870,571 |
Crude oil and condensate |  | 81,233 |  |  | 86,341 |  |  | 143,791 |  |  | 145,485 |
Gain (loss) on derivative instruments |  | (6,819 | ) |  | (2,329 | ) |  | 27,304 |  |  | (2,329 | )
Brokered natural gas |  | 3,813 |  |  | 8,140 |  |  | 8,640 |  |  | 21,293 |
Other |  | 3,264 |  |  | 3,274 |  |  | 6,330 |  |  | 7,970 |
|  | 306,297 |  |  | 533,187 |  |  | 771,062 |  |  | 1,042,990 |
OPERATING EXPENSES |  |  |  |  |  |  |  |  |  |  |  |
Direct operations |  | 36,112 |  |  | 35,605 |  |  | 72,129 |  |  | 71,439 |
Transportation and gathering |  | 98,295 |  |  | 83,976 |  |  | 219,531 |  |  | 161,741 |
Brokered natural gas |  | 2,885 |  |  | 7,031 |  |  | 6,624 |  |  | 18,891 |
Taxes other than income |  | 11,611 |  |  | 12,816 |  |  | 22,891 |  |  | 25,860 |
Exploration |  | 5,298 |  |  | 4,676 |  |  | 14,030 |  |  | 11,150 |
Depreciation, depletion and amortization |  | 152,513 |  |  | 157,563 |  |  | 328,009 |  |  | 304,981 |
General and administrative |  | 19,978 |  |  | 20,127 |  |  | 42,507 |  |  | 41,763 |
|  | 326,692 |  |  | 321,794 |  |  | 705,721 |  |  | 635,825 |
Earnings (loss) on equity method investments |  | 1,512 |  |  | 756 |  |  | 2,933 |  |  | 756 |
Gain (loss) on sale of assets |  | (79 | ) |  | (1,496 | ) |  | 59 |  |  | (2,781 | )
INCOME (LOSS) FROM OPERATIONS |  | (18,962 | ) |  | 210,653 |  |  | 68,333 |  |  | 405,140 |
Interest expense |  | 24,168 |  |  | 16,334 |  |  | 47,734 |  |  | 32,891 |
Income (loss) before income taxes |  | (43,130 | ) |  | 194,319 |  |  | 20,599 |  |  | 372,249 |
Income tax (benefit) expense |  | (15,622 | ) |  | 75,899 |  |  | 7,852 |  |  | 146,798 |
NET INCOME (LOSS) |  | $ | (27,508 | ) |  | $ | 118,420 |  |  | $ | 12,747 |  |  | $ | 225,451 |
Earnings (loss) per share |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (0.07 | ) |  | $ | 0.28 |  |  | $ | 0.03 |  |  | $ | 0.54 |
Diluted |  | $ | (0.07 | ) |  | $ | 0.28 |  |  | $ | 0.03 |  |  | $ | 0.54 |
Weighted-average common shares outstanding |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | 413,713 |  |  | 417,291 |  |  | 413,530 |  |  | 417,097 |
Diluted |  | 413,713 |  |  | 419,092 |  |  | 414,878 |  |  | 418,742 |
Dividends per common share |  | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.04 |  |  | $ | 0.04 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Unaudited)

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
(In thousands) |  | 2015 |  | 2014 |  | 2015 |  | 2014
Net income (loss) |  | $ | (27,508 | ) |  | $ | 118,420 |  |  | $ | 12,747 |  |  | $ | 225,451 |
Other comprehensive income (loss), net of taxes: |  |  |  |  |  |  |  |  |  |  |  |
Reclassification adjustment for settled cash flow hedge contracts(1) |  | — |  |  | 13,807 |  |  | — |  |  | 56,372 |
Changes in fair value of cash flow hedge contracts(2) |  | — |  |  | — |  |  | — |  |  | (80,175 | )
Total other comprehensive income (loss) |  | — |  |  | 13,807 |  |  | — |  |  | (23,803 | )
Comprehensive income (loss) |  | $ | (27,508 | ) |  | $ | 132,227 |  |  | $ | 12,747 |  |  | $ | 201,648 |

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

(2) | Net of income taxes of $53,135 for the six months ended June 30, 2014.

The accompanying notes are an integral part of these condensed consolidated financial statements.
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CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

|  | Six Months Ended June 30,
(In thousands) |  | 2015 |  | 2014
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |  |  |  |
Net income |  | $ | 12,747 |  |  | $ | 225,451 |
Adjustments to reconcile net income to cash provided by operating activities: |  |  |  |  |  |
Depreciation, depletion and amortization |  | 328,009 |  |  | 304,981 |
Deferred income tax expense |  | 7,160 |  |  | 118,453 |
(Gain) loss on sale of assets |  | (59 | ) |  | 2,781 |
Exploratory dry hole cost |  | 178 |  |  | 2,154 |
(Gain) loss on derivative instruments |  | (27,304 | ) |  | 2,329 |
Net cash received (paid) in settlement of derivative instruments |  | 88,730 |  |  | (15,262 | )
Amortization of debt issuance costs |  | 2,337 |  |  | 2,252 |
Stock-based compensation and other |  | 11,602 |  |  | 8,689 |
Changes in assets and liabilities: |  |  |  |  |  |
Accounts receivable, net |  | 99,897 |  |  | 9,588 |
Income taxes |  | (2,184 | ) |  | (23,352 | )
Inventories |  | (6,397 | ) |  | 5,554 |
Other current assets |  | (2,953 | ) |  | 15 |
Accounts payable and accrued liabilities |  | (65,023 | ) |  | (39,084 | )
Other assets and liabilities |  | (2,663 | ) |  | 753 |
Stock-based compensation tax benefit |  | (5,486 | ) |  | (20,354 | )
Net cash provided by operating activities |  | 438,591 |  |  | 584,948 |
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |  |  |  |
Capital expenditures |  | (645,092 | ) |  | (617,613 | )
Acquisitions |  | (16,300 | ) |  | — |
Proceeds from sale of assets |  | 3,002 |  |  | (755 | )
Restricted cash |  | — |  |  | 28,094 |
Investment in equity method investments |  | (10,114 | ) |  | (22,230 | )
Net cash used in investing activities |  | (668,504 | ) |  | (612,504 | )
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |  |  |  |
Borrowings from debt |  | 642,000 |  |  | 611,000 |
Repayments of debt |  | (399,000 | ) |  | (565,000 | )
Dividends paid |  | (16,537 | ) |  | (16,679 | )
Stock-based compensation tax benefit |  | 5,486 |  |  | 20,354 |
Capitalized debt issuance costs |  | (7,838 | ) |  | — |
Other |  | 79 |  |  | 91 |
Net cash provided by financing activities |  | 224,190 |  |  | 49,766 |
Net (decrease) increase in cash and cash equivalents |  | (5,723 | ) |  | 22,210 |
Cash and cash equivalents, beginning of period |  | 20,954 |  |  | 23,400 |
Cash and cash equivalents, end of period |  | $ | 15,231 |  |  | $ | 45,610 |
Supplemental non-cash transactions: |  |  |  |
Change in accrued capital costs |  | (134,875 | ) |  | (32,616 | )

The accompanying notes are an integral part of these condensed consolidated financial statements.
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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, 2014 (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, 2015 and for the three and six months ended June 30, 2015 and 2014, 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 24, 2015 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 March 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The guidance is effective for interim periods and annual period beginning after December 15, 2015; however, early adoption is permitted. The Company does not believe the adoption of this guidance will have a material effect on its financial position, results of operations or cash flows.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, 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. In July 2015, the FASB finalized the delay of the effective date by one year, making the new standard effective for interim periods and annual period beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption; however, the entities reporting under U.S. GAAP are not permitted to adopt the standard earlier than the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). 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:

(In thousands) |  | June 30, 2015 |  | December 31, 2014
Proved oil and gas properties |  | $ | 8,531,171 |  |  | $ | 7,984,979 |
Unproved oil and gas properties |  | 451,332 |  |  | 492,208 |
Gathering and pipeline systems |  | 242,371 |  |  | 241,272 |
Land, building and other equipment |  | 114,809 |  |  | 109,758 |
|  | 9,339,683 |  |  | 8,828,217 |
Accumulated depreciation, depletion and amortization |  | (4,207,028 | ) |  | (3,902,506 | )
|  | $ | 5,132,655 |  |  | $ | 4,925,711 |

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At June 30, 2015, the Company did not have any projects that had exploratory well costs capitalized for a period of greater than one year after drilling.
3. Equity Method Investments
Activity related to the Company's equity method investments is as follows:

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
(In thousands) |  | 2015 |  | 2014 |  | 2015 |  | 2014
Constitution Pipeline Company, LLC |  |  |  |  |  |  |  |
Contributions |  | $ | 3,000 |  |  | $ | 15,250 |  |  | $ | 6,000 |  |  | $ | 21,000 |
Earnings (loss) on equity method investments |  | 1,528 |  |  | 854 |  |  | 2,955 |  |  | 854 |
|  | $ | 4,528 |  |  | $ | 16,104 |  |  | $ | 8,955 |  |  | $ | 21,854 |
Meade Pipeline Co LLC |  |  |  |  |  |  |  |
Contributions |  | $ | 2,036 |  |  | $ | 1,043 |  |  | $ | 4,114 |  |  | $ | 1,230 |
Earnings (loss) on equity method investments |  | (16 | ) |  | (98 | ) |  | (22 | ) |  | (98 | )
|  | $ | 2,020 |  |  | $ | 945 |  |  | $ | 4,092 |  |  | $ | 1,132 |
Total |  |  |  |  |  |  |  |
Contributions |  | $ | 5,036 |  |  | $ | 16,293 |  |  | $ | 10,114 |  |  | $ | 22,230 |
Earnings (loss) on equity method investments |  | 1,512 |  |  | 756 |  |  | 2,933 |  |  | 756 |
|  | $ | 6,548 |  |  | $ | 17,049 |  |  | $ | 13,047 |  |  | $ | 22,986 |

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.
4. Debt and Credit Agreements
The Company’s debt and credit agreements consisted of the following:

(In thousands) |  | June 30, 2015 |  | December 31, 2014
7.33% weighted-average fixed rate notes |  | $ | 20,000 |  |  | $ | 20,000 |
6.51% weighted-average fixed rate notes |  | 425,000 |  |  | 425,000 |
9.78% fixed rate notes |  | 67,000 |  |  | 67,000 |
5.58% weighted-average fixed rate notes |  | 175,000 |  |  | 175,000 |
3.65% weighted-average fixed rate notes |  | 925,000 |  |  | 925,000 |
Revolving credit facility |  | 383,000 |  |  | 140,000 |
|  | $ | 1,995,000 |  |  | $ | 1,752,000 |

The Company was in compliance with all restrictive financial covenants for both the revolving credit facility and fixed rate notes as of June 30, 2015.
Revolving credit facility
At June 30, 2015, the Company had $383.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 2.0% and had unused commitments of $1.4 billion. The Company’s weighted-average effective interest rate under the revolving credit facility for the three months ended June 30, 2015 and 2014 was approximately 2.2% and 2.1%, respectively, and for the six months ended June 30, 2015 and 2014 was approximately 2.3% and 2.2%, respectively.
Effective April 17, 2015, the Company amended its revolving credit facility to extend the maturity date from May 2017 to April 2020 and change the mechanism under which interest rate margins are determined for outstanding borrowings. The revolving credit facility, as amended, provides for an increase in the borrowing base from $3.1 billion to $3.4 billion and an increase in commitments from $1.4 billion to $1.8 billion. The amended credit facility also provides for an accordion feature, which allows the Company to increase the available credit line up to an additional $500 million if one or more of the
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existing or new banks agree to provide such increased amount. The borrowing base is redetermined annually under the terms of the revolving credit facility on April 1. In addition, either the Company or the banks may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties.
Interest rates under the amended credit facility are based on Eurodollar (LIBOR) or alternate base rate (ABR) indications, plus a margin. The associated margins are based on the Company's leverage ratio as shown below:

| Leverage Ratio(1)
| <1.0x |  | ≥1.0x and <2.0x |  | ≥2.0x and <3.0x |  | ≥3.0x
Eurodollar loans | 1.50 | % |  | 1.75 | % |  | 2.00 | % |  | 2.25 | %
ABR loans | 0.50 | % |  | 0.75 | % |  | 1.00 | % |  | 1.25 | %

(1) The ratio of debt and other liabilities to Consolidated EBITDAX, as defined in the credit agreement.
Upon the Company achieving an investment grade rating from either Moody's or S&P, the associated margins will be adjusted and determined based on the Company's respective credit rating on a prospective basis.
The amended credit facility also provides for a commitment fee on the unused available balance at annual rates ranging from 0.30% to 0.50%. The other terms and conditions of the amended facility are generally consistent with the terms and conditions of the revolving credit facility prior to its amendment as disclosed in Note 5 of the Notes to the Consolidated Financial Statements in the Form 10-K.
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. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. 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.
Through March 31, 2014, the Company elected to designate its commodity derivatives as cash flow hedges for accounting purposes. Effective April 1, 2014, the Company elected to discontinue hedge accounting for its commodity derivatives on a prospective basis. 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 reclassified into natural gas and crude oil and condensate revenues in the Condensed Consolidated Statement of Operations throughout the remainder of 2014 as the underlying hedged transactions occurred. As of June 30, 2015 and December 31, 2014, there were no gains or losses deferred in accumulated other comprehensive income (loss) associated with the Company's commodity derivatives.
As of June 30, 2015, 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 |  | 35.7 |  | Bcf |  | Jul. 2015 - Dec. 2015 |  | $3.86 - $3.91 |  | $ | 3.87 |  |  | $4.27 - $4.43 |  | $ | 4.35 |  |  |  |
Natural gas |  | 35.7 |  | Bcf |  | Jul. 2015 - Dec. 2015 |  |  |  |  |  |  |  |  |  |  |  | $ | 3.92 |
Natural gas |  | 17.9 |  | Bcf |  | Jul. 2015 - Oct. 2015 |  |  |  |  |  |  |  |  |  | $ | 3.36 |

In the table above, natural gas prices are stated per Mcf.
Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet

|  |  |  | Fair Values of Derivative Instruments
|  |  |  | Derivative Assets |  | Derivative Liabilities
(In thousands) |  | Balance Sheet Location |  | June 30, 2015 |  | December 31, 2014 |  | June 30, 2015 |  | December 31, 2014
Commodity contracts |  | Derivative instruments (current assets) |  | $ | 76,178 |  |  | $ | 137,603 |  |  | $ | — |  |  | $ | — |

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

(In thousands) |  | June 30, 2015 |  | December 31, 2014
Derivative Assets |  |  |  |  |  |
Gross amounts of recognized assets |  | $ | 76,178 |  |  | $ | 137,603 |
Gross amounts offset in the statement of financial position |  | — |  |  | — |
Net amounts of assets presented in the statement of financial position |  | 76,178 |  |  | 137,603 |
Gross amounts of financial instruments not offset in the statement of financial position |  | — |  |  | 2,338 |
Net amount |  | $ | 76,178 |  |  | $ | 139,941 |

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) |  | 2015 |  | 2014 |  | 2015 |  | 2014
Commodity contracts |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (133,310 | )

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) |  | 2015 |  | 2014 |  | 2015 |  | 2014
Natural gas revenues |  | $ | — |  |  | $ | (22,320 | ) |  | $ | — |  |  | $ | (92,877 | )
Crude oil and condensate revenues |  | — |  |  | (636 | ) |  | — |  |  | (854 | )
|  | $ | — |  |  | $ | (22,956 | ) |  | $ | — |  |  | $ | (93,731 | )

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Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
(In thousands) |  | 2015 |  | 2014 |  | 2015 |  | 2014
Derivatives Designated as Hedges |  |  |  |  |  |  |  |  |  |  |  |
Cash received (paid) on settlement of derivative instruments |  |  |  |  |  |  |  |  |  |  |  |
Natural gas |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (70,557 | )
Crude oil and condensate |  | — |  |  | — |  |  | — |  |  | (218 | )
|  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (70,775 | )
Derivatives Not Designated as Hedges |  |  |  |  |  |  |  |  |  |  |  |
Cash received (paid) on settlement of derivative instruments |  |  |  |  |  |  |  |  |  |  |  |
Natural gas |  | $ | — |  |  | $ | (22,320 | ) |  | $ | — |  |  | $ | (22,320 | )
Crude oil and condensate |  | — |  |  | (636 | ) |  | — |  |  | (636 | )
Gain (loss) on derivative instruments |  | 51,045 |  |  | (15,262 | ) |  | 88,730 |  |  | (15,262 | )
Non-cash gain (loss) on derivative instruments |  |  |  |  |  |  |  |  |  |  |  |
Gain (loss) on derivative instruments |  | (57,864 | ) |  | 12,933 |  |  | (61,426 | ) |  | 12,933 |
|  | $ | (6,819 | ) |  | $ | (25,285 | ) |  | $ | 27,304 |  |  | $ | (25,285 | )
|  | $ | (6,819 | ) |  | $ | (25,285 | ) |  | $ | 27,304 |  |  | $ | (96,060 | )

For the three and six months ended June 30, 2014, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations related to derivative instruments designated as cash flow hedges. In addition, the Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non-performance by third parties.
6. Fair Value Measurements
The Company follows the authoritative guidance for measuring fair value of assets and liabilities in its financial statements. For further information regarding the fair value hierarchy, refer to Note 1 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, at fair value on a nonrecurring basis. As none of the Company’s non-financial assets and liabilities were measured at fair value as of June 30, 2015 and 2014, additional disclosures were not required.
The estimated fair value of the Company’s asset retirement obligations 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 obligations was classified as Level 3 in the fair value hierarchy.
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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) |  | Balance at June 30, 2015
Assets |  |  |  |  |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 13,282 |  |  | $ | — |  |  | $ | — |  |  | $ | 13,282 |
Derivative contracts |  | — |  |  | 28,180 |  |  | 47,998 |  |  | 76,178 |
Total assets |  | $ | 13,282 |  |  | $ | 28,180 |  |  | $ | 47,998 |  |  | $ | 89,460 |
Liabilities |  |  |  |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 30,130 |  |  | $ | — |  |  | $ | — |  |  | $ | 30,130 |
Total liabilities |  | $ | 30,130 |  |  | $ | — |  |  | $ | — |  |  | $ | 30,130 |

(In thousands) |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  | Balance at December 31, 2014
Assets |  |  |  |  |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 13,115 |  |  | $ | — |  |  | $ | — |  |  | $ | 13,115 |
Derivative contracts |  | — |  |  | 51,645 |  |  | 85,958 |  |  | 137,603 |
Total assets |  | $ | 13,115 |  |  | $ | 51,645 |  |  | $ | 85,958 |  |  | $ | 150,718 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 28,932 |  |  | $ | — |  |  | $ | — |  |  | $ | 28,932 |
Total liabilities |  | $ | 28,932 |  |  | $ | — |  |  | $ | — |  |  | $ | 28,932 |

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

|  | Six Months Ended June 30,
(In thousands) |  | 2015 |  | 2014
Balance at beginning of period |  | $ | 85,958 |  |  | $ | (3,910 | )
Total gains (losses) (realized or unrealized): |  |  |  |  |  |
Realized and unrealized gains (losses) included in earnings |  | 12,662 |  |  | (77,935 | )
Included in other comprehensive income |  | — |  |  | (38,412 | )
Settlements |  | (50,622 | ) |  | 93,342 |
Transfers in and/or out of Level 3 |  | — |  |  | — |
Balance at end of period |  | $ | 47,998 |  |  | $ | (26,915 | )
Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period |  | $ | (37,961 | ) |  | $ | 15,407 |

There were no transfers between Level 1 and Level 2 measurements for the three and six months ended June 30, 2015 and 2014.
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 amount reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents approximates fair value due to the short-term maturities of these instruments. Cash and cash equivalents are classified as Level 1 in the fair value hierarchy.
The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of 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 debt is valued using an income approach and classified as Level 3 in the fair value hierarchy.
The carrying amounts and fair values of debt are as follows:

|  | June 30, 2015 |  | December 31, 2014
(In thousands) |  | Carrying Amount |  | Estimated Fair Value |  | Carrying Amount |  | Estimated Fair Value
Debt |  | $ | 1,995,000 |  |  | $ | 2,028,913 |  |  | $ | 1,752,000 |  |  | $ | 1,850,867 |

7. Asset Retirement Obligations
Activity related to the Company’s asset retirement obligations is as follows:

(In thousands) |  | Six Months Ended June 30, 2015
Balance at beginning of period |  | $ | 126,655 |
Liabilities incurred |  | 6,969 |
Liabilities settled |  | (203 | )
Accretion expense |  | 3,342 |
Balance at end of period |  | $ | 136,763 |

As of both June 30, 2015 and December 31, 2014, 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 obligations.
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8. Commitments and Contingencies
Contractual Obligations
The Company has various contractual obligations in the normal course of its operations. There have been no material changes to 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.
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 would not be 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.
9. Stock-based Compensation
General
Stock-based compensation expense during the first six months of 2015 and 2014 was $14.5 million and $9.4 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 2015 and 2014 was $8.6 million and $6.3 million, respectively.
During the first six months of 2015 and 2014, the Company recognized a $5.5 million and $20.4 million tax benefit related to the federal tax deduction in excess of book compensation cost for employee stock-based compensation, respectively. The Company is able to recognize this tax benefit only to the extent it reduces the Company’s income taxes payable.
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 stock-based compensation awards and the applicable award terms.
Restricted Stock Awards
During the first six months of 2015, 3,400 restricted stock awards were granted to employees with a weighted-average grant date per share value of $28.55. The fair value of restricted stock grants is based on the closing 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 2015, 47,320 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date per unit value of $27.96. The fair value of these units is measured based on the closing 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 2015 commenced on January 1, 2015 and ends on December 31, 2017. 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.
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Performance Share Awards Based on Internal Performance Metrics
The fair value of performance award grants based on internal performance metrics is based on the closing 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 2015, 349,780 Employee Performance Share Awards were granted at a grant date per share value of $27.71. 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, 2015, it is considered probable that the criteria for these awards will be met.
Hybrid Performance Share Awards. During the first six months of 2015, 194,947 Hybrid Performance Share Awards were granted at a grant date per share value of $27.71. The 2015 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, 2015, it is considered probable that the criteria for these awards 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 2015, 292,421 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 a predetermined group of 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 19, 2015) and the period-end fair value of the liability component of the TSR Performance Share Awards:

|  | Grant Date |  | June 30, 2015
Fair value per performance share award |  | $ | 19.29 |  |  | $14.60 - $19.30 |
Assumptions: |  |  |  |  |  |
Stock price volatility |  | 32.3 | % |  | 25.6% - 29.0% |
Risk free rate of return |  | 1.0 | % |  | 0.1% - 0.8% |
Expected dividend yield |  | 0.3 | % |  | 0.3 | %

Supplemental Employee Incentive Plan
The Company recognized stock-based compensation expense of $1.6 million for the three months ended June 30, 2014. Stock-based compensation (benefit) expense recognized in the second quarter of 2015 was immaterial. The Company recognized stock-based compensation (benefit) expense of $(0.1) million and $3.1 million for the six months ended June 30, 2015 and 2014, respectively, related to the Company’s Supplemental Employee Incentive 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 to determine the period-end fair value of the Supplemental Employee Incentive Plan IV liability using a Monte Carlo simulation model:

| June 30, 2015
Stock price volatility | 30.3 | %
Risk free rate of return | 0.7 | %
Annual salary increase rate | 4.0 | %
Annual turnover rate | 4.6 | %

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10. Earnings per Common Share
Basic earnings per share (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.
The following is a calculation of basic and diluted weighted-average shares outstanding:

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
(In thousands) |  | 2015 |  | 2014 |  | 2015 |  | 2014
Weighted-average shares - basic |  | 413,713 |  |  | 417,291 |  |  | 413,530 |  |  | 417,097 |
Dilution effect of stock appreciation rights and stock awards at end of period |  | — |  |  | 1,801 |  |  | 1,348 |  |  | 1,645 |
Weighted-average shares - diluted |  | 413,713 |  |  | 419,092 |  |  | 414,878 |  |  | 418,742 |
Weighted-average stock awards and shares excluded from diluted EPS due to the anti-dilutive effect |  | 1,655 |  |  | 2 |  |  | 400 |  |  | 409 |

11. Accumulated Other Comprehensive Income (Loss)
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) |  | 2015 |  | 2014 |  | 2015 |  | 2014 |  | Consolidated Statement of Operations
Gain (Loss) on Cash Flow Hedges |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts |  | $ | — |  |  | $ | (22,320 | ) |  | $ | — |  |  | $ | (92,877 | ) |  | Natural gas revenues
Commodity contracts |  | — |  |  | (636 | ) |  | — |  |  | (854 | ) |  | Crude oil and condensate revenues
|  | — |  |  | (22,956 | ) |  | — |  |  | (93,731 | ) |  | Total before tax
|  | — |  |  | 9,149 |  |  | — |  |  | 37,359 |  |  | Tax benefit (expense)
Total reclassifications for the period |  | $ | — |  |  | $ | (13,807 | ) |  | $ | — |  |  | $ | (56,372 | ) |  | Net of tax

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12. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:

(In thousands) |  | June 30, 2015 |  | December 31, 2014
Accounts receivable, net |  |  |  |  |  |
Trade accounts |  | $ | 130,729 |  |  | $ | 227,835 |
Joint interest accounts |  | 1,388 |  |  | 2,245 |
Income taxes receivable |  | 5,797 |  |  | 3,612 |
Other accounts |  | 1,440 |  |  | 6,515 |
|  | 139,354 |  |  | 240,207 |
Allowance for doubtful accounts |  | (1,000 | ) |  | (1,198 | )
|  | $ | 138,354 |  |  | $ | 239,009 |
Inventories |  |  |  |  |  |
Tubular goods and well equipment |  | $ | 17,750 |  |  | $ | 10,675 |
Natural gas in storage |  | 2,651 |  |  | 3,281 |
Other accounts |  | 22 |  |  | 70 |
|  | $ | 20,423 |  |  | $ | 14,026 |
Other assets |  |  |  |  |  |
Deferred compensation plan |  | $ | 13,282 |  |  | $ | 13,115 |
Debt issuance cost |  | 22,850 |  |  | 17,349 |
Other accounts |  | 65 |  |  | 65 |
|  | $ | 36,197 |  |  | $ | 30,529 |
Accounts payable |  |  |  |  |  |
Trade accounts |  | $ | 37,627 |  |  | $ | 54,949 |
Natural gas purchases |  | 3,138 |  |  | 2,407 |
Royalty and other owners |  | 75,759 |  |  | 97,298 |
Accrued capital costs |  | 87,551 |  |  | 222,426 |
Taxes other than income |  | 8,818 |  |  | 16,806 |
Drilling advances |  | 81 |  |  | 88 |
Other accounts |  | 5,659 |  |  | 6,102 |
|  | $ | 218,633 |  |  | $ | 400,076 |
Accrued liabilities |  |  |  |  |  |
Employee benefits |  | $ | 12,871 |  |  | $ | 22,815 |
Taxes other than income |  | 11,663 |  |  | 7,128 |
Interest payable |  | 30,143 |  |  | 30,677 |
Other accounts |  | 2,788 |  |  | 3,049 |
|  | $ | 57,465 |  |  | $ | 63,669 |
Other liabilities |  |  |  |  |  |
Deferred compensation plan |  | $ | 30,130 |  |  | $ | 28,932 |
Other accounts |  | 4,876 |  |  | 10,675 |
|  | $ | 35,006 |  |  | $ | 39,607 |

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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, 2015, and the related condensed consolidated statements of operations and of comprehensive income for the three-month and six-month periods ended June 30, 2015 and June 30, 2014 and the condensed consolidated statement of cash flows for the six-month periods ended June 30, 2015 and June 30, 2014. 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, 2014, 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 27, 2015, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2014, 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 24, 2015
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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, 2015 and 2014 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, 2014 (Form 10-K).
Overview
On an equivalent basis, our production for the six months ended June 30, 2015 increase d by 25% compared to the six months ended June 30, 2014. For the six months ended June 30, 2015, we produced 309.4 Bcfe, or 1,709 Mmcfe per day, compared to 247.5 Bcfe, or 1,367 Mmcfe per day, for the six months ended June 30, 2014. Natural gas production increase d by 52.6 Bcf, or 22%, to 290.2 Bcf for the first six months of 2015 compared to 237.6 Bcf for the first six months of 2014. This increase was primarily the result of higher production in the Marcellus Shale associated with our drilling program in Pennsylvania. Crude oil/condensate/NGL production increase d by 1.6 Mmbbls, or 95%, to 3.2 Mmbbls in the first six months of 2015 from 1.6 Mmbbls in the first six months of 2014. This increase was the result of higher production associated with our oil-focused Eagle Ford Shale drilling program in south Texas and production associated with the south Texas asset acquisitions in the fourth quarter of 2014.
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 2015 was $2.32 per Mcf, 36% lower than the $3.60 per Mcf realized in the first six months of 2014. Our average realized crude oil price for the first six months of 2015 was $50.00 per Bbl, 49% lower than the $98.39 per Bbl realized in the first six months of 2014. These realized prices include gains and losses resulting from the settlement of commodity derivatives. For information about the impact of realized commodity prices on our natural gas and crude oil and condensate revenues, 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 in these prices will have on our capital program, production volumes or 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.
We account for our derivative instruments on a mark-to-market basis with changes in fair value recognized 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 2015, we drilled 87 gross wells (78.5 net) with a success rate of 100% compared to 76 gross wells (62.0 net) with a success rate of 100% for the comparable period of the prior year. Our total capital and exploration expenditures were $540.4 million for the six months ended June 30, 2015 compared to $594.0 million for the six months ended June 30, 2014. 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 full year 2015 drilling program includes approximately $900.0 million in capital and exploration expenditures and approximately $38.3 million in expected contributions to our equity method investments and is expected to be funded by operating cash flow, existing cash and 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, 2015 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 (including contributions to our equity method investments), interest payments on debt and payment of dividends. See below for additional discussion and analysis of cash flow.
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Effective April 17, 2015, we amended our revolving credit facility to extend the maturity date from May 2017 to April 2020 and to change the mechanism under which interest rate margins are determined for outstanding borrowings. The revolving credit facility, as amended, provides for an increase in the borrowing base from $3.1 billion to $3.4 billion and an increase in commitments from $1.4 billion to $1.8 billion. The amended credit facility also provides for an accordion feature, which allows us to increase the available credit line up to an additional $500 million if one or more of the existing or new banks agree to provide such increased amount. The borrowing base is redetermined annually under the terms of the revolving credit facility on April 1. In addition, either we or the banks may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties. See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further details regarding our debt.
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.
Cash Flows
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, such as decreases in crude oil and natural gas prices and other factors 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) |  | 2015 |  | 2014
Cash flows provided by operating activities |  | $ | 438,591 |  |  | $ | 584,948 |
Cash flows used in investing activities |  | (668,504 | ) |  | (612,504 | )
Cash flows provided by financing activities |  | 224,190 |  |  | 49,766 |
Net (decrease) increase in cash and cash equivalents |  | $ | (5,723 | ) |  | $ | 22,210 |

Operating Activities. Net cash provided by operating activities in the first six months of 2015 decrease d by $146.4 million over the first six months of 2014. This decrease was primarily due to lower operating revenues and higher operating expenses (excluding non-cash expenses), partially offset by favorable changes in working capital and other assets and liabilities. The decrease in operating revenues was primarily due to a decrease in realized natural gas and crude oil prices, partially offset by an increase in equivalent production. Average realized natural gas and crude oil prices decrease d by 36% and 49%, respectively, for the first six months of 2015 compared to the first six months of 2014. Equivalent production increase d by 25% for the first six months of 2015 compared to the first six months of 2014 due to higher natural gas and oil production.
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 increase d by $56.0 million for the first six months of 2015 compared to the first six months of 2014. The increase was due to $27.5 million of higher capital expenditures, $28.1 million of changes in restricted cash balances and a $16.3 million increase in acquisition expenditures related to the acquisition of certain remaining leases associated with our south Texas asset acquisition that closed in the fourth quarter of 2014, partially offset by $12.1 million lower capital contributions associated with our equity method investments and $3.8 million higher proceeds from the sale of assets.
Financing Activities. Cash flows provided by financing activities increase d by $174.4 million for the first six months of 2015 compared to the first six months of 2014. This increase was primarily due to $197.0 million of higher net borrowings, partially offset by a decrease of $14.9 million in tax benefits associated with our stock-based compensation and an increase of $7.8 million in capitalized debt issuance cost related to the amendment of our credit facility in April 2015.
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Capitalization
Information about our capitalization is as follows:

(Dollars in thousands) |  | June 30, 2015 |  | December 31, 2014
Debt (1) |  | $ | 1,995,000 |  |  | $ | 1,752,000 |
Stockholders' equity |  | 2,145,916 |  |  | 2,142,733 |
Total capitalization |  | $ | 4,140,916 |  |  | $ | 3,894,733 |
Debt to capitalization |  | 48 | % |  | 45 | %
Cash and cash equivalents |  | $ | 15,231 |  |  | $ | 20,954 |

(1) | Includes $383.0 million and $140.0 million of borrowings outstanding under our revolving credit facility at June 30, 2015 and December 31, 2014, respectively.

During the six months ended June 30, 2015 and 2014, we paid dividends of $16.5 million ($0.04 per share) and $16.7 million ($0.04 per share) on our common stock, respectively. 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, if required, 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) |  | 2015 |  | 2014
Capital expenditures |  |  |  |  |  |
Drilling and facilities |  | $ | 494,002 |  |  | $ | 547,980 |
Leasehold acquisitions |  | 12,825 |  |  | 26,584 |
Property acquisitions |  | 16,300 |  |  | — |
Pipeline and gathering |  | 1,089 |  |  | 227 |
Other |  | 2,122 |  |  | 8,043 |
|  | 526,338 |  |  | 582,834 |
Exploration expenditures |  | 14,030 |  |  | 11,150 |
Total |  | $ | 540,368 |  |  | $ | 593,984 |

For the full year of 2015, we plan to drill approximately 125 gross wells (115.0 net). In 2015, we plan to spend approximately $900.0 million in total capital and exploration expenditures, compared to $1.6 billion (excluding property acquisitions of $214.7 million) in 2014. 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. 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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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 March 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The guidance is effective for interim periods and annual period beginning after December 15, 2015; however, early adoption is permitted. We do not believe the adoption of this guidance will have a material effect on our financial position, results of operations or cash flows.
May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, 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. In July 2015, the FASB finalized the delay of the effective date by one year, making the new standard effective for interim periods and annual period beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption; however, the entities reporting under U.S. GAAP are not permitted to adopt the standard earlier than the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations or cash flows.
Results of Operations
Second Quarter s of 2015 and 2014 Compared
We reported a net loss in the second quarter of 2015 of $27.5 million, or $0.07 per share, compared to net income of $118.4 million, or $0.28 per share, in the second quarter of 2014. The decrease in net income was primarily due to lower operating revenues, higher operating expenses and interest expense, partially offset by lower 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) |  | 2015 |  | 2014 |  | Amount |  | Percent
Natural gas |  | $ | 224,806 |  |  | $ | 437,761 |  |  | $ | (212,955 | ) |  | (49 | )%
Crude oil and condensate |  | 81,233 |  |  | 86,341 |  |  | (5,108 | ) |  | (6 | )%
Gain (loss) on derivative instruments |  | (6,819 | ) |  | (2,329 | ) |  | (4,490 | ) |  | (193 | )%
Brokered natural gas |  | 3,813 |  |  | 8,140 |  |  | (4,327 | ) |  | (53 | )%
Other |  | 3,264 |  |  | 3,274 |  |  | (10 | ) |  | — | %
|  | $ | 306,297 |  |  | $ | 533,187 |  |  | $ | (226,890 | ) |  | (43 | )%

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|  | Three Months Ended June 30, |  | Variance |  | Increase (Decrease) (In thousands)
|  | 2015 |  | 2014 |  | Amount |  | Percent |
Price Variances |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (1) |  | $ | 1.75 |  |  | $ | 3.59 |  |  | $ | (1.84 | ) |  | (51 | )% |  | $ | (236,649 | )
Crude oil and condensate (2) |  | $ | 56.10 |  |  | $ | 99.36 |  |  | $ | (43.26 | ) |  | (44 | )% |  | (62,627 | )
Total |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (299,276 | )
Volume Variances |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (Bcf) |  | 128.4 |  |  | 121.8 |  |  | 6.6 |  |  | 5 | % |  | $ | 23,694 |
Crude oil and condensate (Mbbl) |  | 1,448 |  |  | 869 |  |  | 579 |  |  | 67 | % |  | 57,519 |
Total |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 81,213 |

(1) | Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.18 per Mcf . There was no impact in 2015.

(2) | Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.73 per Bbl. There was no impact in 2015.

Natural Gas Revenues
The decrease in natural gas revenues of $213.0 million is due to lower natural gas prices, partially offset by higher production. The increase in production was associated with the positive results of our Marcellus Shale drilling program in Pennsylvania, partially offset by lower production in east Texas due to normal production declines.
Crude Oil and Condensate Revenues
The decrease in crude oil and condensate revenues of $5.1 million is due to lower crude oil prices, partially offset by higher production. The increase in production was a result of our oil-focused drilling program in south Texas and production associated with the south Texas asset acquisitions in the fourth quarter of 2014.
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. Changes in fair value and cash settlements of derivative instruments are recognized in operating revenues in the Condensed Consolidated Statement of Operations.
Impact of Derivative Instruments on Operating Revenues

|  | Three Months Ended June 30,
(In thousands) |  | 2015 |  | 2014
Cash received (paid) on settlement of derivative instruments |  |  |  |  |  |
Natural gas |  | $ | — |  |  | $ | (22,320 | )
Crude oil and condensate |  | — |  |  | (636 | )
Gain (loss) on derivative instruments |  | 51,045 |  |  | (15,262 | )
|  | $ | 51,045 |  |  | $ | (38,218 | )
Non-cash gain (loss) on derivative instruments |  |  |  |  |  |
Gain (loss) on derivative instruments |  | (57,864 | ) |  | 12,933 |
|  | $ | (6,819 | ) |  | $ | (25,285 | )

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Brokered Natural Gas Revenue and Cost

|  | Three Months Ended June 30, |  | Variance |  | Price and Volume Variances (In thousands)
|  | 2015 |  | 2014 |  | Amount |  | Percent |
Brokered Natural Gas Sales |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sales price ($/Mcf) |  | $ | 2.82 |  |  | $ | 4.96 |  |  | $ | (2.14 | ) |  | (43 | )% |  | $ | (2,889 | )
Volume brokered (Mmcf) |  | x | 1,350 |  |  | x | 1,642 |  |  | (292 | ) |  | (18 | )% |  | (1,438 | )
Brokered natural gas (In thousands) |  | $ | 3,813 |  |  | $ | 8,140 |  |  |  |  |  |  | $ | (4,327 | )
Brokered Natural Gas Purchases |  |  |  |  |  |  |  |  |  |  |  |
Purchase price ($/Mcf) |  | $ | 2.14 |  |  | $ | 4.28 |  |  | $ | (2.14 | ) |  | (50 | )% |  | $ | 2,889 |
Volume brokered (Mmcf) |  | x | 1,350 |  |  | x | 1,642 |  |  | (292 | ) |  | (18 | )% |  | 1,257 |
Brokered natural gas (In thousands) |  | $ | 2,885 |  |  | $ | 7,031 |  |  |  |  |  |  |  |  | $ | 4,146 |
Brokered natural gas margin (In thousands) |  | $ | 928 |  |  | $ | 1,109 |  |  |  |  |  |  |  |  | $ | (181 | )

The $0.2 million decrease in brokered natural gas margin is a result of lower brokered volumes.
Operating and Other Expenses

|  | Three Months Ended June 30, |  | Variance
(In thousands) |  | 2015 |  | 2014 |  | Amount |  | Percent
Operating and Other Expenses |  |  |  |  |  |  |  |  |  |  |  |
Direct operations |  | $ | 36,112 |  |  | $ | 35,605 |  |  | $ | 507 |  |  | 1 | %
Transportation and gathering |  | 98,295 |  |  | 83,976 |  |  | 14,319 |  |  | 17 | %
Brokered natural gas |  | 2,885 |  |  | 7,031 |  |  | (4,146 | ) |  | (59 | )%
Taxes other than income |  | 11,611 |  |  | 12,816 |  |  | (1,205 | ) |  | (9 | )%
Exploration |  | 5,298 |  |  | 4,676 |  |  | 622 |  |  | 13 | %
Depreciation, depletion and amortization |  | 152,513 |  |  | 157,563 |  |  | (5,050 | ) |  | (3 | )%
General and administrative |  | 19,978 |  |  | 20,127 |  |  | (149 | ) |  | (1 | )%
|  | $ | 326,692 |  |  | $ | 321,794 |  |  | $ | 4,898 |  |  | 2 | %
Earnings (loss) on equity method investments |  | $ | 1,512 |  |  | $ | 756 |  |  | $ | 756 |  |  | 100 | %
Gain (loss) on sale of assets |  | (79 | ) |  | (1,496 | ) |  | 1,417 |  |  | 95 | %
Interest expense |  | 24,168 |  |  | 16,334 |  |  | 7,834 |  |  | 48 | %
Income tax (benefit) expense |  | (15,622 | ) |  | 75,899 |  |  | (91,521 | ) |  | (121 | )%

Total costs and expenses from operations increase d by $4.9 million, or 2%, in the second quarter of 2015 compared to the same period of 2014. The primary reasons for this fluctuation are as follows:

• | Direct operations increase d $0.5 million largely due to higher operating costs as a result of higher production and production costs associated with the south Texas asset acquisitions in the fourth quarter of 2014. These cost increases were partially offset by cost reductions from suppliers, improved operational efficiencies and lower workover costs in 2015 compared to 2014.

• | Transportation and gathering increase d $14.3 million due to higher throughput as a result of higher Marcellus Shale production, higher transportation rates and the commencement of various transportation and gathering agreements in the Marcellus Shale during 2014.

• | Brokered natural gas decrease d $4.1 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

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• | Taxes other than income decrease d $1.2 million primarily due to $0.9 million lower production taxes resulting from lower oil prices, partially offset by higher oil production in south Texas.

• | Depreciation, depletion and amortization decrease d $5.1 million, of which $23.1 million was due to lower DD&A rate of $1.01 per Mcfe for the second quarter of 2015 compared to $1.18 per Mcfe for the second quarter of 2014, partially offset by a $12.3 million increase due to higher equivalent production volumes. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our Marcellus Shale drilling program and the impairment charge recorded in the fourth quarter of 2014 associated with higher DD&A rate properties. These decreases were partially offset by an increase in amortization of unproved properties of $5.0 million in the second quarter of 2015 due to an increase in amortization rates as a result of ongoing evaluation of our unproved properties and undeveloped leasehold acquisitions during the year.

• | General and administrative decrease d $0.1 million due to $1.6 million lower expense associated with our supplemental employee incentive plan due to the change in fair value associated with the likelihood of our stock price achieving the trigger stock price specified in the plan and $1.0 million lower legal expenses. These decreases were partially offset by $4.0 million of higher stock-based compensation expense primarily due to a $4.3 million increase associated with the mark-to-market of our liability-based performance awards and the change in the liability associated with in our common stock held in the deferred compensation plan. The remaining increases and decreases in other expenses were not individually significant.

Earnings (loss) on equity method investments
The $0.8 million increase in equity method investments is the result of increased activity in 2015 compared to 2014.
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. There was no material gain (loss) on sale of assets in the second quarter of 2015.
Interest Expense
Interest expense increase d $7.8 million due to $8.4 million of higher interest expense associated with our private placement in September 2014 of $925 million aggregate principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 3.65% and an increase in commitment fees on the unused portion of our revolving credit facility of $0.5 million. These increases were partially offset by lower interest expense of $1.1 million associated with our revolving credit facility due to a decrease in weighted-average borrowings based on daily balances of approximately $346.3 million compared to approximately $574.2 million during the second quarter of 2015 and 2014, respectively, partially offset by a slightly higher weighted-average effective interest rate of approximately 2.2% during 2015 compared to approximately 2.1% in 2014, respectively.
Income Tax (Benefit) Expense
Income tax expense decrease d $91.5 million due to lower pretax income and a lower effective tax rate. The effective tax rate for the second quarter of 2015 and 2014 was 36.2% and 39.1%, respectively. The decrease in the effective tax rate was primarily due to a change in our effective state income tax rates based on updated state apportionment factors in states in which we operate. The decrease in our state apportionment factors was primarily driven by a shift in the sourcing of revenues based on the location of customers to whom we ultimately sell our natural gas in the northeast United States.
First Six Months of 2015 and 2014 Compared
We reported net income in the first six months of 2015 of $12.7 million, or $0.03 per share, compared to $225.5 million, or $0.54 per share, in the first six months of 2014. The decrease in net income was due to lower operating revenues and higher operating expenses and interest expense, partially offset by lower income taxes.
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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.

|  | Six Months Ended June 30, |  | Variance
Revenue Variances (In thousands) |  | 2015 |  | 2014 |  | Amount |  | Percent
Natural gas |  | $ | 584,997 |  |  | $ | 870,571 |  |  | $ | (285,574 | ) |  | (33 | )%
Crude oil and condensate |  | 143,791 |  |  | 145,485 |  |  | (1,694 | ) |  | (1 | )%
Gain (loss) on derivative instruments |  | 27,304 |  |  | (2,329 | ) |  | 29,633 |  |  | 1,272 | %
Brokered natural gas |  | 8,640 |  |  | 21,293 |  |  | (12,653 | ) |  | (59 | )%
Other |  | 6,330 |  |  | 7,970 |  |  | (1,640 | ) |  | (21 | )%
|  | $ | 771,062 |  |  | $ | 1,042,990 |  |  | $ | (271,928 | ) |  | (26 | )%

|  | Six Months Ended June 30, |  | Variance |  | Increase (Decrease) (In thousands)
|  | 2015 |  | 2014 |  | Amount |  | Percent |
Price Variances |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (1) |  | $ | 2.02 |  |  | $ | 3.66 |  |  | $ | (1.64 | ) |  | (45 | )% |  | $ | (478,090 | )
Crude oil and condensate (2) |  | $ | 50.00 |  |  | $ | 98.70 |  |  | $ | (48.70 | ) |  | (49 | )% |  | (140,022 | )
Total |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (618,112 | )
Volume Variances |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (Bcf) |  | 290.2 |  |  | 237.6 |  |  | 52.6 |  |  | 22 | % |  | $ | 192,516 |
Crude oil and condensate (Mbbl) |  | 2,876 |  |  | 1,474 |  |  | 1,402 |  |  | 95 | % |  | 138,328 |
Total |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 330,844 |

(1) | Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.39 per Mcf. There was no impact in 2015.

(2) | Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.58 per Bbl. There was no impact in 2015.

Natural Gas Revenues
The decrease in natural gas revenues of $285.6 million is due to lower natural gas prices, partially offset by higher production. The increase in production associated with the positive results of our Marcellus Shale drilling program in Pennsylvania.
Crude Oil and Condensate Revenues
The decrease in crude oil and condensate revenues of $1.7 million is due to lower crude oil prices, partially offset by higher production. The increase in production was a result of our oil-focused Eagle Ford Shale drilling program in south Texas and production associated with the south Texas asset acquisitions in the fourth quarter of 2014.
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. Changes in fair value and cash settlements of derivative instruments are recognized in operating revenues in the Condensed Consolidated Statement of Operations.
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Impact of Derivative Instruments on Operating Revenues

|  | Six Months Ended June 30,
(In thousands) |  | 2015 |  | 2014
Cash received (paid) on settlement of derivative instruments |  |  |  |  |  |
Natural gas |  | $ | — |  |  | $ | (92,877 | )
Crude oil and condensate |  | — |  |  | (854 | )
Gain (loss) on derivative instruments |  | 88,730 |  |  | (15,262 | )
|  | $ | 88,730 |  |  | $ | (108,993 | )
Non-cash gain (loss) on derivative instruments |  |  |  |
Gain (loss) on derivative instruments |  | (61,426 | ) |  | 12,933 |
|  | $ | 27,304 |  |  | $ | (96,060 | )

Brokered Natural Gas Revenue and Cost

|  | Six Months Ended June 30, |  | Variance |  | Price and Volume Variances (In thousands)
|  | 2015 |  | 2014 |  | Amount |  | Percent |
Brokered Natural Gas Sales |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sales price ($/Mcf) |  | $ | 3.07 |  |  | $ | 4.92 |  |  | $ | (1.85 | ) |  | (38 | )% |  | $ | (5,213 | )
Volume brokered (Mmcf) |  | x | 2,818 |  |  | x | 4,328 |  |  | (1,510 | ) |  | (35 | )% |  | (7,440 | )
Brokered natural gas (In thousands) |  | $ | 8,640 |  |  | $ | 21,293 |  |  |  |  |  |  | $ | (12,653 | )
Brokered Natural Gas Purchases |  |  |  |  |  |  |  |  |  |  |  |
Purchase price ($/Mcf) |  | $ | 2.35 |  |  | $ | 4.36 |  |  | $ | (2.01 | ) |  | (46 | )% |  | $ | 5,664 |
Volume brokered (Mmcf) |  | x | 2,818 |  |  | x | 4,328 |  |  | (1,510 | ) |  | (35 | )% |  | 6,603 |
Brokered natural gas (In thousands) |  | $ | 6,624 |  |  | $ | 18,891 |  |  |  |  |  |  |  |  | $ | 12,267 |
Brokered natural gas margin (In thousands) |  | $ | 2,016 |  |  | $ | 2,402 |  |  |  |  |  |  |  |  | $ | (386 | )

The $0.4 million decrease in brokered natural gas margin is a result of lower brokered volumes partially offset by a decrease in purchase price that outpaced the decrease in sales price.
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Operating and Other Expenses

|  | Six Months Ended June 30, |  | Variance
(In thousands) |  | 2015 |  | 2014 |  | Amount |  | Percent
Operating and Other Expenses |  |  |  |  |  |  |  |  |  |  |  |
Direct operations |  | $ | 72,129 |  |  | $ | 71,439 |  |  | $ | 690 |  |  | 1 | %
Transportation and gathering |  | 219,531 |  |  | 161,741 |  |  | 57,790 |  |  | 36 | %
Brokered natural gas |  | 6,624 |  |  | 18,891 |  |  | (12,267 | ) |  | (65 | )%
Taxes other than income |  | 22,891 |  |  | 25,860 |  |  | (2,969 | ) |  | (11 | )%
Exploration |  | 14,030 |  |  | 11,150 |  |  | 2,880 |  |  | 26 | %
Depreciation, depletion and amortization |  | 328,009 |  |  | 304,981 |  |  | 23,028 |  |  | 8 | %
General and administrative |  | 42,507 |  |  | 41,763 |  |  | 744 |  |  | 2 | %
|  | $ | 705,721 |  |  | $ | 635,825 |  |  | $ | 69,896 |  |  | 11 | %
Earnings (loss) on equity method investments |  | $ | 2,933 |  |  | $ | 756 |  |  | $ | 2,177 |  |  | 288 | %
Gain (loss) on sale of assets |  | 59 |  |  | (2,781 | ) |  | 2,840 |  |  | 102 | %
Interest expense |  | 47,734 |  |  | 32,891 |  |  | 14,843 |  |  | 45 | %
Income tax expense |  | 7,852 |  |  | 146,798 |  |  | (138,946 | ) |  | (95 | )%

Total costs and expenses from operations increase d by $69.9 million, or 11%, in the first six months of 2015 compared to the same period of 2014. The primary reasons for this fluctuation are as follows:

• | Direct operations increase d $0.7 million largely due to higher operating costs as a result of higher production and production costs associated with the south Texas asset acquisitions in the fourth quarter of 2014. These cost increases were partially offset by cost reductions from suppliers, improved operational efficiencies and lower workover costs in 2015 compared to 2014.

• | Transportation and gathering increase d $57.8 million due to higher throughput as a result of higher Marcellus Shale production, higher transportation rates and the commencement of various transportation and gathering agreements in the Marcellus Shale during 2014.

• | Brokered natural gas decrease d $12.3 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

• | Taxes other than income decrease d $3.0 million due to $1.8 million lower production taxes resulting from lower oil prices, partially offset by higher oil production in south Texas and $0.9 million lower drilling impact fees associated with our Marcellus Shale drilling activities due to lower natural gas prices.

• | Exploration expense increase d $2.9 million as a result of a $5.2 million charge related to the release of certain drilling rig contracts in south Texas, partially offset by lower exploratory dry hole costs of $2.1 million.

• | Depreciation, depletion and amortization increase d $23.0 million, of which $72.0 million was due to higher equivalent production volumes, partially offset by $54.8 million due to a lower DD&A rate of $0.99 per Mcfe for the first six months of 2015 compared to $1.16 per Mcfe for the first six months of 2014. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our Marcellus Shale drilling program and the impairment charge recorded in the fourth quarter of 2014 associated with higher DD&A rate properties. In addition, amortization of unproved properties increased $4.0 million as a result of ongoing evaluation of our unproved properties and undeveloped leasehold acquisitions during the year and accretion expense increased $1.3 million.

• | General and administrative increase d $0.7 million due to higher stock-based compensation expense of $5.1 million primarily due to an $8.8 million increase associated with the mark-to-market of our liability-based performance awards and the change in liability associated with in our common stock held in the deferred compensation plan, partially offset by $3.2 million of lower expense associated with our supplemental employee incentive plan due to the change in fair value associated with the likelihood of our stock price achieving the

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trigger stock price specified in the plan and $1.7 million of lower employee-related costs. The remaining increases and decreases in other expenses were not individually significant.
Earnings (loss) on equity method investments
The $2.2 million increase in equity method investments is the result of increased activity in 2015 compared to 2014.
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 certain of our proved oil and gas properties in Oklahoma. There was no material gain (loss) on sale of assets in the first six months of 2015.
Interest Expense
Interest expense increase d $14.8 million due to $16.7 million of higher interest expense associated with our private placement in September 2014 of $925 million aggregate principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 3.65% and higher commitment fees on the unused portion of our revolving credit facility of $1.0 million. These increases were partially offset by a decrease in interest expense of $3.1 million associated with our revolving credit facility due to a decrease in weighted-average borrowings based on daily balances of approximately $272.0 million compared to approximately $565.2 million during the first six months of 2015 and 2014, respectively, partially offset by a slightly higher weighted-average effective interest rate of approximately 2.3% during 2015 compared to approximately 2.2% in 2014.
Income Tax Expense
Income tax expense decrease d $138.9 million due to lower pretax income and a lower effective tax rate. The effective tax rate for the first six months of 2015 and 2014 was 38.1% and 39.4%, respectively. The decrease in the effective tax rate was primarily due to a change in our effective state income tax rates based on updated state apportionment factors in states in which we operate. The decrease in our state apportionment factors was primarily driven by a shift in the sourcing of revenues based on the location of customers to whom we ultimately sell our natural gas in the northeast United States.
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.
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 provide only 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.
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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, 2015, we had the following outstanding commodity derivatives:

|  |  |  |  |  |  | Collars |  | Swaps |  | Estimated Fair Value Asset (Liability) (In thousands)
|  |  |  |  |  |  | Floor |  | Ceiling |  |  |
Type of Contract |  | Volume |  | Contract Period |  | Range |  | Weighted- Average |  | Range |  | Weighted- Average |  | Weighted- Average |
Natural gas |  | 35.7 |  | Bcf |  | Jul. 2015 - Dec. 2015 |  | $3.86 - $3.91 |  | $ | 3.87 |  |  | $4.27 - $4.43 |  | $ | 4.35 |  |  |  |  |  | $ | 32,359 |
Natural gas |  | 35.7 |  | Bcf |  | Jul. 2015 - Dec. 2015 |  |  |  |  |  |  |  |  |  |  |  | $ | 3.92 |  |  | 35,860 |
Natural gas |  | 17.9 |  | Bcf |  | Jul. 2015 - Oct. 2015 |  |  |  |  |  |  |  |  |  |  |  | $ | 3.36 |  |  | 8,008 |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 76,227 |

In the table above, natural gas prices are stated per Mcf.
The amounts set forth in the table above represent our derivative position at June 30, 2015 and exclude the impact of non-performance risk. Non-performance risk is considered in the fair value of our derivative instruments that are recorded in our Condensed Consolidated Financial Statements and 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 2015, natural gas collars with floor prices ranging from $3.86 to $3.91 per Mcf and ceiling prices ranging from $4.27 to $4.43 per Mcf covered 35.2 Bcf, or 12%, of natural gas production at an average price of $3.87 per Mcf. Natural gas swaps covered 53.7 Mcf, or 18%, of natural gas production at an average price of $3.85 per Mcf.
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.
Our counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.
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.
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 amount reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents approximates fair value due to the short-term maturities of these instruments.
The fair value of 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.
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We use available market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and estimated fair values of debt are as follows:

|  | June 30, 2015 |  | December 31, 2014
(In thousands) |  | Carrying Amount |  | Estimated Fair Value |  | Carrying Amount |  | Estimated Fair Value
Debt |  | $ | 1,995,000 |  |  | $ | 2,028,913 |  |  | $ | 1,752,000 |  |  | $ | 1,850,867 |

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 2015 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, 2014.
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. The maximum number of remaining shares that may be purchased under the plan as of June 30, 2015 was 10.1 million.
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ITEM 6. Exhibits

Exhibit Number |  | Description
15.1 |  | Awareness letter of PricewaterhouseCoopers LLP.
31.1 |  | 302 Certification — Chairman, President and Chief Executive Officer.
31.2 |  | 302 Certification — Executive Vice President and Chief Financial Officer.
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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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 24, 2015 | By: | /s/ DAN O. DINGES
|  | Dan O. Dinges
|  | Chairman, President and Chief Executive Officer
|  | (Principal Executive Officer)
July 24, 2015 | By: | /s/ SCOTT C. SCHROEDER
|  | Scott C. Schroeder
|  | Executive Vice President and Chief Financial Officer
|  | (Principal Financial Officer)
July 24, 2015 | By: | /s/ TODD M. ROEMER
|  | Todd M. Roemer
|  | Controller
|  | (Principal Accounting Officer)

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