10-Q 1 cog-03312017x10q.htm 10-Q Document

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 March 31, 2017
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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ý
 
Accelerated filer o
 
 
 
Non-accelerated filer o
 
Smaller reporting company o
 
 
 
(Do not check if a smaller reporting company)
 
Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
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 April 24, 2017, there were 465,523,385 shares of Common Stock, Par Value $.10 Per Share, outstanding.



CABOT OIL & GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2


PART I. FINANCIAL INFORMATION
ITEM 1.    Financial Statements
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In thousands, except share amounts)
 
March 31,
2017
 
December 31,
2016
ASSETS
 
 

 
 

Current assets
 
 

 
 

Cash and cash equivalents
 
$
537,485

 
$
498,542

Accounts receivable, net
 
192,783

 
191,045

Income taxes receivable
 
1,601

 
10,298

Inventories
 
12,095

 
13,304

Other current assets
 
4,349

 
2,692

Total current assets
 
748,313

 
715,881

Properties and equipment, net (Successful efforts method)
 
4,328,360

 
4,250,125

Equity method investments
 
135,983

 
129,524

Other assets
 
31,732

 
27,039

 
 
$
5,244,388

 
$
5,122,569

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 

 
 

Current liabilities
 
 

 
 

Accounts payable
 
$
183,305

 
$
168,411

Accrued liabilities
 
14,299

 
21,492

Interest payable
 
12,262

 
27,650

Income taxes payable
 
1,837

 

Derivative instruments
 
12,692

 
40,259

Total current liabilities
 
224,395

 
257,812

Long-term debt, net
 
1,520,870

 
1,520,530

Deferred income taxes
 
590,575

 
579,447

Asset retirement obligations
 
133,526

 
131,733

Postretirement benefits
 
37,042

 
36,259

Other liabilities
 
30,801

 
29,121

Total liabilities
 
2,537,209

 
2,554,902

 
 
 
 
 
Commitments and contingencies
 

 

 
 
 
 
 
Stockholders' equity
 
 

 
 

Common stock:
 
 

 
 

Authorized — 960,000,000 shares of $0.10 par value in 2017 and 2016, respectively
 
 

 
 

Issued — 475,414,452 shares and 475,042,692 shares in 2017 and 2016, respectively
 
47,541

 
47,504

Additional paid-in capital
 
1,728,182

 
1,727,310

Retained earnings
 
1,237,289

 
1,098,703

Accumulated other comprehensive income
 
1,002

 
985

Less treasury stock, at cost:
 
 

 
 

9,892,680 shares in 2017 and 2016, respectively
 
(306,835
)
 
(306,835
)
Total stockholders' equity
 
2,707,179

 
2,567,667

 
 
$
5,244,388

 
$
5,122,569

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

3


CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
 
 
Three Months Ended 
 March 31,
(In thousands, except per share amounts)
 
2017
 
2016
OPERATING REVENUES
 
 

 
 

   Natural gas
 
$
433,442

 
$
227,578

   Crude oil and condensate
 
42,990

 
30,676

   Gain on derivative instruments
 
33,384

 
18,994

   Brokered natural gas
 
4,695

 
3,180

   Other
 
3,332

 
1,513

 
 
517,843

 
281,941

OPERATING EXPENSES
 
 

 
 

   Direct operations
 
24,641

 
26,035

   Transportation and gathering
 
123,474

 
109,652

   Brokered natural gas
 
4,046

 
2,566

   Taxes other than income
 
9,058

 
5,994

   Exploration
 
6,198

 
6,383

   Depreciation, depletion and amortization
 
135,100

 
161,887

   General and administrative
 
23,700

 
27,873

 
 
326,217

 
340,390

Earnings (loss) on equity method investments
 
(1,283
)
 
2,009

Gain (loss) on sale of assets
 
(223
)
 
1,354

INCOME (LOSS) FROM OPERATIONS
 
190,120

 
(55,086
)
Interest expense
 
20,771

 
24,375

Other expense
 
424

 
503

Income (loss) before income taxes
 
168,925

 
(79,964
)
Income tax expense (benefit)
 
63,205

 
(28,770
)
NET INCOME (LOSS)
 
$
105,720

 
$
(51,194
)
 
 
 
 
 
Earnings (loss) per share
 
 

 
 

Basic
 
$
0.23

 
$
(0.12
)
Diluted
 
$
0.23

 
$
(0.12
)
 
 
 
 
 
Weighted-average common shares outstanding
 
 

 
 

Basic
 
465,348

 
431,841

Diluted
 
466,888

 
431,841

 
 
 
 
 
Dividends per common share
 
$
0.02

 
$
0.02

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

4


CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
 
 
Three Months Ended 
 March 31,
(In thousands)
 
2017
 
2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 

 
 

  Net income (loss)
 
$
105,720

 
$
(51,194
)
  Adjustments to reconcile net income (loss) to cash provided by operating activities:
 
 

 
 

Depreciation, depletion and amortization
 
135,100

 
161,887

Deferred income tax expense (benefit)
 
53,289

 
(28,973
)
(Gain) loss on sale of assets
 
223

 
(1,354
)
Exploratory dry hole cost
 
2,842

 

Gain on derivative instruments
 
(33,384
)
 
(18,994
)
Net cash paid in settlement of derivative instruments
 
(1,524
)
 

(Earnings) loss on equity method investments
 
1,283

 
(2,009
)
Amortization of debt issuance costs
 
1,189

 
1,191

Stock-based compensation and other
 
8,283

 
10,606

  Changes in assets and liabilities:
 
 

 
 

Accounts receivable, net
 
(1,738
)
 
19,358

Income taxes
 
10,534

 
233

Inventories
 
1,209

 
1,101

Other current assets
 
1,170

 
1,300

Accounts payable and accrued liabilities
 
151

 
(9,610
)
Interest payable
 
(15,388
)
 
(16,660
)
Other assets and liabilities
 
419

 
230

Net cash provided by operating activities
 
269,378

 
67,112

CASH FLOWS FROM INVESTING ACTIVITIES
 
 

 
 

Capital expenditures
 
(208,384
)
 
(92,237
)
Proceeds from sale of assets
 
374

 
49,828

Investment in equity method investments
 
(7,742
)
 
(11,652
)
Net cash used in investing activities
 
(215,752
)
 
(54,061
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 

 
 

Borrowings from debt
 

 
90,000

Repayments of debt
 

 
(503,000
)
Sale of common stock, net
 

 
995,278

Dividends paid
 
(9,306
)
 
(8,282
)
Tax withholdings on stock award vestings
 
(5,414
)
 
(5,022
)
Capitalized debt issuance costs
 

 
(3,223
)
Other
 
37

 

Net cash provided by (used in) financing activities
 
(14,683
)
 
565,751

Net increase in cash and cash equivalents
 
38,943

 
578,802

Cash and cash equivalents, beginning of period
 
498,542

 
514

Cash and cash equivalents, end of period
 
$
537,485

 
$
579,316

 
 
 
 
 
Supplemental non-cash investing transactions:
 
 
 
 
Change in accrued capital costs
 
$
6,695

 
$
(549
)
The accompanying notes are an integral part of these condensed consolidated financial statements.

5


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, 2016 (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.
Recently Adopted Accounting Pronouncements
Stock-Based Compensation. In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-09, Improvements to Employee Share-Based Payment Accounting, as an amendment to Accounting Standards Codification (ASC) Topic 718. The areas for simplification in this update involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, forfeitures, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for interim and annual periods beginning after December 15, 2016. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method.
The Company adopted this guidance effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits resulted in a cumulative-effect adjustment of $42.2 million, which increased retained earnings and decreased net deferred tax liabilities by the same amount as of the beginning of 2017. Effective January 1, 2017, cash paid by the Company when directly withholding shares from employee awards for tax-withholding purposes will be classified as a financing activity. This change has been recognized retrospectively beginning January 1, 2015. Prior periods have been adjusted as follows:
 
 
Net Cash Provided by Operating Activities
 
Net Cash Provided by Financing Activities
(In thousands)
 
As Reported
 
As Adjusted
 
As Reported
 
As Adjusted
Year ended December 31, 2015
 
$
740,737

 
$
749,598

 
$
232,157

 
$
223,296

Three months ended March 31, 2016
 
62,090

 
67,112

 
570,773

 
565,751

Six months ended June 30, 2016
 
147,244

 
152,290

 
497,474

 
492,428

Nine months ended September 30, 2016
 
252,649

 
257,705

 
468,171

 
463,115

Year ended December 31, 2016
 
392,377

 
398,441

 
458,869

 
453,805

The remaining provisions of this amendment did not have a material effect on the Company's financial position or results of operations.
Accounting Changes and Error Corrections. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a description of the effect of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance is effective immediately.
Retirement Benefits. In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715). The amendments in this update require that an employer report the service cost component of postretirement benefits in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost

6


component and outside a subtotal of income from operations. The amendments in this update also allow only the service cost component to be eligible for capitalization when applicable. The guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. The amendments in this update should be applied retrospectively for the presentation of the service cost component and the other components of net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic benefit cost in assets. The Company elected to adopt this guidance effective January 1, 2017. The reclassification of interest and amortization of prior service cost resulted in an increase in operating income and an increase in other expense (non-operating expense) of $1.6 million and $1.4 million for the years ended December 31, 2016 and 2015 and $0.5 million for the three months ended March 31, 2016, respectively.
Recently Issued Accounting Pronouncements
Financial Instruments. In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall, as an amendment to ASC Subtopic 825-10. The amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Among other items, this update will simplify the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment. When a qualitative assessment indicates that impairment exists, an entity is required to measure the investment at fair value. This impairment assessment reduces the complexity of the other-than-temporary impairment guidance that entities follow currently. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption of this amendment is not permitted. The adoption of this guidance will change the methodology that the Company uses to evaluate its equity method investments for impairment. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operation or cash flows.
Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, as a new Topic, ASC Topic 842. The new lease guidance supersedes Topic 840. The core principle of the guidance is that a company should recognize the assets and liabilities that arise from leases. This ASU does not apply to leases to explore for or use minerals, oil, natural gas and similar nonregenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. The guidance is effective for interim and annual periods beginning after December 15, 2018. This ASU is to be adopted using a modified retrospective approach. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, ASC 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 August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferred the effective date of ASU No. 2014-09 by one year, making the new standard effective for interim and annual periods beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption.
Additionally, in March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-scope improvements and practical expedients, which addresses narrow-scope improvements to the guidance on collectibility, non-cash consideration, and completed contracts at transition. Additionally, the amendments in this update provide a practical expedient for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which clarifies the guidance or corrects unintended application of guidance. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows.
Statement of Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted, provided that all of the amendments are adopted in the same period. This ASU

7


must be adopted using a retrospective transition method. The Company is currently evaluating the effect that adopting this guidance will have on its presentation of cash flows. Adopting the guidance is expected to have no effect on the Company's financial position or results of operations.
2. Properties and Equipment, Net
Properties and equipment, net are comprised of the following:
(In thousands)
 
March 31,
2017
 
December 31,
2016
Proved oil and gas properties
 
$
7,589,749

 
$
7,437,604

Unproved oil and gas properties
 
296,279

 
260,543

Gathering and pipeline systems
 
188,466

 
187,846

Land, building and other equipment
 
85,257

 
84,462

 
 
8,159,751

 
7,970,455

Accumulated depreciation, depletion and amortization
 
(3,831,391
)
 
(3,720,330
)
 
 
$
4,328,360

 
$
4,250,125

At March 31, 2017, the Company did not have any projects that had exploratory well costs capitalized for a period of greater than one year after drilling.
In February 2016, the Company completed the divestiture of certain proved and unproved oil and gas properties in east Texas for approximately $56.4 million and recognized a $0.5 million gain on sale of assets.
3. Equity Method Investments
The Company holds a 25% equity interest in Constitution Pipeline Company, LLC (Constitution) and a 20% equity interest in Meade Pipeline Co LLC (Meade). Activity related to these equity method investments is as follows:
 
 
Constitution
 
Meade
 
Total
 
 
Three Months Ended March 31,
 
Three Months Ended March 31,
 
Three Months Ended March 31,
(In thousands)
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Balance at beginning of period
 
$
96,850

 
$
90,345

 
$
32,674

 
$
13,172

 
$
129,524

 
$
103,517

Contributions
 
1,125

 
6,250

 
6,617

 
5,402

 
7,742

 
11,652

Earnings (loss) on equity method investments
 
(1,282
)
 
2,011

 
(1
)
 
(2
)
 
(1,283
)
 
2,009

Balance at end of period
 
$
96,693

 
$
98,606

 
$
39,290

 
$
18,572

 
$
135,983

 
$
117,178

During 2017, the Company expects to contribute approximately $70.0 million to its equity method investments. For further information regarding the Company’s equity method investments, refer to Note 4 of the Notes to the Consolidated Financial Statements in the Form 10-K.
Constitution
On April 22, 2016, Constitution announced that the New York State Department of Environmental Conservation (NYSDEC) denied Constitution's application for a Section 401 Water Quality Certification (Certification) for the New York State portion of its proposed 124-mile route. During second quarter of 2016, Constitution filed legal actions in the U.S. Court of Appeals for the Second Circuit and the U.S. District Court for the Northern District of New York challenging the legality and appropriateness of the NYSDEC’s decision. Both courts have granted Constitution's motions to expedite the schedules for the legal actions. On March 16, 2017, the U.S. District Court for the Northern District of New York issued an order ruling, without prejudice, that it lacked subject matter jurisdiction to hear Constitution’s complaint. The U.S. Court of Appeals has heard oral arguments but has not yet ruled on Constitution's appeal.
Constitution stated that it remains committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC’s decision. In light of the denial of the Certification and ongoing litigation, Constitution has revised its target in-service date to the second half of 2018, assuming that the U.S. Court of Appeals challenge process is satisfactorily and promptly concluded.

8


In light of the NYSDEC’s denial and resulting litigation, the Company evaluated its investment in Constitution for other-than-temporary impairment (OTTI) and, as of March 31, 2017, does not believe there is an indication of an OTTI. The Company’s evaluation considered various factors, including but not limited to prior Federal Energy Regulatory Commission (FERC) approval and the related economic viability of the project, the pending appeal filed by Constitution and the other members’ commitment to the project. To the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is no longer viable or elects to not go forward as legal and regulatory actions progress, the Company will reevaluate the facts and circumstances relative to its conclusions with respect to OTTI. In the event that facts and circumstances change, the Company may be required to recognize an impairment charge up to its investment value at such time, net of any cash and working capital held by Constitution. The Company will continue to monitor the carrying value of its investment as required.
At this time, the Company remains committed to funding the project in an amount in proportion to its ownership interest for the development and construction of the new pipeline. The Company's total contributions for this project are expected to be approximately $240.0 million. As of March 31, 2017, the Company has made contributions of $89.7 million since inception of the project.
4. Debt and Credit Agreements
The Company’s debt and credit agreements consisted of the following:
(In thousands)
 
March 31,
2017
 
December 31,
2016
6.51% weighted-average senior notes
 
$
361,000

 
$
361,000

9.78% senior notes
 
67,000

 
67,000

5.58% weighted-average senior notes
 
175,000

 
175,000

3.65% weighted-average senior notes
 
925,000

 
925,000

 
 
1,528,000

 
1,528,000

Unamortized debt issuance costs
 
(7,130
)
 
(7,470
)
 
 
$
1,520,870

 
$
1,520,530

The borrowing base under the terms of the Company's revolving credit facility is redetermined annually in April. In addition, either the Company or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. Effective April 11, 2017, the borrowing base and available commitments were reaffirmed at $3.2 billion and $1.7 billion, respectively.
At March 31, 2017, the Company was in compliance with all restrictive financial covenants for both its revolving credit facility and senior notes. As of March 31, 2017, based on the Company's asset coverage and leverage ratios, there were no interest rate adjustments required for the Company's senior notes.
At March 31, 2017, the Company had no borrowings outstanding under its revolving credit facility and had unused commitments of $1.7 billion. The Company’s weighted-average effective interest rate for the revolving credit facility for the three months ended March 31, 2016 was approximately 2.3%.
5. Derivative Instruments and Hedging Activities
As of March 31, 2017, the Company had the following outstanding commodity derivatives:
 
 
 
 
 
 
 
Collars
 
 
 
Basis Swaps
 
 
 
 
 
 
 
Floor
 
Ceiling
 
Swaps
 
Type of Contract
 
Volume
 
Contract Period
 
Range
 
Weighted-Average
 
Range
 
Weighted-Average
 
Weighted-Average
 
Weighted-Average
Natural gas
 
26.7

Bcf
 
Apr. 2017 - Dec. 2017
 
 
 
 
 
 
 
 
 
$
3.12

 
 
Natural gas
 
13.4

Bcf
 
Apr. 2017 - Dec. 2017
 
 
 
 
 
 
 
 
 
$
3.46

 
 
Natural gas
 
26.7

Bcf
 
Apr. 2017 - Dec. 2017
 
$

 
$
3.09

 
$3.42-$3.45
 
$
3.43

 
 
 
 
Natural gas
 
21.3

Bcf
 
Jan. 2018 - Dec. 2019
 
 
 
 
 
 
 
 
 
 
 
$
0.42

Crude oil
 
1.4

Mmbbl
 
Apr. 2017 - Dec. 2017
 
$

 
$
50.00

 
$56.25-$56.50
 
$
56.39

 
 
 
 
In the table above, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.

9


Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet
 
 
 
 
Derivative Assets
 
Derivative Liabilities
(In thousands)
 
Balance Sheet Location
 
March 31,
2017
 
December 31,
2016
 
March 31,
2017
 
December 31,
2016
Commodity contracts
 
Other current assets
 
$
2,826

 
$

 
$

 
$

Commodity contracts
 
Other assets (non-current)
 
7,506

 
2,991

 

 

Commodity contracts
 
Derivative instruments (current)
 

 

 
12,692

 
40,259

 
 
 
 
$
10,332

 
$
2,991

 
$
12,692

 
$
40,259

Offsetting of Derivative Assets and Liabilities in the Condensed Consolidated Balance Sheet
(In thousands)
 
March 31,
2017
 
December 31,
2016
Derivative assets
 
 

 
 

Gross amounts of recognized assets
 
$
12,354

 
$
2,991

Gross amounts offset in the statement of financial position
 
(2,022
)
 

Net amounts of assets presented in the statement of financial position
 
10,332

 
2,991

Gross amounts of financial instruments not offset in the statement of financial position
 
51

 

Net amount
 
$
10,383

 
$
2,991

 
 
 
 
 
Derivative liabilities
 
 

 
 

Gross amounts of recognized liabilities
 
$
14,714

 
$
40,259

Gross amounts offset in the statement of financial position
 
(2,022
)
 

Net amounts of liabilities presented in the statement of financial position
 
12,692

 
40,259

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

 
757

Net amount
 
$
12,692

 
$
41,016

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations
 
 
Three Months Ended 
 March 31,
(In thousands)
 
2017
 
2016
Cash received (paid) on settlement of derivative instruments
 
 

 
 

Gain (loss) on derivative instruments
 
$
(1,524
)
 
$

Non-cash gain (loss) on derivative instruments
 
 

 
 

Gain (loss) on derivative instruments
 
34,908

 
18,994

 
 
$
33,384

 
$
18,994

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.

10


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  
 March 31, 2017
Assets
 
 

 
 

 
 

 
 

Deferred compensation plan
 
$
13,566

 
$

 
$

 
$
13,566

Derivative instruments
 

 

 
10,332

 
10,332

     Total assets
 
$
13,566

 
$

 
$
10,332

 
$
23,898

Liabilities
 
 
 
 

 
 

 
 

Deferred compensation plan
 
$
25,420

 
$

 
$

 
$
25,420

Derivative instruments
 

 
7,429

 
5,263

 
12,692

     Total liabilities
 
$
25,420

 
$
7,429

 
$
5,263

 
$
38,112

(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, 2016
Assets
 
 

 
 

 
 

 
 

Deferred compensation plan
 
$
12,587

 
$

 
$

 
$
12,587

Derivative instruments
 

 

 
2,991

 
2,991

     Total assets
 
$
12,587

 
$

 
$
2,991

 
$
15,578

Liabilities
 
 
 
 

 
 

 
 

Deferred compensation plan
 
$
24,169

 
$

 
$

 
$
24,169

Derivative instruments
 

 
21,400

 
18,859

 
40,259

     Total liabilities
 
$
24,169

 
$
21,400

 
$
18,859

 
$
64,428

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

11


The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
 
 
Three Months Ended 
 March 31,
(In thousands)
 
2017
 
2016
Balance at beginning of period
 
$
(15,868
)
 
$

Total gain (loss) included in earnings
 
21,918

 
3,647

Settlement (gain) loss
 
(981
)
 

Transfers in and/or out of level 3
 

 

Balance at end of period
 
$
5,069

 
$
3,647

 
 
 
 
 
Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period
 
$
20,937

 
$
3,647

There were no transfers between Level 1 and Level 2 fair value measurements for the three months ended March 31, 2017 and 2016.
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. The Company recorded an impairment charge related to certain oil and gas properties and other assets during the year ended December 31, 2016. Refer to Note 3 of the Notes to the Consolidated Financial Statements in the Form 10-K for additional disclosures related to fair value associated with the impaired assets. As none of the Company’s other non-financial assets and liabilities were measured at fair value as of March 31, 2017 and December 31, 2016, additional disclosures were not required.
The estimated fair value of the Company’s asset retirement obligation at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.
Fair 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. Cash and cash equivalents are classified as Level 1 in the fair value hierarchy and the remaining financial instruments are classified as Level 2.
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 senior 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 senior 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 amount and fair value of debt is as follows:
 
 
March 31, 2017
 
December 31, 2016
(In thousands)
 
Carrying
Amount
 
Estimated Fair
Value
 
Carrying
Amount
 
Estimated Fair
Value
Debt
 
$
1,520,870

 
$
1,500,879

 
$
1,520,530

 
$
1,463,643


12


7. Asset Retirement Obligations
Activity related to the Company’s asset retirement obligations is as follows:
(In thousands)
 
Three Months Ended 
 March 31, 2017
Balance at beginning of period
 
$
133,733

Liabilities incurred
 
702

Liabilities settled
 
(696
)
Accretion expense
 
1,787

Balance at end of period
 
$
135,526

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,” “Lease Commitments” and “Hydraulic Fracturing Services 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. Capital Stock
On February 22, 2016, the Company entered into an underwriting agreement, pursuant to which the Company sold an aggregate of 44.0 million shares of common stock at a price to the Company of $19.675 per share. On February 26, 2016, the Company received $865.7 million in net proceeds, after deducting underwriting discounts and commissions. On March 2, 2016, the Company sold an additional 6.6 million shares of common stock as a result of the exercise of the underwriters’ option to purchase additional shares and received $129.9 million in net proceeds. These net proceeds were used for general corporate purposes, including repaying indebtedness under the Company’s revolving credit facility and repurchasing certain of the Company's senior notes.
10. Stock-based Compensation
General
From time to time the Company grants certain stock-based compensation awards, including restricted stock awards, restricted stock units and performance share awards. Stock-based compensation expense associated with these awards was $8.3 million and $10.6 million in the first quarter of 2017 and 2016, respectively. Stock-based compensation expense is included in general and administrative expense in the Condensed Consolidated Statement of Operations.
As described in Note 1 to the Condensed Consolidated Financial Statements, effective January 1, 2017, the Company adopted ASU No. 2016-09, which requires that excess tax benefits and tax deficiencies on stock-based compensation be recorded in the income statement. During the first three months of 2017, the Company recorded an increase to tax expense of

13


$0.8 million in the Condensed Consolidated Statement of Operations as a result of book compensation cost for employee stock-based compensation exceeding the federal and state tax deductions for awards that vested during the period.
Prior to the adoption of ASU No. 2016-09, windfall tax benefits were recorded in additional paid in capital in the Condensed Consolidated Balance Sheet and tax shortfalls reduced additional paid in capital to the extent they offset previously recorded windfall tax benefits. During the first three months of 2016, the Company recorded a tax shortfall of $2.0 million, resulting in a reduction of the Company's windfall tax benefit that was recorded in additional paid in capital in the Condensed Consolidated Balance Sheet. The tax shortfall was a result of book compensation cost for employee stock-based compensation exceeding the federal and state tax deductions for certain awards that vested during the period.
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 Units
During the first three months of 2017, 46,618 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date value of $22.57 per unit. 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 during the first three months of 2017 commenced on January 1, 2017 and ends on December 31, 2019. The Company used an annual forfeiture rate assumption ranging from 0% to 6% for purposes of recognizing stock-based compensation expense for its performance share awards.
Performance Share Awards Based on Internal Performance Metrics
The fair value of performance share award grants based on internal performance metrics is based on the closing stock price on the grant date. Each performance share award represents the right to receive up to 100% of the award in shares of common stock. Based on the Company’s probability assessment at March 31, 2017, it is considered probable that the criteria for all performance awards based on internal metrics awards will be met.
Employee Performance Share Awards. During the first three months of 2017, 406,460 Employee Performance Share Awards were granted at a grant date value of $22.60 per share. 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.
Hybrid Performance Share Awards. During the first three months of 2017, 272,920 Hybrid Performance Share Awards were granted at a grant date value of $22.60 per share. The 2017 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.
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 three months of 2017, 409,380 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.

14


The following assumptions were used to determine the grant date fair value of the equity component (February 22, 2017) and the period-end fair value of the liability component of the TSR Performance Share Awards:
 
 
Grant Date
 
March 31, 2017
Fair value per performance share award
 
$
19.85

 
$7.35 - $14.16
Assumptions:
 
 

 
 
     Stock price volatility
 
37.8
%
 
36.0% - 43.3%
     Risk free rate of return
 
1.4
%
 
1.0% - 1.4%
11. 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. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.
The following is a calculation of basic and diluted weighted-average shares outstanding:
 
 
Three Months Ended 
 March 31,
(In thousands)
 
2017
 
2016
Weighted-average shares - basic
 
465,348

 
431,841

Dilution effect of stock appreciation rights and stock awards at end of period
 
1,540

 

Weighted-average shares - diluted
 
466,888

 
431,841

The following is a calculation of weighted-average shares excluded from diluted EPS due to the anti-dilutive effect:
 
 
Three Months Ended 
 March 31,
(In thousands)
 
2017
 
2016
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect due to net loss
 

 
700

Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method
 
477

 
28

Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect
 
477

 
728



15


12. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
(In thousands)
 
March 31,
2017
 
December 31,
2016
Accounts receivable, net
 
 

 
 

Trade accounts
 
$
189,244

 
$
185,594

Joint interest accounts
 
1,448

 
1,359

Other accounts
 
3,334

 
5,335

 
 
194,026

 
192,288

Allowance for doubtful accounts
 
(1,243
)
 
(1,243
)
 
 
$
192,783

 
$
191,045

 
 
 
 
 
Inventories
 
 

 
 

Tubular goods and well equipment
 
$
10,335

 
$
11,005

Natural gas in storage
 
1,760

 
2,299

 
 
$
12,095

 
$
13,304

 
 
 
 
 
Other current assets
 
 

 
 

Prepaid balances and other
 
$
1,523

 
$
2,692

Derivative instruments
 
2,826

 

 
 
$
4,349

 
$
2,692

 
 
 
 
 
Other assets
 
 

 
 

Deferred compensation plan
 
$
13,566

 
$
12,587

Debt issuance costs
 
10,554

 
11,403

Derivative instruments
 
7,506

 
2,991

Other accounts
 
106

 
58

 
 
$
31,732

 
$
27,039

 
 
 
 
 
Accounts payable
 
 

 
 

Trade accounts
 
$
27,881

 
$
27,355

Natural gas purchases
 
903

 
2,231

Royalty and other owners
 
92,562

 
85,449

Accrued capital costs
 
41,342

 
34,647

Taxes other than income
 
17,780

 
13,827

Other accounts
 
2,837

 
4,902

 
 
$
183,305

 
$
168,411

 
 
 
 
 
Accrued liabilities
 
 

 
 

Employee benefits
 
$
6,746

 
$
14,153

Taxes other than income
 
4,025

 
3,829

Asset retirement obligations
 
2,000

 
2,000

Other accounts
 
1,528

 
1,510

 
 
$
14,299

 
$
21,492

 
 
 
 
 
Other liabilities
 
 

 
 

Deferred compensation plan
 
$
25,420

 
$
24,169

Other accounts
 
5,381

 
4,952

 
 
$
30,801

 
$
29,121


16


ITEM 2.     Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following review of operations for the three month periods ended March 31, 2017 and 2016 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, 2016 (Form 10-K).
OVERVIEW
Financial and Operating Overview
Financial and operating results for the three months ended March 31, 2017 compared to the three months ended March 31, 2016 are as follows:
Equivalent production increased 9.8 Bcfe, or 6%, from 160.3 Bcfe, or 1,761.9 Mmcfe per day, in 2016 to 170.1 Bcfe, or 1,889.6 Mmcfe per day, in 2017.
Natural gas production increased 10.7 Bcf, or 7%, from 153.1 Bcf in 2016 to 163.8 Bcf in 2017, as a result of drilling and completion activities in Pennsylvania.
Crude oil/condensate/NGL production decreased 0.2 Mmbbls, or 13%, from 1.2 Mmbbls in 2016 to 1.0 Mmbbls in 2017, as result of a decrease in drilling and completion activities in south Texas.
Average realized natural gas price was $2.64 per Mcf, 77% higher than the $1.49 per Mcf realized in the comparable period of the prior year.
Average realized crude oil price was $46.73 per Bbl, 69% higher than the $27.65 per Bbl realized in the comparable period of the prior year.
Drilled 21 gross wells (21.0 net) with a success rate of 95.2% compared to 10 gross wells (10.0 net) with a success rate of 100% for the comparable period of the prior year.
Completed 25 gross wells (24.0 net) in 2017 compared to 15 gross wells (15.0 net) in 2016.
Total capital expenditures were $212.2 million compared to $91.7 million in the comparable period of the prior year.
Average rig count during 2017 was approximately 2.0 rigs in the Marcellus Shale and approximately 1.0 rigs in the Eagle Ford Shale, compared to an average rig count in the Marcellus Shale of approximately 1.2 rigs and approximately 0.5 rigs in the Eagle Ford Shale in 2016.
Market Conditions and Commodity Prices
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. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions and other factors. In addition, our realized prices are further impacted by our hedging activities. As a result, we cannot accurately predict future commodity 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. Location differentials have increased in certain regions, such as in the Appalachian region, resulting in further declines in natural gas prices. We expect natural gas and crude oil prices to remain volatile. 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. 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.
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 associated with our derivative instruments, we will likely experience volatility in our earnings 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.
Commodity prices have remained volatile but have improved during 2017 compared to the fourth quarter of 2016. In the event that commodity prices significantly decline, management would test the recoverability of the carrying value of its oil and gas properties and, if necessary, record an impairment charge.

17


We believe that we are well-positioned to manage the challenges presented in a volatile commodity pricing environment, and that we can endure the continued volatility in current and future commodity prices by:
Continuing to exercise discipline in our capital program with the expectation of funding our capital expenditures with cash on hand, operating cash flows, and if required, borrowings under our revolving credit facility.
Continuing to optimize our drilling, completion and operational efficiencies, resulting in lower operating costs per unit of production.
Continuing to manage our balance sheet which provides sufficient availability under our revolving credit facility and existing cash balances to meet our capital requirements and maintain compliance with our debt covenants.
Continuing to manage price risk by strategically hedging our natural gas and crude oil production.
Outlook
Based on the expectation for higher operating cash flow due to an improvement in the commodity price outlook, we increased our budgeted capital expenditures compared to 2016. Our full year 2017 capital spending program includes approximately $775.0 million in capital expenditures related to our drilling and completion program and contributions of approximately $70.0 million to our equity method investments. All such expenditures are expected to be funded by existing cash, operating cash flow and if required, borrowings under our revolving credit facility.
In 2016, we drilled 40 gross wells (38.0 net) and completed 76 gross wells (76.0 net), of which 62 gross wells (62.0 net) were drilled but uncompleted in prior years. In 2017, we plan to drill 95 gross wells (90.0 net) and complete 95 gross wells (90.0 net), of which 51 gross wells (45.0 net) were drilled but uncompleted in prior years. In 2017, we plan to operate an average of approximately 3.0 rigs, an increase from an average of approximately 1.4 rigs in 2016. 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 expenditures accordingly.
Financial Condition
Capital Resources and Liquidity
Our primary sources of cash for the three months ended March 31, 2017 were from the sale of natural gas and crude oil production. These cash flows were primarily used to fund our capital 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.
The borrowing base under the terms of our revolving credit facility is redetermined annually in April. In addition, either we or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. Effective April 11, 2017, the borrowing base and available commitments were reaffirmed at $3.2 billion and $1.7 billion, respectively. There were no borrowings outstanding under our revolving credit facility as of March 31, 2017.
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. We believe that, with the existing cash on hand, internally generated cash flow and availability under our revolving credit facility, we have the capacity to finance our spending plans.
At March 31, 2017, we were in compliance with all restrictive financial covenants for both the revolving credit facility and senior notes. As of March 31, 2017, based on our asset coverage and leverage ratios, there were no interest rate adjustments required for our senior notes. See our Form 10-K for further discussion of our restrictive financial covenants.

18


Cash Flows
Our cash flows from operating activities, investing activities and financing activities are as follows:
 
 
Three Months Ended 
 March 31,
(In thousands)
 
2017
 
2016
Cash flows provided by operating activities
 
$
269,378

 
$
67,112

Cash flows used in investing activities
 
(215,752
)
 
(54,061
)
Cash flows provided by (used in) financing activities
 
(14,683
)
 
565,751

Net increase in cash and cash equivalents
 
$
38,943

 
$
578,802

Operating Activities.  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, primarily as a result of supply and demand for natural gas and crude oil, pipeline infrastructure constraints and seasonal influences. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures. See “Results of Operations” for a review of the impact of prices and volumes on revenues.
Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit facility, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, sales of our securities and changes in the fair value of our commodity derivative activity. From time to time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. At March 31, 2017 and December 31, 2016, we had a working capital surplus of $523.9 million and $458.1 million, respectively. We believe we have adequate liquidity and availability under our revolving credit facility to meet our working capital requirements.
Net cash provided by operating activities in the first three months of 2017 increased by $202.3 million compared to the first three months of 2016. This increase was primarily due higher operating revenues, partially offset by higher cash operating expenses. The increase in operating revenues was primarily due to an increase in realized natural gas and crude oil prices and an increase in equivalent production. Average realized natural gas and crude oil prices increased by 77% and 69%, respectively, for the first three months of 2017 compared to the first three months of 2016. Equivalent production increased by 6% for the first three months of 2017 compared to the first three months of 2016 due to higher natural gas production in the Marcellus Shale, partially offset by lower oil production in the Eagle Ford Shale.
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.
Investing Activities. Cash flows used in investing activities increased by $161.7 million for the first three months of 2017 compared to the first three months of 2016. The increase was due to $116.1 million higher capital expenditures and $49.5 million lower proceeds from the sale of assets, partially offset by $3.9 million lower capital contributions associated with our equity method investments.
Financing Activities. Cash flows provided by financing activities decreased by $580.4 million for the first three months of 2017 compared to the first three months of 2016. This decrease was primarily due to $995.3 million lower net proceeds and $1.0 million of higher dividend payments both related to the issuance of common stock in 2016, partially offset by $413.0 million of lower net repayments of debt due to the repayment of the outstanding balance on our revolving credit facility and certain of our senior notes with the proceeds from the issuance of common stock and lower capitalized debt issuance costs of $3.2 million related to the amendment of our revolving credit facility and senior notes in December 2015.

19


Capitalization
Information about our capitalization is as follows:
(Dollars in thousands)
 
March 31,
2017
 
December 31,
2016
Debt
 
$
1,520,870

 
$
1,520,530

Stockholders' equity
 
2,707,179

 
2,567,667

Total capitalization
 
$
4,228,049

 
$
4,088,197

Debt to total capitalization
 
36
%
 
37
%
Cash and cash equivalents
 
$
537,485

 
$
498,542

Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital 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:
 
 
Three Months Ended 
 March 31,
(In thousands)
 
2017
 
2016
Capital expenditures
 
 

 
 

Drilling and facilities
 
$
141,987

 
$
90,913

Leasehold acquisitions
 
67,892

 
344

Pipeline and gathering
 
618

 
269

Other
 
1,740

 
162

 
 
212,237

 
91,688

Exploration expenditures
 
6,198

 
6,383

Total
 
$
218,435

 
$
98,071

 
For the full year of 2017, we plan to drill approximately 95 gross wells (90.0 net) and complete 95 gross wells (90.0 net), of which 51 gross wells (45.0 net) were drilled but uncompleted in prior years. In 2017, our drilling program includes approximately $775.0 million in total capital expenditures compared to $372.5 million in 2016. See “Financial and Operating Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital 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,” “Lease Commitments” and “Hydraulic Fracturing Services 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.
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.

20


New Accounting Pronouncements
Refer to Note 1 to the Condensed Consolidated Financial Statements, “Financial Statement Presentation,” for a discussion of new accounting pronouncements that affect us.
Results of Operations
First Three Months of 2017 and 2016 Compared
We reported net income in the first three months of 2017 of $105.7 million, or $0.23 per share, compared to a net loss of $51.2 million, or $0.12 per share, in the first three months of 2016. The increase in net income was primarily due to higher operating revenues and lower operating expenses and interest expense, partially offset by higher income tax expense.
Revenue, Price and Volume Variances
Our revenues vary from year to year as a result of changes in commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.
 
 
Three Months Ended March 31,
 
Variance
Revenue Variances (In thousands)
 
2017
 
2016
 
Amount
 
Percent
   Natural gas
 
$
433,442

 
$
227,578

 
$
205,864

 
90
%
   Crude oil and condensate
 
42,990

 
30,676

 
12,314

 
40
%
   Gain on derivative instruments
 
33,384

 
18,994

 
14,390

 
76
%
   Brokered natural gas
 
4,695

 
3,180

 
1,515

 
48
%
   Other
 
3,332

 
1,513

 
1,819

 
120
%
 
 
$
517,843

 
$
281,941

 
$
235,902

 
84
%
 
 
Three Months Ended March 31,
 
Variance
 
Increase
(Decrease)
(In thousands)
 
 
2017
 
2016
 
Amount
 
Percent
 
Price Variances
 
 

 
 

 
 

 
 

 
 

Natural gas
 
$
2.65

 
$
1.49

 
$
1.16

 
78
 %
 
$
189,921

Crude oil and condensate
 
$
46.68

 
$
27.65

 
$
19.03

 
69
 %
 
17,540

Total
 
 

 
 

 
 

 
 

 
$
207,461

Volume Variances
 
 

 
 

 
 

 
 

 
 

Natural gas (Bcf)
 
163.8

 
153.1

 
10.7

 
7
 %
 
$
15,943

Crude oil and condensate (Mbbl)
 
921

 
1,110

 
(189
)
 
(17
)%
 
(5,226
)
Total
 
 

 
 

 
 

 
 

 
$
10,717

Natural Gas Revenues
The increase in natural gas revenues of $205.9 million was due to higher natural gas prices and higher production. The increase in production was a result of our drilling and completion activities in Pennsylvania, partially offset by the divestiture of certain oil and gas properties in east Texas in February 2016.
Crude Oil and Condensate Revenues
The increase in crude oil and condensate revenues of $12.3 million was due to higher crude oil prices, partially offset by lower production. The decrease in production was a result of a decrease in drilling and completion activities in south Texas.

21


Impact of Derivative Instruments on Operating Revenues
 
 
Three Months Ended 
 March 31,
(In thousands)
 
2017
 
2016
Cash received (paid) on settlement of derivative instruments
 
 

 
 

Gain (loss) on derivative instruments
 
$
(1,524
)
 
$

Non-cash gain (loss) on derivative instruments
 
 
 
 
Gain (loss) on derivative instruments
 
34,908

 
18,994

 
 
$
33,384

 
$
18,994

Brokered Natural Gas
 
 
Three Months Ended March 31,
 
Variance
 
Price and
Volume
Variances
(In thousands)
 
 
2017
 
2016
 
Amount
 
Percent
 
Brokered Natural Gas Sales
 
 
 
 
 
 
 
 

 
 

 
 

Sales price ($/Mcf)
 
$
3.92

 
$
2.20

 
$
1.72

 
78
 %
 
$
2,058

Volume brokered (Mmcf)
 
x
1,196

 
x
1,443

 
(247
)
 
(17
)%
 
(543
)
Brokered natural gas (In thousands)
 
$
4,695

 
$
3,180

 
 
 
 
 
$
1,515

 
 
 
 
 
 
 
 
 
 
 
 
 
Brokered Natural Gas Purchases
 
 
 
 
 
 
 
 
 
 
 
 
Purchase price ($/Mcf)
 
$
3.38

 
$
1.78

 
$
1.60

 
90
 %
 
$
1,920

Volume brokered (Mmcf)
 
x
1,196

 
x
1,443

 
(247
)
 
(17
)%
 
(440
)
Brokered natural gas (In thousands)
 
$
4,046

 
$
2,566

 
 

 
 

 
$
1,480

 
 
 
 
 
 
 
 
 
 
 
 
 
Brokered natural gas margin (In thousands)
 
$
649

 
$
614

 
 

 
 

 
$
35

The slight increase in brokered natural gas margin is a result of a increase in sales price that outpaced the increase in purchase price and lower brokered volumes.
Operating and Other Expenses
 
 
Three Months Ended March 31,
 
Variance
(In thousands)
 
2017
 
2016
 
Amount
 
Percent
Operating and Other Expenses
 
 

 
 

 
 

 
 

   Direct operations
 
$
24,641

 
$
26,035

 
$
(1,394
)
 
(5
)%
   Transportation and gathering
 
123,474

 
109,652

 
13,822

 
13
 %
   Brokered natural gas
 
4,046

 
2,566

 
1,480

 
58
 %
   Taxes other than income
 
9,058

 
5,994

 
3,064

 
51
 %
   Exploration
 
6,198

 
6,383

 
(185
)
 
(3
)%
   Depreciation, depletion and amortization
 
135,100

 
161,887

 
(26,787
)
 
(17
)%
   General and administrative
 
23,700

 
27,873

 
(4,173
)
 
(15
)%
 
 
$
326,217

 
$
340,390

 
$
(14,173
)
 
(4
)%
 
 
 
 
 
 
 
 
 
Earnings (loss) on equity method investments
 
$
(1,283
)
 
$
2,009

 
$
(3,292
)
 
(164
)%
Gain (loss) on sale of assets
 
(223
)
 
1,354

 
(1,577
)
 
(116
)%
Interest expense
 
20,771

 
24,375

 
(3,604
)
 
(15
)%
Other expense
 
424

 
503

 
(79
)
 
(16
)%
Income tax expense (benefit)
 
63,205

 
(28,770
)
 
91,975

 
(320
)%

22


Total costs and expenses from operations decreased by $14.2 million, or 4%, in the first three months of 2017 compared to the same period of 2016. The primary reasons for this fluctuation are as follows:
Direct operations decreased $1.4 million largely due to improved operational efficiencies, cost reductions from service providers and suppliers in 2017 compared to 2016 and the divestiture of certain oil and gas properties in east Texas in February 2016.
Transportation and gathering increased $13.8 million due to higher throughput as a result of higher Marcellus Shale production and a charge associated with transportation expenses in the Eagle Ford.
Brokered natural gas increased $1.5 million. See the preceding table titled “Brokered Natural Gas” for further analysis.
Taxes other than income increased $3.1 million due to $2.5 million higher production taxes, primarily resulting from higher crude oil prices and the receipt of a production tax refund of $1.9 million in February 2016. Additionally, drilling impact fees increased $1.4 million as a result of drilling more wells in Pennsylvania during 2017 compared to 2016 and ad valorem taxes decreased $0.9 million as a result of lower property values primarily in south Texas. The remaining changes in taxes other than income were not individually significant.
Exploration decreased $0.2 million as a result of lower charges related to the release of certain drilling rig contracts in south Texas, partially offset by higher dry hole costs of $2.8 million in 2017. In the first three months of 2016, we recorded rig termination charges of $3.2 million. We recorded no rig termination charges in the first three months of 2017.
Depreciation, depletion and amortization decreased $26.8 million, of which $36.7 million was due to a lower DD&A rate of $0.72 per Mcfe for the first three months of 2017 compared to $0.94 per Mcfe for the first three months of 2016, partially offset by a $9.1 million increase due to higher equivalent production volumes. The lower DD&A rate was primarily due to positive reserve revisions and the impairment of oil and gas properties and related pipeline assets in West Virginia and Virginia in 2016. Offsetting the decreases was $1.4 million higher amortization of unproved properties in the first three months of 2017 as a result of the ongoing evaluation of our unproved properties and and increase in unproved leases.
General and administrative decreased $4.2 million due to lower stock-based compensation expense of $2.4 million primarily due to changes in the Company's stock price and reductions in other general and administrative expenses that were not individually significant.
Earnings (Loss) on Equity Method Investments
The decrease in equity method earnings is the result of our proportionate share of net earnings from our equity method investments in 2017 compared to 2016.
Gain (Loss) on Sale of Assets
An aggregate gain of $1.4 million was recognized in the first three months of 2016 primarily due to the sale of certain of our oil and gas properties in east Texas. There were no individually significant gains or losses on the sale of assets recognized during the first three months of 2017.
Interest Expense
Interest expense decreased $3.6 million due to a $2.1 million decrease resulting from the repayment of the outstanding borrowings under our revolving credit facility in March 2016, which remained undrawn through March 31, 2017. Interest expense also decreased $1.5 million resulting from the repurchase of $64.0 million of our 6.51% weighted-average senior notes in May 2016 and the repayment of $20.0 million of our 7.33% weighted-average senior notes in July 2016.
Income Tax Expense (Benefit)
Income tax expense increased $92.0 million due to higher pretax income and a higher effective tax rate. The effective tax rates for the first three months of 2017 and 2016 were 37.4% and 36.0%, respectively. The increase in the effective tax rate is primarily due to an increase in the blended state statutory tax rate as a result of changes in our state apportionment factors in the

23


states in which we operate and the impact of excess tax benefits and tax deficiencies on stock-based compensation, as well as non-recurring discrete items recorded during the first three months of 2017 versus the first three months of 2016.
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 any of our counterparties defaulted, this protection might be limited as we might not receive the full benefit of our commodity derivatives. Please read the discussion below as well as Note 6 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our derivative and risk management activities.
Periodically, we enter into commodity derivatives, including collar, swap and basis 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 March 31, 2017, we had the following outstanding commodity derivatives:
 
 
 
 
 
 
 
Collars
 
 
 
Basis Swaps
 
Estimated 
Fair Value 
Asset (Liability)
(In thousands)
 
 
 
 
 
 
 
Floor
 
Ceiling
 
Swaps
 
 
Type of Contract
 
Volume
 
Contract Period
 
Range
 
Weighted-
Average
 
Range
 
Weighted-
Average
 
Weighted-
Average
 
Weighted- Average
 
Natural gas
 
26.7

Bcf
 
Apr. 2017 - Dec. 2017
 
 
 
 
 
 
 
 
 
$
3.12

 
 
 
$
(7,487
)
Natural gas
 
13.4

Bcf
 
Apr. 2017 - Dec. 2017
 
 
 
 
 
 
 
 
 
$
3.46

 
 
 
3,472

Natural gas
 
26.7

Bcf
 
Apr. 2017 - Dec. 2017
 
$

 
$
3.09

 
$3.42-$3.45
 
$
3.43

 
 
 
 
 
(3,397
)
Natural gas
 
21.3

Bcf
 
Jan. 2018 - Dec. 2019
 
 
 
 
 
 
 
 
 
 
 
$
0.42

 
3,473

Crude oil
 
1.4

Mmbbl
 
Apr. 2017 - Dec. 2017
 
$

 
$
50.00

 
$56.25-$56.50
 
$
56.39

 
 
 
 
 
1,377

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
(2,562
)
In the above table, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.
The amounts set forth in the table above represent our total unrealized derivative position at March 31, 2017 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

24


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 three months of 2017, natural gas collars with floor prices of $3.09 per Mcf and ceiling prices ranging from $3.42 to $3.45 per Mcf covered 8.7 Bcf, or 5%, of natural gas production at an average price of $3.31 per Mcf. Natural gas swaps covered 11.6 Bcf, or 7%, of natural gas production at an average price of $3.21 per Mcf. Crude oil collars with floor prices of $50.00 per Bbl and ceiling prices ranging from $56.25 to $56.50 per Bbl covered 0.5 Mmbbl, or 49%, of crude oil production at an average price of $51.98 per Bbl.
We are exposed to market risk on commodity derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. 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 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.
We use available market data and valuation methodologies to estimate the fair value of debt. 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 senior 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 senior notes and the revolving credit facility is based on interest rates currently available to us.
The carrying amount and fair value of debt is as follows:
 
 
March 31, 2017
 
December 31, 2016
(In thousands)
 
Carrying
Amount
 
Estimated Fair
Value
 
Carrying
Amount
 
Estimated Fair
Value
Debt
 
$
1,520,870

 
$
1,500,879

 
$
1,520,530

 
$
1,463,643

ITEM 4.    Controls and Procedures
As of March 31, 2017, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
There were no changes in the Company's internal control over financial reporting that occurred during the first quarter of 2017 that have materially affected, or are reasonably likely to materially effect, the Company's internal control over financial reporting.

25



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, 2016.

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 program as of March 31, 2017 was 10.1 million shares.
ITEM 6.    Exhibits
Exhibit
Number
 
Description
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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.

26


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)
 
 
April 28, 2017
By:
/s/ DAN O. DINGES
 
 
Dan O. Dinges
 
 
Chairman, President and Chief Executive Officer
 
 
(Principal Executive Officer)
 
 
April 28, 2017
By:
/s/ SCOTT C. SCHROEDER
 
 
Scott C. Schroeder
 
 
Executive Vice President and Chief Financial Officer