10-Q

s

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2017

or

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

For the transition period from to

Commission File Number: 001-36511

Eclipse Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware	46-4812998
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2121 Old Gatesburg Rd, Suite 110 State College, PA	16803
(Address of principal executive offices)	(Zip code)

(814) 308-9754

(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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    ☒  Yes     ☐  No

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    ☐  No

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.

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐  (Do not check if a small reporting company)	Small reporting company	☐
		Emerging growth company	☒

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.  ☒

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

Number of shares of the registrant’s common stock outstanding at November 9, 2017: 262,740,355 shares

ECLIPSE RESOURCES CORPORATION

QUARTERLY REPORT ON FORM 10-Q

TABLE OF CONTENTS

		Page
Cautionary Statement Regarding Forward-Looking Statements		3
PART I - Financial Information		5
Item 1.	Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46
PART II - Other Information		47
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 6.	Exhibits	47
Index to Exhibits		48
Signatures		50

2

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (the “Quarterly Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and income or losses, projected costs and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “will,” “plan,” “would,” “could,” “endeavor,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are or were, when made, based on our current expectations and assumptions about future events and are or were, when made, based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described in “Item 1A. Risk Factors” of our Annual Report on Form 10-K, filed with the Securities and Exchange Commission (the “SEC”) on March 3, 2017.

Forward-looking statements may include statements about, among other things:

• realized prices for natural gas, natural gas liquids (“NGLs”) and oil and the volatility of those prices;

• write-downs of our natural gas and oil asset values due to declines in commodity prices;

• our business strategy;

• our reserves, including the impact of current commodity prices on our estimated year end reserves;

• general economic conditions;

• our financial strategy, liquidity and capital required for developing our properties and the timing related thereto;

• the timing and amount of future production of natural gas, NGLs and oil;

• our hedging strategy and results;

• future drilling plans;

• competition and government regulations, including those related to hydraulic fracturing;

• the anticipated benefits under our commercial agreements;

• pending legal matters relating to our leases;

• marketing of natural gas, NGLs and oil;

• leasehold and business acquisitions;

• leasehold terms expiring before production can be established;

• the costs, terms and availability of gathering, processing, fractionation and other midstream services;

• credit markets;

• uncertainty regarding our future operating results, including initial production rates and liquid yields in our type curve areas; and

• plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, legal and environmental risks, drilling and other operating risks, regulatory changes, commodity price volatility and the recent significant decline of the price of natural gas, NGLs and oil, inflation, lack of availability of drilling, production and processing equipment and services, inability to successfully negotiate or enter into definitive agreements regarding our proposed joint development transaction with Sequel Energy Group LLC, or to effectively implement that transaction, counterparty credit risk, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, risks associated with our level of indebtedness, the timing of development expenditures, and the other risks described in “Item 1A. Risk Factors” of our Annual Report on Form 10-K, filed with the SEC on March 3, 2017.

3

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect new information obtained or events or circumstances that occur after the date of this Quarterly Report.

4

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

ECLIPSE RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

	September 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	28,795		$	201,229
Accounts receivable		40,553			44,423
Assets held for sale		426			468
Other current assets		6,959			4,295
Total current assets		76,733			250,415
PROPERTY AND EQUIPMENT AT COST
Oil and natural gas properties, successful efforts method:
Unproved properties		488,260			526,270
Proved oil and gas properties, net		636,023			414,482
Other property and equipment, net		7,190			6,748
Total property and equipment, net		1,131,473			947,500
OTHER NONCURRENT ASSETS
Other assets		2,040			729
TOTAL ASSETS	$	1,210,246		$	1,198,644
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	69,914		$	44,049
Accrued capital expenditures		19,319			11,083
Accrued liabilities		24,981			55,044
Accrued interest payable		9,973			21,098
Liabilities held for sale		189			245
Total current liabilities		124,376			131,519
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs		494,332			492,278
Asset retirement obligations		5,766			4,806
Other liabilities		2,740			13,434
Total liabilities		627,214			642,037
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, 50,000,000 authorized, no shares issued and outstanding		—			—
Common stock, $0.01 par value, 1,000,000,000 authorized, 262,740,355    and 260,591,893 shares issued and outstanding, respectively		2,637			2,607
Additional paid in capital		1,965,514			1,958,731
Treasury stock, shares at cost; 992,315 and 72,704 shares, respectively		(2,096	)		(61	)
Accumulated deficit		(1,383,023	)		(1,404,670	)
Total stockholders' equity		583,032			556,607
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,210,246		$	1,198,644

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

5

ECLIPSE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(In thousands, except per share data)

(Unaudited)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
REVENUES
Natural gas, oil and natural gas liquids sales	$	91,549		$	54,351		$	277,174		$	140,740
Brokered natural gas and marketing revenue		—			128			2,428			10,411
Total revenues		91,549			54,479			279,602			151,151
OPERATING EXPENSES
Lease operating		5,032			2,186			11,943			7,111
Transportation, gathering and compression		30,869			26,888			92,715			78,279
Production and ad valorem taxes		2,427			1,128			6,391			5,894
Brokered natural gas and marketing expense		8			42			2,474			11,604
Depreciation, depletion and amortization		35,588			28,225			86,929			64,287
Exploration		8,937			12,083			29,514			45,183
General and administrative		11,347			8,036			32,209			29,712
Rig termination and standby		—			(112	)		—			3,843
Impairment of proved oil and gas properties		—			—			—			17,665
Accretion of asset retirement obligations		143			100			395			275
(Gain) loss on sale of assets		(13	)		102			(12	)		(944	)
Total operating expenses		94,338			78,678			262,558			262,909
OPERATING INCOME (LOSS)		(2,789	)		(24,199	)		17,044			(111,758	)
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		(1,889	)		10,639			41,385			(8,407	)
Interest expense, net		(12,016	)		(12,393	)		(36,763	)		(38,293	)
Gain (loss) on early extinguishment of debt		—			—			—			14,489
Other income (expense)		—			4			(19	)		(137	)
Total other income (expense), net		(13,905	)		(1,750	)		4,603			(32,348	)
INCOME (LOSS) BEFORE INCOME TAXES		(16,694	)		(25,949	)		21,647			(144,106	)
INCOME TAX BENEFIT (EXPENSE)		—			—			—			(540	)
NET INCOME (LOSS)	$	(16,694	)	$	(25,949	)	$	21,647		$	(144,646	)
NET INCOME (LOSS) PER COMMON SHARE
Basic	$	(0.06	)	$	(0.10	)	$	0.08		$	(0.62	)
Diluted	$	(0.06	)	$	(0.10	)	$	0.08		$	(0.62	)
WEIGHTED AVERAGE COMMON SHARES    OUTSTANDING
Basic		262,586			258,812			262,044			234,933
Diluted		262,586			258,812			264,717			234,933

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

6

ECLIPSE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

	Number of Shares		Common Stock ($0.01 Par)		Additional Paid-in- Capital			Treasury Stock			Accumulated Deficit			Total
Balances, December 31,    2016		260,591,893	$	2,607	$	1,958,731		$	(61	)	$	(1,404,670	)	$	556,607
Stock-based compensation		—		—		6,857			—			—			6,857
Equity issuance costs		—		—		(44	)		—			—			(44	)
Issuance of restricted stock		153,192		2		(2	)		—			—			—
Issuance of common stock upon vesting of    equity-based compensation awards, net of    shares withheld for income tax withholdings		1,995,270		28		(28	)		(2,035	)		—			(2,035	)
Net income		—		—		—			—			21,647			21,647
Balances, September 30,    2017		262,740,355	$	2,637	$	1,965,514		$	(2,096	)	$	(1,383,023	)	$	583,032

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

7

ECLIPSE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	For the Nine Months Ended September 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	21,647		$	(144,646	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating    activities
Depreciation, depletion and amortization		86,929			64,287
Exploration expense		14,206			28,952
Stock-based compensation		6,857			5,464
Impairment of proved oil and gas properties		—			17,665
Accretion of asset retirement obligations		395			275
(Gain) loss on derivative instruments		(41,385	)		8,407
Net cash receipts (payments) on settled derivatives		(5,048	)		35,870
(Gain) loss on sale of assets		(12	)		(944	)
(Gain) loss on early extinguishment of debt		—			(14,489	)
Deferred income taxes		—			540
Amortization of deferred financing costs		1,553			1,457
Amortization of debt discount		992			1,033
Changes in operating assets and liabilities:
Accounts receivable		4,357			(1,797	)
Other assets		56			(1,902	)
Accounts payable and accrued liabilities		(3,344	)		(28,659	)
Net cash provided by (used in) operating activities		87,203			(28,487	)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties		(254,353	)		(92,204	)
Capital expenditures for other property and equipment		(1,901	)		(852	)
Proceeds from sale of assets		551			14,887
Net cash used in investing activities		(255,703	)		(78,169	)
CASH FLOWS FROM FINANCING ACTIVITIES
Debt issuance costs		(1,657	)		40
Repayments of long-term debt		(198	)		(23,936	)
Proceeds from issuance of common stock		—			124,361
Equity issuance costs		(44	)		(484	)
Employee tax withholding for settlement of equity compensation awards		(2,035	)		(61	)
Net cash provided by (used in) financing activities		(3,934	)		99,920
Net decrease in cash and cash equivalents		(172,434	)		(6,736	)
Cash and cash equivalents at beginning of period		201,229			184,405
Cash and cash equivalents at end of period	$	28,795		$	177,669
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	$	46,638		$	48,101
Cash paid for income taxes	$	—		$	—
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	$	565		$	923
Additions to oil and natural gas properties - changes in accounts payable,    accrued liabilities, and accrued capital expenditures	$	27,125		$	26,055

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

8

ECLIPSE RESOURCES CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Organization and Nature of Operations

Eclipse Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas.

Note 2—Basis of Presentation

The accompanying condensed consolidated financial statements are unaudited except the condensed consolidated balance sheet at December 31, 2016, which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. All such adjustments are of a normal recurring nature.  These interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements, and the notes to those statements, which are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2017.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2017 or any other future periods.

Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the condensed consolidated financial statements are the following:

• estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion and amortization and impairment of capitalized costs of oil and natural gas properties;

• estimates of asset retirement obligations;

• estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;

• impairment of undeveloped properties and other assets; and

• depreciation and depletion of property and equipment.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

9

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of September 30, 2017 or December 31, 2016.

The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $37.8 million and $41.4 million of accrued revenues, net of certain expenses, at September 30, 2017 and December 31, 2016, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets.

(c) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, Depletion and Amortization” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s consolidated statements of operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

	September 30, 2017			December 31, 2016
Oil and natural gas properties:
Unproved	$	488,260		$	526,270
Proved		1,852,828			1,545,860
Gross oil and natural gas properties		2,341,088			2,072,130
Less accumulated depreciation, depletion and amortization		(1,216,805	)		(1,131,378	)
Oil and natural gas properties, net		1,124,283			940,752
Other property and equipment		13,333			11,447
Less accumulated depreciation		(6,143	)		(4,699	)
Other property and equipment, net		7,190			6,748
Property and equipment, net	$	1,131,473		$	947,500

10

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

The Company capitalized interest expense totaling $0.9 million and $0.4 million for the three months ended September 30, 2017 and 2016, respectively.  The Company capitalized interest expense totaling $1.8 million and $0.8 million for the nine months ended September 30, 2017 and 2016, respectively.

Other Property and Equipment

Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

(d) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of September 30, 2017 or December 31, 2016.

In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.

Brokered natural gas and marketing revenues include revenues from brokered gas or revenue the Company receives as a result of selling and buying natural gas that is not related to its production and revenue from the release of transportation capacity. The Company realizes brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. The Company considers these activities as ancillary to its natural gas sales and thus, reports them within one operating segment.

(e) Concentration of Credit Risk

The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of September 30, 2017 and December 31, 2016 (in thousands):

	September 30, 2017		December 31, 2016
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	37,845	$	41,398
Joint interest owners		2,076		2,850
Derivatives		609		122
Other		23		53
Total	$	40,553	$	44,423

11

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s unsettled commodity derivative contracts was a net liability position of ($5.5) million and ($48.1) million at September 30, 2017 and December 31, 2016, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are such counterparties required to provide credit support to the Company. As of September 30, 2017 and December 31, 2016, the Company did not have past-due receivables from or payables to any of such counterparties.

(f) Depreciation, Depletion and Amortization

Oil and Natural Gas Properties

Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties totaled approximately $35.1 million and $27.7 million for the three months ended September 30, 2017 and 2016, respectively, and $85.4 million and $62.8 million for the nine months ended September 30, 2017 and 2016, respectively.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation totaled approximately $0.5 million for each of the three months ended September 30, 2017 and 2016 and $1.5 million for each of the nine months ended September 30, 2017 and 2016. This amount is included in DD&A expense in the condensed consolidated statements of operations.

(g) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review for impairment of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the nine months ended September 30, 2016 relating to proved properties in the Marcellus Shale. There were no impairments of proved properties for the three or nine months ended September 30, 2017 or the three months ended September 30, 2016.

The aforementioned impairment charge represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows.

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The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $4.1 million and $9.4 million for the three months ended September 30, 2017 and 2016, respectively, and approximately $12.4 million and $28.1 million for the nine months ended September 30, 2017 and 2016, respectively. The decrease in impairment charges during the three and nine months ended September 30, 2017 is the result of a decrease in expected lease expirations due to the increase in the Company’s planned future drilling activity. These costs are included in exploration expense in the condensed consolidated statements of operations.

(h) Income Taxes

The Company accounts for income taxes, as required, under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

(i) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.  The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

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(j) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

(k) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 10.33% for each of the nine months ended September 30, 2017 and 2016.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2017 (in thousands):

	Nine Months Ended September 30, 2017
Asset retirement obligations, beginning of period	$	4,806
Additional liabilities incurred		565
Accretion		395
Asset retirement obligations, end of period	$	5,766

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(l) Lease Obligations

The Company leases office space under an operating lease that expires in 2024. The lease term begins on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

(m) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

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(n) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(o) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

(p) Recent Accounting Pronouncements

The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to 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. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period with early adoption permitted.

The Company expects to adopt this standard effective January 1, 2018 using the modified retrospective method.  As part of the implementation process, the Company has substantially completed the detailed analysis of the impact of the standard on its contracts.  The Company does not expect this standard to have a significant impact on its financial position or results of operations but adopting this guidance will require that revenue recognition policy disclosures include further detail regarding performance obligations as to the nature, amount, timing and estimates of revenue and cash flows generated from the Company’s contracts with customers.  The Company continues to monitor relevant industry guidance regarding implementation of the standard and adjust its implementation strategies as necessary.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity will be required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.”  The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows.  These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company is evaluating the impact of the adoption on its statement of cash flows and related disclosures.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.”  Currently under the standard there are three elements of a business: inputs, processes and outputs.  The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets.  If that screen is met, the set of assets is not a business.  The new framework also specifies the minimum required inputs and processes necessary to be a business.  This amendment is effective for periods after December 15, 2017, with early adoption permitted.  The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

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(q) Correction of Immaterial Error

During the three months ended March 31, 2017, the Company determined that its estimated accrual for production and ad valorem tax expense was overstated for prior periods. The Company evaluated the materiality of this error on both a quantitative and qualitative basis under the guidance of ASC 250 “Accounting Changes and Errors Corrections,” and determined that it did not have a material impact to previously issued financial statements.

Although the error was immaterial to prior periods, the prior period financial statements were revised, in accordance with SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, due to the significance of the out-of-period correction to the current period. Immaterial errors related to periods prior to the year ended December 31, 2016 are reflected as an adjustment to beginning accumulated deficit for that year. Periods not presented herein will be revised, as applicable, in future filings.

A reconciliation of the effects of the revision to amounts in the previously reported consolidated financial statements is as follows (in thousands, except per share amounts):

	As of  December 31, 2016
	As Reported			Adjustment			As Adjusted
Balance Sheet
Accounts receivable	$	43,638		$	785		$	44,423
Total current assets		249,630			785			250,415
Total assets		1,197,859			785			1,198,644
Accrued liabilities		64,150			(9,106	)		55,044
Total current liabilities		140,625			(9,106	)		131,519
Total liabilities		651,143			(9,106	)		642,037
Accumulated deficit		(1,414,561	)		9,891			(1,404,670	)
Total stockholders' equity		546,716			9,891			556,607
Total liabilities and stockholders' equity		1,197,859			785			1,198,644

	As of  December 31, 2016
	As Reported			Adjustment		As Adjusted
Statement of Stockholders' Equity
Accumulated deficit	$	(1,414,561	)	$	9,891	$	(1,404,670	)
Total stockholders' equity		546,716			9,891		556,607

	Three Months Ended September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations and Comprehensive Income    (Loss)
Production and ad valorem taxes	$	1,980		$	(852	)	$	1,128
Total operating expenses		79,530			(852	)		78,678
Operating loss		(25,051	)		852			(24,199	)
Loss before income taxes		(26,801	)		852			(25,949	)
Net loss		(26,801	)		852			(25,949	)
Basic and diluted loss per share	$	(0.10	)	$	(0.00	)	$	(0.10	)

	Nine Months Ended September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations and Comprehensive Income    (Loss)
Production and ad valorem taxes	$	1,747		$	4,147		$	5,894
Total operating expenses		258,762			4,147			262,909
Operating loss		(107,611	)		(4,147	)		(111,758	)
Loss before income taxes		(139,959	)		(4,147	)		(144,106	)
Net loss		(140,499	)		(4,147	)		(144,646	)
Basic and diluted loss per share	$	(0.60	)	$	(0.02	)	$	(0.62	)

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	As of September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Cash Flows
Net loss	$	(140,499	)	$	(4,147	)	$	(144,646	)
Accounts receivable		(1,261	)		(536	)		(1,797	)
Accounts payable and accrued liabilities		(33,342	)		4,683			(28,659	)

Note 4—Sale of Oil and Natural Gas Property Interests

During the three months ended September 30, 2016, the Company received $0.4 million from the sale of pipeline assets.  As a result of this sale, the Company recognized a loss of less than $0.1 million.

During the three months ended September 30, 2016, the Company received $1.1 million from acreage trades with various working interest owners totaling approximately 149.5 acres.

During the nine months ended September 30, 2016, the Company completed the sale of its Conventional oil and gas properties and related equipment for approximately $4.7 million. As a result of this sale, the Company recognized a gain of approximately $1.0 million.

During the nine months ended September 30, 2016, the Company received $3.9 million from the sale of mineral interests related primarily to unproved properties to a third party.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the nine months ended September 30, 2016, the Company received $4.8 million from the sale of unproved leases to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the nine months ended September 30, 2017, the Company received approximately $0.5 million from a completed asset sale with a third party totaling approximately 100 acres.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

Note 5—Derivative Instruments

Commodity Derivatives

The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.

The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of September 30, 2017, the Company’s derivative instruments were with Bank of Montreal, Citibank, Goldman Sachs, Morgan Stanley, Capital One N.A., BP Energy Company and KeyBank N.A. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of September 30, 2017, for future production periods:

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Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		10,000	October 2017 – December 2017	$	2.98
		10,000	October 2017 – December 2017	$	3.21
		30,000	October 2017 – March 2018	$	3.46
Natural Gas Three-way Collars:
Floor purchase price (put)		160,000	October 2017 – December 2017	$	2.83
Ceiling sold price (call)		160,000	October 2017 – December 2017	$	3.37
Floor sold price (put)		160,000	October 2017 – December 2017	$	2.31
Floor purchase price (put)		30,000	October 2017 – March 2019	$	3.00
Ceiling sold price (call)		30,000	October 2017 – March 2019	$	3.40
Floor sold price (put)		20,000	October 2017 – March 2019	$	2.40
Floor sold price (put)		10,000	October 2017 – March 2019	$	2.20
Floor purchase price (put)		40,000	October 2017 – December 2018	$	2.90
Ceiling sold price (call)		40,000	October 2017 – December 2018	$	3.38
Floor sold price (put)		40,000	October 2017 – December 2018	$	2.30
Floor purchase price (put)		60,000	January 2018 – March 2018	$	2.90
Ceiling sold price (call)		60,000	January 2018 – March 2018	$	3.75
Floor sold price (put)		60,000	January 2018 – March 2018	$	2.40
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.90
Ceiling sold price (call)		60,000	April 2018 – December 2018	$	3.25
Floor sold price (put)		60,000	April 2018 – December 2018	$	2.40
Floor purchase price (put)		60,000	January 2018 – December 2018	$	2.80
Ceiling sold price (call)		60,000	January 2018 – December 2018	$	3.35
Floor sold price (put)		60,000	January 2018 – December 2018	$	2.33
Natural Gas Call/Put Options:
Call sold		40,000	January 2018 – December 2018	$	3.75
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
TCO - Columbia		20,000	October 2017 – December 2017	$	(0.19	)
Appalachia - Dominion		80,000	October 2017 – November 2017	$	(1.02	)
Appalachia - Dominion		50,000	December 2017	$	(0.56	)
Appalachia - Dominion		50,000	January 2018 – March 2018	$	(0.43	)
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)

Oil Derivatives

Description	Volume (Bbls/d)		Production Period	WeightedAverage Price($/Bbl)
Oil Three-way Collars:
Floor purchase price (put)		2,000	October 2017 – December 2017	$	46.00
Ceiling sold price (call)		2,000	October 2017 – December 2017	$	60.00
Floor sold price (put)		2,000	October 2017 – December 2017	$	38.00

NGL Derivatives

Description	Volume (Gal/d)		Production Period	Weighted Average Price ($/Gal)
Propane Swaps:
		84,000	October 2017 – December 2017	$	0.60

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Fair Values and Gains (Losses)

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the condensed consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.

As of September 30, 2017	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	6,358		$	(3,638	)	$	2,720		Other current assets
Commodity derivatives - noncurrent		976			(831	)		145		Other assets
Total assets	$	7,334		$	(4,469	)	$	2,865
Liabilities
Commodity derivatives - current	$	(9,844	)	$	3,638		$	(6,206	)	Accrued liabilities
Commodity derivatives - noncurrent		(3,006	)		831			(2,175	)	Other liabilities
Total liabilities	$	(12,850	)	$	4,469		$	(8,381	)

As of December 31, 2016	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	50		$	(50	)	$	—
Commodity derivatives - noncurrent		—			—			—
Total assets	$	50		$	(50	)	$	—
Liabilities
Commodity derivatives - current	$	(35,459	)	$	50		$	(35,409	)	Accrued liabilities
Commodity derivatives - noncurrent		(12,673	)		—			(12,673	)	Other liabilities
Total liabilities	$	(48,132	)	$	50		$	(48,082	)

(a) The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the condensed consolidated statements of operations for the periods presented (in thousands):

		Amount of Gain (Loss) Recognized in Income
Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss) Recognized in Income	Three Months Ended September 30,					Nine Months Ended September 30,
		2017			2016		2017		2016
Commodity derivatives	Gain (loss) on derivative instruments	$	(1,889	)	$	10,639	$	41,385	$	(8,407	)

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Note 6—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the condensed consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are readily available in the public market, such as natural gas and crude oil forward curves. These values are compared to the values given by counterparties for reasonableness. Since the Company’s derivative instruments do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.

	Level 1		Level 2			Level 3		TotalFair Value
As of September 30, 2017: (in thousands)
Commodity derivative instruments	$	—	$	(5,516	)	$	—	$	(5,516	)
Total	$	—	$	(5,516	)	$	—	$	(5,516	)
As of December 31, 2016: (in thousands)
Commodity derivative instruments	$	—	$	(48,082	)	$	—	$	(48,082	)
Total	$	—	$	(48,082	)	$	—	$	(48,082	)

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3—Summary of Significant Accounting Policies).

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3—Summary of Significant Accounting Policies).

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 7—Debt).

Note 7—Debt

8.875% Senior Unsecured Notes Due 2023

On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of the principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding Senior PIK Notes. The Company used the remaining net proceeds to fund its capital expenditure plan and for general corporate purposes.

During the three and nine months ended September 30, 2017, the Company amortized $0.8 million and $2.5 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.  The Company amortized $0.7 million and $2.5 million of deferred financing costs and debt discount to interest expense using the effective interest method for the three and nine months ended September 30, 2016, respectively. 

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The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the indenture at September 30, 2017.

During the nine months ended September 30, 2016, the Company repurchased $39.5 million of the outstanding senior unsecured notes in open market purchases for $23.4 million. The principal of the outstanding senior unsecured notes that were repurchased less cash proceeds and unamortized debt discount and deferred financing costs were charged to gain on early extinguishment of debt, totaling $14.5 million for the nine months ended September 30, 2016.  The Company repurchased all such senior unsecured notes with cash on hand. 

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at September 30, 2017 was $519.4 million.

Revolving Credit Facility

During the first quarter of 2014, the Company entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that matures in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October).

On February 24, 2016, the Company amended the Credit Amendment governing its revolving credit facility to, among other things, adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense, and to permit the sale of certain conventional properties. The amendment to the Credit Agreement governing the revolving credit facility increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5% and required the Company to, within 60 days of the effectiveness of the amendment, execute and deliver additional mortgages on the Company’s oil and gas properties that include at least 90% of its proved reserves.

On February 24, 2017, the Company entered into an additional amendment that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020.  In addition, the amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Net Debt to EBITDAX.  On August 1, 2017, the Company entered into an additional amendment that increased the borrowing base from $175 million to $225 million.  The Company’s next scheduled borrowing base redetermination is expected to be completed by April 2018.

At September 30, 2017, the borrowing base was $225 million and the Company had no outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $33.6 million, the Company had available borrowing capacity under the revolving credit facility of $191.4 million at September 30, 2017.  Subsequent to September 30, 2017, the Company borrowed $15 million under its revolving credit facility, which reduced the Company’s available borrowing capacity to $176.4 million.

The revolving credit facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the revolving credit facility as of September 30, 2017. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.5% of the unused facility based on utilization.

Note 8—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation

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contributed to the plan. The Company recorded compensation expense related to matching contributions, classified under general and administrative, of $0.2 million and $0.1 million for the three months ended September 30, 2017 and 2016, respectively, and $0.6 million and $0.5 million for the nine months ended September 30, 2017 and 2016, respectively.

Note 9—Stock-Based Compensation

The Company is authorized to grant up to 25,000,000 shares of common stock under its 2014 Long-Term Incentive Plan (as amended, the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 10,364,375 shares were available for future grants under the Plan as of September 30, 2017.

Our stock-based compensation expense was as follows for the three and nine months ended September 30, 2017 and 2016 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Restricted stock units	$	1,351	$	1,012	$	3,943	$	3,254
Performance units		987		651		2,627		1,708
Restricted stock issued to directors		90		101		287		454
Incentive units		—		—		—		48
Total expense	$	2,428	$	1,764	$	6,857	$	5,464

Restricted Stock Units

Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock and restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of September 30, 2017, there was $7.2 million of total unrecognized compensation cost related to outstanding restricted stock units. The weighted average period for the shares to vest is approximately 1 year. A summary of restricted stock unit awards activity during the nine months ended September 30, 2017 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2016		4,343,582		$	2.14	$	11,597
Granted		2,692,797			2.12
Vested		(2,914,881	)		1.65
Forfeited		(64,144	)		2.46
Total awarded and unvested, September 30, 2017		4,057,354		$	2.48	$	10,143

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of September 30, 2017, there was $6.0 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the shares to vest is approximately 2 years. A summary of performance stock unit awards activity during the nine months ended September 30, 2017 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2016		1,928,002		$	3.31	$	5,148
Granted		2,564,523			1.94
Vested		—			—
Forfeited		(78,130	)		2.75
Total awarded and unvested, September 30, 2017		4,414,395		$	2.52	$	10,646

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The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s public peer group.

Restricted Stock Issued to Directors

On May 11, 2015, the Company issued an aggregate of 132,496 restricted shares of common stock to its seven non-employee members of its Board of Directors, which became fully vested on May 11, 2016. For the nine months ended September 30, 2016, the Company recognized expense of approximately $0.3 million related to these awards.

On May 18, 2016, the Company issued an aggregate of 149,448 restricted shares of common stock to its three non-employee  members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which became fully vested on May 18, 2017.  For the three and nine months ended September 30, 2016, the Company recognized expense of approximately $0.2 million related to these awards.  For the nine months ended September 30, 2017, the Company recognized expense of approximately $0.2 million related to these awards.

On May 17, 2017, the Company issued an aggregate of 153,192 restricted shares of common stock to its three non-employee members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which are scheduled to fully vest on May 17, 2018.  For the three and nine months ended September 30, 2017, the Company recognized expense of approximately $0.1 million and $0.3 million, respectively, related to these awards.  As of September 30, 2017, there was approximately $0.2 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s directors.

Note 10—Equity

Public Offering of Common Stock

On June 28, 2016, the Company commenced an underwritten public offering of 37,500,000 shares of common stock, which was priced at $3.50 per share.  The Company closed the offering on July 5, 2016 and received net proceeds of approximately $123 million (after deducting underwriting discounts and commissions and estimated expenses), which the Company used to fund its capital expenditure plan and for general corporate purposes.  

Note 11—Earnings (Loss) Per Share

Earnings (Loss) Per Share

Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive.  The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three and nine months ended September 30, 2017 and 2016, respectively:

	Three Months Ended September 30,
(in thousands, except per share data)	2017								2016
	Income (Loss)			Shares		Per Share			Income (Loss)			Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(16,694	)		262,586	$	(0.06	)	$	(25,949	)		258,812	$	(0.10	)
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—			—
Diluted:
Net income (loss), shares, diluted	$	(16,694	)		262,586	$	(0.06	)	$	(25,949	)		258,812	$	(0.10	)

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	Nine Months Ended September 30,
(in thousands, except per share data)	2017						2016
	Income (Loss)		Shares		Per Share		Income (Loss)			Shares		Per Share
Basic:
Net income (loss), shares, basic	$	21,647		262,044	$	0.08	$	(144,646	)		234,933	$	(0.62	)
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—		2,673				—			—
Diluted:
Net income (loss), shares, diluted	$	21,647		264,717	$	0.08	$	(144,646	)		234,933	$	(0.62	)

Note 12—Related Party Transactions

During the three and nine months ended September 30, 2017, the Company incurred approximately $0.2 million and $0.4 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which are owned by the Company’s Chairman, President and Chief Executive Officer.  The Company incurred approximately $0.1 million and $0.4 million related to such services during the three and nine months ended September 30, 2016, respectively.  The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms.

Note 13—Commitments and Contingencies

(a) Legal Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

(b) Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

(c) Leases

The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.

The Company leases office space under an operating lease that expires in 2024. The Company recognized rent expense of $0.2 million and $0.1 million for the three months ended September 30, 2017 and 2016, respectively, and $0.5 million and $0.7 million for the nine months ended September 30, 2017 and 2016, respectively.

Note 14—Income Tax

For the year ending December 31, 2017, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company recorded no income tax expense for the period due to a reduction of previously recorded valuation allowance in the amount of $7.5 million, which is net of a discrete item in the amount of $0.6 million related to an income tax for a share based compensation windfall settled in the first quarter of 2017.  

The Company is forecasting positive pretax income for the year and as a result plans on reducing its valuation allowance to the extent the Company records pretax income cumulatively year to date in the quarter.  At this time, the Company does not believe that the weight of evidence allows the release of its valuation allowance (due to a preponderance of negative evidence as to future realizability) and accordingly reflect a current deferred tax benefit of zero.  The Company continues to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.  No current federal income taxes are anticipated to be paid in the next twelve months. For the nine months ended September 30, 2017, the Company’s overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to valuation allowances and other permanent differences.

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During the second quarter of 2017, the Internal Revenue Service completed its examination of Eclipse Resources Corporation for its tax year 2014.  There were no adjustments to the Company’s tax returns as a result of the examination.

Note 15—Subsidiary Guarantors

The Company’s wholly-owned subsidiaries each have fully and unconditionally, joint and severally, guaranteed the Company’s 8.875% senior unsecured notes (See Note 7—Debt). The Parent company has no independent assets or operations. The Company’s wholly-owned subsidiaries are not restricted from transferring funds to the Parent or other wholly-owned subsidiaries. The Company’s wholly-owned subsidiaries do not have any restricted net assets.

A subsidiary guarantor may be released from its obligations under the guarantee:

• in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or

• if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture governing the senior unsecured notes.

Note 16—Subsequent Events

Management has evaluated subsequent events and believes there are no events that would have a material impact on the aforementioned financial statements and related disclosures, other than those disclosed in the accompanying notes to the condensed consolidated financial statements (See Note 7—Debt).

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016 and our condensed consolidated financial statements and related notes appearing elsewhere in this Quarterly Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview of Our Business

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. As of September 30, 2017, we had assembled an acreage position approximating 206,000 net acres in Eastern Ohio, which excludes any acreage currently pending title.

Approximately 99,000 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 15,000 of these net acres are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio within what we refer to as our Marcellus Area. We are the operator of approximately 92% of our net acreage within the Utica Core Area and our Marcellus Area. We intend to focus on developing our substantial inventory of horizontal drilling locations during commodity price environments that will allow us to generate attractive returns and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.

As of September 30, 2017, we, or our operating partners, had commenced drilling 227 gross wells within the Utica Core Area and our Marcellus Area, of which 5 gross were top holed, 2 gross were drilling, 15 gross were awaiting completion or were in the process of being completed, 3 gross were awaiting midstream, and 202 gross had been turned to sales.

As of September 30, 2017, we were operating 2 horizontal rigs in the Utica Core Area. We had average daily production for the three months ended September 30, 2017 of approximately 352.8 MMcfe comprised of approximately 82% natural gas, 13% NGLs and 5% oil.

How We Evaluate Our Operations

In evaluating our current and future financial results, we focus on production and revenue growth, lease operating expense, general and administrative expense (both before and after non-cash stock compensation expense) and operating margin per unit of production. In addition to these metrics, we use Adjusted EBITDAX, a non-GAAP measure, to evaluate our financial results. We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion and amortization (“DD&A”); amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX is not a measure of net income as determined by generally accepted accounting principles in United States, or “U.S. GAAP.”

In addition to the operating metrics above, as we grow our reserve base, we will assess our capital spending by calculating our operated proved developed reserves and our operated proved developed finding costs and development costs. We believe that operated proved developed finding and development costs are one of the key measurements of the performance of an oil and gas exploration and production company. We will focus on our operated properties as we control the location, spending and operations associated with drilling these properties. In determining our proved developed finding and development costs, only cash costs incurred in connection with exploration and development will be used in the calculation, while the costs of acquisitions will be excluded because our board approves each material acquisition. In evaluating our proved developed reserve additions, any reserve revisions for changes in commodity prices between years will be excluded from the assessment, but any performance related reserve revisions are included.

We also continually evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our acreage in the Utica Core Area and our Marcellus Area. We review changes in drilling and completion costs; lease operating costs; natural gas, NGLs and oil prices; well productivity; and other factors in order to focus our drilling on the highest rate of return areas within our acreage.

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Overview of Results for the Three and Nine Months Ended September 30, 2017

During the three months ended September 30, 2017, we achieved the following financial and operating results:

• our average daily net production for the three months ended September 30, 2017 was 352.8 MMcfe per day representing an increase of 59% over the comparable period of the prior year;

• commenced drilling 10 gross (9.7 net) operated Utica and Marcellus Shale wells, commenced completions of 6 gross (6.0 net) operated Utica Shale wells and turned-to-sales 2 gross (2.0 net) operated Utica Shale wells;

• recognized net loss of ($16.7) million for the three months ended September 30, 2017 compared to a net loss of ($25.9) million for the three months ended September 30, 2016; and

• realized Adjusted EBITDAX of $45.9 million for the three months ended September 30, 2017 compared to $22.6 million for three months ended September 30, 2016. Adjusted EBITDAX is a non-GAAP financial measure. See “Non-GAAP Financial Measure” for more information.

During the nine months ended September 30, 2017, we achieved the following financial and operating results:

• increased our average daily net production for the nine months ended September 30, 2017 by 41% over the comparable period of the prior year, to 310.4 MMcfe per day;

• completed the drilling of two of our 19,500 foot extended reach lateral wells in less than 17 days to total depth;

• commenced drilling 23 gross (22.5 net) operated Utica and Marcellus Shale wells, commenced completions of 19 gross (18.8 net) operated Utica Shale wells and turned-to-sales 16 gross (15.7 net) operated Utica Shale wells;

• recognized net income of $21.6 million for the nine months ended September 30, 2017 compared to a net loss of  ($144.6) million for the nine months ended September 30, 2016; and

• realized Adjusted EBITDAX of $135.7 million for the nine months ended September 30, 2017 compared to $59.9 million for the nine months ended September 30, 2016. Adjusted EBITDAX is a non-GAAP financial measure. See “Non-GAAP Financial Measure” for more information.

Market Conditions

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists average, high, low and average monthly settled NYMEX Henry Hub prices for natural gas and NYMEX WTI prices for oil for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
NYMEX Henry Hub High ($/MMBtu)	$	3.18	$	3.19	$	3.71	$	3.19
NYMEX Henry Hub Low ($/MMBtu)		2.76		2.67		2.44		1.49
Average Daily NYMEX Henry Hub ($/MMBtu)		2.95		2.88		3.01		2.37
Average Monthly NYMEX Settled Henry Hub ($/MMBtu)		3.00		2.81		3.17		2.29
NYMEX WTI High ($/Bbl)	$	52.14	$	49.02	$	54.48	$	51.23
NYMEX WTI Low ($/Bbl)		44.25		39.50		42.48		26.19
Average NYMEX WTI ($/Bbl)		48.18		44.89		49.30		42.25

Historically, commodity prices have been extremely volatile, and we expect this volatility to continue for the foreseeable future. A decline in commodity prices could materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

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The Company is committed to profitably developing its natural gas, NGLs and condensate reserves through an environmentally responsible and cost-effective operational plan.  The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop its reserves.  Despite the continued low price commodity environment, the Company believes the long-term outlook for its business is favorable due to the Company’s resource base, low cost structure, risk management strategies, and disciplined investment of capital.

It is difficult to quantify the impact of changes in future commodity prices on our reported estimated net proved reserves with any degree of certainty because of the various components and assumptions used in the process.  However, to demonstrate the sensitivity of our estimates of natural gas, NGLs and oil reserves to changes in commodity prices, we provided an analysis in our Annual Report on Form 10-K for the year ended December 31, 2016.  Further, if we recalculated our reserves using the unweighted arithmetic average first-day-of-the-month price for each of the twelve months in the period ended September 30, 2017 and held all other factors constant, then our estimated net proved reserves at December 31, 2016 would have increased by approximately 152% from our previously reported estimated net proved reserves at such time, including a 15% addition of proved developed reserves and a 389% addition of proved undeveloped reserves.  The foregoing estimate is based upon an average SEC price of $3.00 per MMBtu for natural gas and $49.81 per Bbl for NGLs and oil. This calculation only isolates the potential impact of commodity prices on our estimated proved reserves and does not account for other factors impacting our estimated proved reserves, such as anticipated drilling and completion costs and our production results since December 31, 2016. There are also numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods. As such, this calculation is provided for illustrative purposes only and should not be construed as indicative of our final year-end reserve estimation process.

We consider future commodity prices when determining our development plan, but many other factors are also considered.  To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan. We plan to fund our development budget with a portion of the cash on hand at September 30, 2017, cash flows from operations, borrowings under our revolving credit facility, proceeds from asset sales, proceeds from the potential drilling joint venture, and proceeds from additional debt and/or equity offerings.

Results of Operations

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to our operations for the three months ended September 30, 2017 and 2016:

	Three Months Ended September 30,
	2017		2016		Change
Revenues (in thousands)
Natural gas sales	$	65,970	$	35,006	$	30,964
NGL sales		13,741		7,048		6,693
Oil sales		11,838		12,297		(459	)
Brokered natural gas and marketing revenue		—		128		(128	)
Total revenues	$	91,549	$	54,479	$	37,070

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Our production grew by approximately 12.1 Bcfe for the three months ended September 30, 2017 over the same period in 2016 due to new wells that we placed into production. Our production for the three months ended September 30, 2017 and 2016 is set forth in the following table:

	Three Months Ended September 30,
	2017		2016		Change
Production:
Natural gas (MMcf)		26,716.4		15,372.2		11,344.2
NGL sales (Mbbls)		675.6		525.5		150.1
Oil sales (Mbbls)		281.3		310.0		(28.7	)
Total (MMcfe)		32,457.8		20,385.2		12,072.6
Average daily production volume:
Natural gas (Mcf/d)		290,396		167,089		123,307
NGL sales (Bbls/d)		7,343		5,712		1,631
Oil sales (Bbls/d)		3,058		3,370		(312	)
Total (Mcfe/d)		352,802		221,575		131,227

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Our average realized price (including cash derivative settlements and firm third-party transportation costs) received during the three months ended September 30, 2017 was $2.59 per Mcfe compared to $2.51 per Mcfe during the three months ended September 30, 2016. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all derivative settlements and third-party firm transportation costs) calculation also includes all cash settlements for derivatives. Average sales price (excluding cash settled derivatives) does not include derivative settlements or third-party transportation costs which are reported in transportation, gathering and compression expense on the accompanying condensed consolidated statements of operations. Average sales price (excluding cash settled derivatives) does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the three months ended September 30, 2017 and 2016 are shown below:

	Three Months Ended September 30,
	2017		2016		Change
Average Sales Price (excluding cash settled derivatives    and firm transportation)
Natural gas ($/Mcf)	$	2.47	$	2.28	$	0.19
NGLs ($/Bbl)		20.34		13.41		6.93
Oil ($/Bbl)		42.08		39.67		2.41
Total average prices ($/Mcfe)		2.82		2.67		0.15
Average Sales Price (including cash settled derivatives,    excluding firm transportation)
Natural gas ($/Mcf)	$	2.55	$	2.50	$	0.05
NGLs ($/Bbl)		19.52		13.21		6.31
Oil ($/Bbl)		42.42		43.60		(1.18	)
Total average prices ($/Mcfe)		2.87		2.89		(0.02	)
Average Sales Price (including firm transportation,    excluding cash settled derivatives)
Natural gas ($/Mcf)	$	2.13	$	1.77	$	0.36
NGLs ($/Bbl)		20.34		13.41		6.93
Oil ($/Bbl)		42.08		39.67		2.41
Total average prices ($/Mcfe)		2.54		2.28		0.26
Average Sales Price (including cash settled derivatives    and firm transportation)
Natural gas ($/Mcf)	$	2.20	$	2.00	$	0.20
NGLs ($/Bbl)		19.52		13.21		6.31
Oil ($/Bbl)		42.42		43.60		(1.18	)
Total average prices ($/Mcfe)		2.59		2.51		0.08

Brokered natural gas and marketing revenue was $0.1 million for the three months ended September 30, 2016.  There was no Brokered natural gas and marketing revenue for the three months ended September 30, 2017.  Brokered natural gas and marketing revenue includes revenue received from selling natural gas not related to production and from the release of firm transportation capacity.  The decrease from the prior year period to the current year period was due to increased utilization of our firm transportation capacity for operated production during the three months ended September 30, 2017, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.  

30

Costs and Expenses

We believe some of our expense fluctuations are most accurately analyzed on a unit-of-production, or per Mcfe, basis. The following table presents these expenses for the three months ended September 30, 2017 and 2016:

	Three Months Ended September 30,
	2017		2016		Change
Operating Expenses (in thousands):
Lease operating	$	5,032	$	2,186	$	2,846
Transportation, gathering and compression		30,869		26,888		3,981
Production and ad valorem taxes		2,427		1,128		1,299
Depreciation, depletion and amortization		35,588		28,225		7,363
General and administrative		11,347		8,036		3,311
Operating Expenses per Mcfe:
Lease operating	$	0.16	$	0.11	$	0.05
Transportation, gathering and compression		0.95		1.32		(0.37	)
Production and ad valorem taxes		0.07		0.06		0.01
Depreciation, depletion and amortization		1.10		1.38		(0.28	)
General and administrative		0.35		0.39		(0.04	)

Lease operating expense was $5.0 million in the three months ended September 30, 2017 compared to $2.2 million in the three months ended September 30, 2016.  Lease operating expense per Mcfe was $0.16 in the three months ended September 30, 2017 compared to $0.11 in the three months ended September 30, 2016.  The increase of $2.8 million and $0.05 per Mcfe is attributable to an increase in the number of producing wells and salt water disposal expenses during the three months ended September 30, 2017, as compared to the three months ended September 30, 2016.  Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.  

Transportation, gathering and compression expense was $30.9 million during the three months ended September 30, 2017 compared to $26.9 million in the three months ended September 30, 2016.  Transportation, gathering and compression expense per Mcfe was $0.95 in the three months ended September 30, 2017 compared to $1.32 in the three months ended September 30, 2016.  The following table details our transportation, gathering and compression expenses for the three months ended September 30, 2017 and 2016:

	Three Months Ended September 30,
	2017		2016		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	12,949	$	9,323	$	3,626
Processing and fractionation		7,799		7,603		196
Liquids transportation and stabilization		1,005		2,123		(1,118	)
Marketing		6		6		—
Firm transportation		9,110		7,833		1,277
	$	30,869	$	26,888	$	3,981
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.40	$	0.47	$	(0.07	)
Processing and fractionation		0.24		0.37		(0.13	)
Liquids transportation and stabilization		0.03		0.10		(0.07	)
Marketing		—		—		—
Firm transportation		0.28		0.38		(0.10	)
	$	0.95	$	1.32	$	(0.37	)

The increase of $4.0 million to expenses in the three months ended September 30, 2017 was due to our production growth and increased firm transportation expenses, which increased primarily due to additional capacity that came online during the fourth quarter of 2016.  The decrease of $0.37 per Mcfe was primarily related to increased production associated with natural gas, lower contractual rates, and increased utilization of firm transportation capacity.

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Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $2.4 million in the three months ended September 30, 2017 compared to $1.1 million in the three months ended September 30, 2016. Production and ad valorem taxes per Mcfe was $0.07 in the three months ended September 30, 2017 compared to $0.06 in the three months ended September 30, 2016.  The increase in production and ad valorem taxes is due to increased production for the three months ended September 30, 2017.  The $0.01increase on a per unit basis is due to the change in commodity mix.

Depreciation, depletion and amortization was approximately $35.6 million in the three months ended September 30, 2017 compared to $28.2 million in the three months ended September 30, 2016. The increase in the three months ended September 30, 2017 when compared to the three months ended September 30, 2016 is due to the increase in production for the three months ended September 30, 2017.  On a per Mcfe basis, DD&A decreased to $1.10 in the three months ended September 30, 2017 from $1.38 in the three months ended September 30, 2016, which was predominantly driven by the lower depletion rate resulting from our increased reserves for the three months ended September 30, 2017.

General and administrative expense was $11.3 million for the three months ended September 30, 2017 compared to $8.0 million for the three months ended September 30, 2016.  General and administrative expense per Mcfe was $0.35 in the three months ended September 30, 2017 compared to $0.39 in the three months ended September 30, 2016.  The increase of $3.3 million during the three months ended September 30, 2017 when compared to three months ended September 30, 2016 was primarily due to higher salaries and benefits associated with increased headcount.  The decrease of $0.04 per Mcfe is due to fixed costs being spread across higher production as of September 30, 2017 as compared to September 30, 2016.  General and administrative expense includes $2.4 million and $1.8 million of stock-based compensation expense for the three months ended September 30, 2017 and 2016, respectively.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. The following table details our other operating expenses for the three months ended September 30, 2017 and 2016:

	Three Months Ended September 30,
	2017			2016			Change
Other Operating Expenses (in thousands):
Brokered natural gas and marketing expense	$	8		$	42		$	(34	)
Exploration		8,937			12,083			(3,146	)
Rig termination and standby		—			(112	)		112
Accretion of asset retirement obligations		143			100			43
(Gain) loss on sale of assets		(13	)		102			(115	)

Brokered natural gas and marketing expense was less than $0.1 million for each of the three months ended September 30, 2017 and 2016.  Brokered natural gas and marketing expenses relate to gas purchases that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties.  The decrease from the prior year period to the current year period was due to increased utilization of our firm transportation capacity for operated production during the three months ended September 30, 2017, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.

Exploration expense was $8.9 million for the three months ended September 30, 2017 compared to $12.1 million for the three months ended September 30, 2016. The following table details our exploration-related expenses for the three months ended September 30, 2017 and 2016:

	Three Months Ended September 30,
	2017		2016		Change
Exploration Expenses (in thousands):
Geological and geophysical	$	200	$	112	$	88
Delay rentals		3,723		2,286		1,437
Impairment of unproved properties		4,125		9,360		(5,235	)
Dry hole and other		889		325		564
	$	8,937	$	12,083	$	(3,146	)

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Delay rentals were $3.7 million for the three months ended September 30, 2017 compared to $2.3 million for the three months ended September 30, 2016.  The increase in delay rental expenses relates to converting future lump-sum extension payments into annual delay rentals.

Impairment of unproved properties was $4.1 million for the three months ended September 30, 2017 compared to $9.4 million for the three months ended September 30, 2016. The decrease in impairment charges during the three months ended September 30, 2017 is the result of a decrease in expected lease expirations due to the increase in our planned future drilling activity.  As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.

Accretion of asset retirement obligations was $0.1 million for the three months ended September 30, 2017 compared to $0.1 million for three months ended September 30, 2016. The accretion expense primarily relates to the asset retirement obligations associated with the number of producing wells.

Other Income (Expense)

Gain (loss) on derivative instruments was ($1.9) million for the three months ended September 30, 2017 compared to $10.6 million for the three months ended September 30, 2016, driven by changes in commodity prices during each year. Cash receipts were approximately $1.5 million and $4.6 million for derivative instruments that settled during the three months ended September 30, 2017 and September 30, 2016, respectively.

Interest expense, net was $12.0 million for the three months ended September 30, 2017 compared to $12.4 million for three months ended September 30, 2016.  Interest expense primarily relates to our senior unsecured notes and was relatively consistent during such periods.

Income tax benefit (expense) was not recognized for the three months ended September 30, 2017 and 2016 due to the Company reducing the valuation allowance to the extent of the tax effect of recorded pre-tax income and recording valuation allowance due to recurring pre-tax losses, respectively.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to our operations for the nine months ended September 30, 2017 and 2016:

	Nine Months Ended September 30,
	2017		2016		Change
Revenues (in thousands)
Natural gas sales	$	187,280	$	86,935	$	100,345
NGL sales		41,954		22,901		19,053
Oil sales		47,940		30,904		17,036
Brokered natural gas and marketing revenue		2,428		10,411		(7,983	)
Total revenues	$	279,602	$	151,151	$	128,451

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Our production grew by approximately 24.6 Bcfe for the nine months ended September 30, 2017 over the same period in 2016 as we placed new wells into production. Our production for the nine months ended September 30, 2017 and 2016 is set forth in the following table:

	Nine Months Ended September 30,
	2017		2016		Change
Production:
Natural gas (MMcf)		66,225.8		44,358.0		21,867.8
NGL sales (Mbbls)		2,002.7		1,725.1		277.6
Oil sales (Mbbls)		1,083.2		910.4		172.8
Total (MMcfe)		84,741.2		60,171.0		24,570.2
Average daily production volume:
Natural gas (Mcf/d)		242,585		161,891		80,694
NGL sales (Bbls/d)		7,336		6,296		1,040
Oil sales (Bbls/d)		3,968		3,323		645
Total (Mcfe/d)		310,409		219,605		90,804

During the nine months ended September 30, 2016, the Company was affected by revisions of prior estimates related to one of its non-operated partners that increased total net production by approximately 2.2 Bcfe, or 8 MMcfe per day, for such period.

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Our average realized price (including cash derivative settlements and firm third-party transportation costs) received during the nine months ended September 30, 2017 was $2.87 per Mcfe compared to $2.59 per Mcfe during the nine months ended September 30, 2016. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all derivative settlements and third-party firm transportation costs) calculation also includes all cash settlements for derivatives. Average sales price (excluding cash settled derivatives) does not include derivative settlements or third-party transportation costs which are reported in transportation, gathering and compression expense on the accompanying condensed consolidated statements of operations. Average sales price (excluding cash settled derivatives) does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the nine months ended September 30, 2017 and 2016 are shown below:

	Nine Months Ended September 30,
	2017		2016		Change
Average Sales Price (excluding cash settled derivatives    and firm transportation)
Natural gas ($/Mcf)	$	2.83	$	1.96	$	0.87
NGLs ($/Bbl)		20.95		13.28		7.67
Oil ($/Bbl)		44.26		33.95		10.31
Total average prices ($/Mcfe)		3.27		2.34		0.93
Average Sales Price (including cash settled derivatives,    excluding firm transportation)
Natural gas ($/Mcf)	$	2.78	$	2.57	$	0.21
NGLs ($/Bbl)		19.99		13.36		6.63
Oil ($/Bbl)		44.41		43.56		0.85
Total average prices ($/Mcfe)		3.21		2.94		0.27
Average Sales Price (including firm transportation,    excluding cash settled derivatives)
Natural gas ($/Mcf)	$	2.39	$	1.49	$	0.90
NGLs ($/Bbl)		20.95		13.28		7.67
Oil ($/Bbl)		44.26		33.95		10.31
Total average prices ($/Mcfe)		2.93		1.99		0.94
Average Sales Price (including cash settled derivatives    and firm transportation)
Natural gas ($/Mcf)	$	2.34	$	2.10	$	0.24
NGLs ($/Bbl)		19.99		13.36		6.63
Oil ($/Bbl)		44.41		43.56		0.85
Total average prices ($/Mcfe)		2.87		2.59		0.28

During the nine months ended September 30, 2016, the Company was affected by revisions of prior estimates related to one of its non-operated partners that decreased natural gas realized prices by approximately $0.09 per Mcf and increased NGL prices by $0.24 per Bbl for such period.

Brokered natural gas and marketing revenue was $2.4 million and $10.4 million for the nine months ended September 30, 2017 and 2016, respectively.  Brokered natural gas and marketing revenue includes revenue received from selling natural gas not related to production and from the release of firm transportation capacity.  The decrease from the prior year period to the current year period was due to increased utilization of our firm transportation capacity for operated production during the nine months ended September 30, 2017, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.  

35

Costs and Expenses

We believe some of our expense fluctuations are most accurately analyzed on a unit-of-production, or per Mcfe, basis. The following table presents these expenses for the nine months ended September 30, 2017 and 2016:

	Nine Months Ended September 30,
	2017		2016		Change
Operating Expenses (in thousands)
Lease operating	$	11,943	$	7,111	$	4,832
Transportation, gathering and compression		92,715		78,279		14,436
Production and ad valorem taxes		6,391		5,894		497
Depreciation, depletion and amortization		86,929		64,287		22,642
General and administrative		32,209		29,712		2,497
Operating Expenses per Mcfe:
Lease operating	$	0.14	$	0.12	$	0.02
Transportation, gathering and compression		1.10		1.30		(0.20	)
Production and ad valorem taxes		0.08		0.10		(0.02	)
Depreciation, depletion and amortization		1.03		1.07		(0.04	)
General and administrative		0.38		0.49		(0.11	)

Lease operating expense was $11.9 million in the nine months ended September 30, 2017 compared to $7.1 million in the nine months ended September 30, 2016. Lease operating expense per Mcfe was $0.14 in the nine months ended September 30, 2017 compared to $0.12 in the nine months ended September 30, 2016.  The increase of $4.8 million and $0.02 per Mcfe is attributable to an increase in the number of producing wells, salt water disposal expenses, and increased workover expenses during the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016.  Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.

Transportation, gathering and compression expense was $92.7 million during the nine months ended September 30, 2017 compared to $78.3 million in the nine months ended September 30, 2016.  Transportation, gathering and compression expense per Mcfe was $1.10 in the nine months ended September 30, 2017 compared to $1.30 in the nine months ended September 30, 2016.  The following table details our transportation, gathering and compression expenses for the nine months ended September 30, 2017 and 2016:

	Nine Months Ended September 30,
	2017		2016		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	34,860	$	28,633	$	6,227
Processing and fractionation		23,560		23,469		91
Liquids transportation and stabilization		5,011		5,461		(450	)
Marketing		25		3		22
Firm transportation		29,259		20,713		8,546
	$	92,715	$	78,279	$	14,436
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.41	$	0.48	$	(0.07	)
Processing and fractionation		0.28		0.39		(0.11	)
Liquids transportation and stabilization		0.06		0.09		(0.03	)
Marketing		—		0.00		—
Firm transportation		0.35		0.34		0.01
	$	1.10	$	1.30	$	(0.20	)

The increase of $14.4 million in the nine months ended September 30, 2017 was due to our production growth and increased firm transportation expenses, which increased primarily due to additional capacity that came online during the fourth quarter of 2016.  The decrease of $0.20 on a per unit basis was primarily related to our increased production associated with natural gas and lower contractual rates.

36

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $6.4 million in the nine months ended September 30, 2017 compared to $5.9 million in the nine months ended September 30, 2016. Production and ad valorem taxes per Mcfe was $0.08 in the nine months ended September 30, 2017 compared to $0.10 in the nine months ended September 30, 2016.  The increase in production and ad valorem taxes in total is related to increased well count.  The decrease in production and ad valorem taxes on a per unit basis is due to the lower taxable value rate for the nine months ended September 30, 2017.

Depreciation, depletion and amortization was approximately $86.9 million in the nine months ended September 30, 2017 compared to $64.3 million in the nine months ended September 30, 2016. The increase in the nine months ended September 30, 2017 when compared to the nine months ended September 30, 2016 is due to the increase in production and proved property costs during the nine months ended September 30, 2017. On a per Mcfe basis, DD&A decreased to $1.03 in the nine months ended September 30, 2017 from $1.07 in the nine months ended September 30, 2016, which was predominantly driven by the lower depletion rate resulting from our increased reserves during the nine months ended September 30, 2017.

General and administrative expense was $32.2 million for the nine months ended September 30, 2017 compared to $29.7 million for the nine months ended September 30, 2016.  General and administrative expense per Mcfe was $0.38 in the nine months ended September 30, 2017 compared to $0.49 in the nine months ended September 30, 2016.  The increase of $2.5 million and decrease of $0.11 per Mcfe during the nine months ended September 30, 2017 when compared to nine months ended September 30, 2016 was due higher salaries and benefits associated with increased headcount and fixed costs spread across increased production as of September 30, 2017 as compared to September 30, 2016, respectively.  General and administrative expense includes $6.9 million and $5.5 million of stock-based compensation expense for the nine months ended September 30, 2017 and 2016, respectively.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. The following table details our other operating expenses for the nine months ended September 30, 2017 and 2016:

	Nine Months Ended September 30,
	2017			2016			Change
Other Operating Expenses (in thousands):
Brokered natural gas and marketing expense	$	2,474		$	11,604		$	(9,130	)
Exploration		29,514			45,183			(15,669	)
Rig termination and standby		—			3,843			(3,843	)
Impairment of proved oil and natural gas properties		—			17,665			(17,665	)
Accretion of asset retirement obligations		395			275			120
(Gain) loss on sale of assets		(12	)		(944	)		932

Brokered natural gas and marketing expense was $2.5 million for the nine months ended September 30, 2017 compared to $11.6 million for the nine months ended September 30, 2016.  Brokered natural gas and marketing expenses relate to gas purchases that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties.  The decrease from the prior year period to the current year period was due to increased utilization of our firm transport capacity for operated production during the nine months ended September 30, 2017, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.  

Exploration expense was $29.5 million for the nine months ended September 30, 2017 compared to $45.2 million for the nine months ended September 30, 2016. The following table details our exploration-related expenses for the nine months ended September 30, 2017 and 2016:

	Nine Months Ended September 30,
	2017		2016		Change
Exploration Expenses (in thousands):
Geological and geophysical	$	979	$	528	$	451
Delay rentals		14,329		15,703		(1,374	)
Impairment of unproved properties		12,375		28,080		(15,705	)
Dry hole and other		1,831		872		959
	$	29,514	$	45,183	$	(15,669	)

37

Delay rentals were $14.3 million for the nine months ended September 30, 2017 compared to $15.7 million for the nine months ended September 30, 2016.  The decrease in delay rental expenses relates to the reduction of converting future lump-sum extension payments into annual delay rentals and increased drilling activity during the current year period.

Impairment of unproved properties was $12.4 million for the nine months ended September 30, 2017 compared to $28.1 million for the nine months ended September 30, 2016. The decrease in impairment charges during the nine months ended September 30, 2017 is the result of a decrease in expected lease expirations due to the increase in our planned future drilling activity. As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.

Rig termination and standby expense for the nine months ended September 30, 2016 were $3.8 million related primarily to standby costs that we incurred from temporarily suspending our drilling operations for a portion of such period.  There were no rig termination and standby expenses for the nine months ended September 30, 2017.

Impairment of proved oil and gas properties was $17.7 million for the nine months ended September 30, 2016.  There was no impairment of proved oil and gas properties recognized for the nine months ended September 30, 2017.

Accretion of asset retirement obligations was $0.4 million for the nine months ended September 30, 2017 compared to $0.3 million for nine months ended September 30, 2016. The accretion expense primarily relates to the asset retirement obligations associated with the number of producing wells.

Other Income (Expense)

Gain (loss) on derivative instruments was $41.4 million for the nine months ended September 30, 2017 compared to ($8.4) million for the nine months ended September 30, 2016, driven by changes in commodity prices during each year. Cash payments were approximately $5.0 million and cash receipts were approximately $35.9 million for derivative instruments that settled during the nine months ended September 30, 2017 and September 30, 2016, respectively.

Interest expense, net was $36.8 million for the nine months ended September 30, 2017 compared to $38.3 million for nine months ended September 30, 2016. The decrease in interest expense was primarily due to the early extinguishment of debt during the nine months ended September 30, 2016.

Gain on early extinguishment of debt was $14.5 million for the nine months ended September 30, 2016 resulting from the repurchase of $39.5 million of our outstanding senior unsecured notes on the open market for $23.4 million during such period. The outstanding senior unsecured notes principal repurchased less cash proceeds and unamortized debt discount and deferred financing costs of $1.6 million were charged to gain on early extinguishment of debt.  No gain or loss on early extinguishment of debt was recognized for the nine months ended September 30, 2017.

Income tax benefit (expense) was ($0.5) million for the nine months ended September 30, 2016 related to the write-off of certain state deferred tax assets.  No income tax expense was recorded for the nine months ended September 30, 2017 due to the Company reducing the valuation allowance to the extent of the tax effect of recorded pre-tax income.

Cash Flows, Capital Resources and Liquidity

Cash Flows

Cash flows from operations are primarily affected by production volumes and commodity prices. Our cash flows from operations also are impacted by changes in working capital. Short-term liquidity needs are satisfied by our operating cash flow, proceeds from asset sales, borrowings under our revolving credit facility, proceeds from the potential drilling joint venture, and proceeds from issuances of debt and equity securities.

Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016

Net cash provided by (used in) operations in the nine months ended September 30, 2017 was $87.2 million compared to ($28.5) million in the nine months ended September 30, 2016. The increase in cash provided from operating activities reflects the increase in our production and commodity prices during the year-over-year comparative periods, working capital changes, and the timing of cash receipts and disbursements.

38

Net cash used in investing activities in the nine months ended September 30, 2017 was $255.7 million compared to $78.2 million in the nine months ended September 30, 2016.

During the nine months ended September 30, 2017, we:

• spent $254.4 million on capital expenditures for oil and natural gas properties;

• spent $1.9 million on property and equipment; and

• received $0.6 million of proceeds relating to the sale of assets.

During the nine months ended September 30, 2016, we:

• spent $92.2 million on capital expenditures for oil and gas properties;

• spent $0.9 million on property and equipment; and

• received $14.9 million of proceeds relating to the sale of assets.

Net cash provided by (used in) financing activities in the nine months ended September 30, 2017 was ($3.9) million compared to $99.9 million in the nine months ended September 30, 2016.

During the nine months ended September 30, 2017, we:

• paid $1.6 million in financing costs associated with an amendment to the Credit Agreement governing our revolving credit facility that, among other things, increased our borrowing base under such revolving credit facility; and

• paid $2.0 million to repurchase stock in relation to tax withholding for settlement of equity compensation awards.

During the nine months ended September 30, 2016, we:

• purchased outstanding senior unsecured notes with aggregate principal amount of $39.5 million for $23.4 million; and

• successfully completed a public offering of 37,500,000 shares of common stock for approximately $123 million of net proceeds.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, asset sales, borrowings under our revolving credit facility and access to the debt and equity capital markets. We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs which require substantial capital expenditures. We periodically review capital expenditures and adjust our budget based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. We believe that our existing cash on hand, operating cash flow and available borrowings under our revolving credit facility will be adequate to meet our capital and operating requirements for 2017.

Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We will continue using net cash on hand, cash flows from operations, and borrowings under our revolving credit facility to satisfy near-term financial obligations and liquidity needs, and as necessary, we will seek additional sources of debt or equity to fund these requirements. Longer-term cash flows are subject to a number of variables including the level of production and prices we receive for our production as well as various economic conditions that have historically affected the natural gas and oil business. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

As of September 30, 2017, we were in compliance with all of our debt covenants under the credit agreement governing our revolving credit facility and the indenture governing our 8.875% senior unsecured notes due 2023. Further, based on our current forecast and activity levels, we expect to remain in compliance with all such debt covenants for the next twelve months. However, if oil and natural gas prices decrease to lower levels, we are likely to generate lower operating cash flows, which would make it more difficult for us to remain in compliance with all of our debt covenants, including requirements with respect to working capital and interest coverage ratios. This could negatively impact our ability to maintain sufficient liquidity and access to capital resources.

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Credit Arrangements

Long-term debt at September 30, 2017 and December 31, 2016, excluding discount, totaled $510.5 million. (See Note 7—Debt).

On July 6, 2015, we issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of the principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, we received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which we used approximately $510.7 million to finance the redemption of all of our outstanding 12.0% Senior PIK notes due 2018. We used the remaining net proceeds to fund our capital expenditure plan and for general corporate purposes. (See Note 7—Debt).

During the nine months ended September 30, 2016, the Company repurchased $39.5 million of the outstanding senior unsecured notes in open market purchases for $23.4 million. The outstanding principal of the senior unsecured notes that were repurchased less cash proceeds and unamortized debt discount and deferred financing costs of $1.6 million were charged to gain on early extinguishment of debt, totaling $14.5 million. 

The indenture governing our senior unsecured notes contains covenants that, among other things, limit the ability of our restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. We were in compliance with all applicable covenants in the indenture at September 30, 2017.

We have also entered into a $500 million revolving credit facility, which is governed by a Credit Agreement that includes customary affirmative and negative covenants. In February 2017, we entered into an amendment to the Credit Agreement governing our revolving credit facility that increased the borrowing base under such facility from $125 million to $175 million and extended the maturity date from January 2018 to February 2020.  In August 2017, we entered into an additional amendment that increased the borrowing base from $175 million to $225 million.  As of September 30, 2017, the borrowing base was $225 million and we had no outstanding borrowings under our revolving credit facility.  After giving effect to our outstanding letters of credit, totaling $33.6 million, we had available borrowing capacity under our revolving credit facility of $191.4 million.  Subsequent to September 30, 2017, we borrowed $15 million under our revolving credit facility, which reduced the available borrowing capacity to $176.4 million.  Our next scheduled borrowing base redetermination is expected to be completed by April 2018.  We were in compliance with all applicable covenants in the Credit Agreement at September 30, 2017.

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas, NGLs and oil production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas, NGLs and oil production. Pricing for natural gas, NGLs and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in natural gas, NGLs and oil prices, we may enter into financial commodity derivative contracts to ensure that we receive minimum prices for a portion of our future natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas and the WTI price for oil.

Our hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor

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price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, zero cost collars that set a floor and ceiling price for the hedged production, and puts which require us to pay a premium either up front or at settlement and allow us to receive a fixed price at our option if the put price is above the market price. As of September 30, 2017, we had entered into the following derivative contracts:

Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		10,000	October 2017 – December 2017	$	2.98
		10,000	October 2017 – December 2017	$	3.21
		30,000	October 2017 – March 2018	$	3.46
Natural Gas Three-way Collars:
Floor purchase price (put)		160,000	October 2017 – December 2017	$	2.83
Ceiling sold price (call)		160,000	October 2017 – December 2017	$	3.37
Floor sold price (put)		160,000	October 2017 – December 2017	$	2.31
Floor purchase price (put)		30,000	October 2017 – March 2019	$	3.00
Ceiling sold price (call)		30,000	October 2017 – March 2019	$	3.40
Floor sold price (put)		20,000	October 2017 – March 2019	$	2.40
Floor sold price (put)		10,000	October 2017 – March 2019	$	2.20
Floor purchase price (put)		40,000	October 2017 – December 2018	$	2.90
Ceiling sold price (call)		40,000	October 2017 – December 2018	$	3.38
Floor sold price (put)		40,000	October 2017 – December 2018	$	2.30
Floor purchase price (put)		60,000	January 2018 – March 2018	$	2.90
Ceiling sold price (call)		60,000	January 2018 – March 2018	$	3.75
Floor sold price (put)		60,000	January 2018 – March 2018	$	2.40
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.90
Ceiling sold price (call)		60,000	April 2018 – December 2018	$	3.25
Floor sold price (put)		60,000	April 2018 – December 2018	$	2.40
Floor purchase price (put)		60,000	January 2018 – December 2018	$	2.80
Ceiling sold price (call)		60,000	January 2018 – December 2018	$	3.35
Floor sold price (put)		60,000	January 2018 – December 2018	$	2.33
Natural Gas Call/Put Options:
Call sold		40,000	January 2018 – December 2018	$	3.75
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
TCO - Columbia		20,000	October 2017 – December 2017	$	(0.19	)
Appalachia - Dominion		80,000	October 2017 – November 2017	$	(1.02	)
Appalachia - Dominion		50,000	December 2017	$	(0.56	)
Appalachia - Dominion		50,000	January 2018 – March 2018	$	(0.43	)
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)

Oil Derivatives

Description	Volume (Bbls/d)		Production Period	WeightedAverage Price($/Bbl)
Oil Three-way Collars:
Floor purchase price (put)		2,000	October 2017 – December 2017	$	46.00
Ceiling sold price (call)		2,000	October 2017 – December 2017	$	60.00
Floor sold price (put)		2,000	October 2017 – December 2017	$	38.00

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NGL Derivatives

Description	Volume (Gal/d)		Production Period	Weighted Average Price ($/Gal)
Propane Swaps:
		84,000	October 2017 – December 2017	$	0.60

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with Bank of Montreal, Citibank, Goldman Sachs, Morgan Stanley, Capital One N.A., BP Energy Company and KeyBank N.A. We believe all of such institutions currently are an acceptable credit risk. As of September 30, 2017, we did not have any past due receivables from such counterparties.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at September 30, 2017. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $17.1 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $19.3 million. A hypothetical 10 percent decrease in future oil prices would increase future earnings related to derivatives by $5.0 million. Similarly, a hypothetical 10 percent increase in future oil prices would decrease future earnings related to derivatives by $5.7 million.

Capital Requirements

Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties and repayment of principal and interest on outstanding debt. Our board of directors approved an initial capital budget for 2017 of approximately $300 million.  The budget includes approximately $261 million for drilling and completions activities, $33 million for land activities and $6 million for other capital requirements.  In addition to these amounts, we expect to spend approximately $17 million during 2017 related to leases that were signed during 2016.  The 2017 Capital Budget is expected to be substantially funded through internally generated cash flows and the Company’s current cash balance.  The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas, NGLs and oil prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in natural gas, NGLs or oil prices from current levels may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production and our proved reserves as well as our ability to maintain compliance with our debt covenants. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets.

In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our revolving credit agreement and other factors.

Capitalization

As of September 30, 2017 and December 31, 2016, our total debt, excluding debt discount, and capitalization were as follows (in millions):

	September 30, 2017		December 31, 2016
Senior unsecured notes	$	510.5	$	510.5
Stockholders' equity		583.0		556.6
Total capitalization	$	1,093.5	$	1,067.1

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Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering, and compressions services and asset retirement obligations. As of September 30, 2017 and December 31, 2016, we did not have any capital leases, any significant off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed any debt of any unrelated party. Our condensed consolidated balance sheet at September 30, 2017 reflects accrued interest payable of $10.0 million, compared to $21.1 million as of December 31, 2016.

Other

We lease acreage that is generally subject to lease expiration if operations are not commenced within a specified period, generally five years. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Interest Rates

At September 30, 2017 and December 31, 2016, we had $510.5 million of senior unsecured notes outstanding, excluding discounts, which bear interest at a fixed cash rate of 8.875% and is due semi-annually from the date of issuance.

In February 2014, we entered into a $500 million senior secured revolving bank credit facility. Borrowings under our revolving credit facility are subject to borrowing base limitations based on the collateral value of our proved properties and commodity hedge positions and are subject to semiannual redeterminations. In February 2017, we entered into an amendment to the Credit Agreement governing our revolving credit facility that increased the borrowing base under such facility from $125 million to $175 million and extended the maturity date of such facility from January 2018 to February 2020.  In August 2017, we entered into an additional amendment that increased the borrowing base from $175 million to $225 million.  As of September 30, 2017, the borrowing base was $225 million and we had no outstanding borrowings under our revolving credit facility. After giving effect to our outstanding letters of credit, totaling $33.6 million, we had available borrowing capacity under our revolving credit facility of $191.4 million.  Subsequent to September 30, 2017, we borrowed $15 million under our revolving credit facility, which reduced the available borrowing capacity to $176.4 million.  Our next scheduled borrowing base redetermination is expected to be completed by April 2018.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments which are described above under “—Cash Contractual Obligations.”

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, it does not normally have a significant effect on our business. We expect our costs in fiscal 2017 to continue to be a function of supply and demand.  Further strengthening of commodity prices could stimulate demand for ancillary services causing services costs to increase.  In the near term, the majority of our service costs are expected to remain flat in 2017 due to previously negotiated drilling, stimulation, and rentals contracts.  Along with these contracts, we have secured quality service equipment and tenured personnel to limit our exposure to increasing service costs and improve operational efficacies.  

Non-GAAP Financial Measure

“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; DD&A; amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items set forth in the table below. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or

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loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

• is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

• helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

• is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under the Credit Agreement governing the revolving credit facility and the indenture governing the senior unsecured notes.

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss) from operations to Adjusted EBITDAX for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
$ thousands	2017			2016				2017		2016
Net income (loss)	$	(16,694	)	$	(25,949	)	$	21,647		$	(144,646	)
Depreciation, depletion and amortization		35,588			28,225			86,929			64,287
Exploration expense		8,937			12,083			29,514			45,183
Rig termination and standby		—			(112	)		—			3,843
Impairment of proved oil and gas properties		—			—			—			17,665
Stock-based compensation		2,428			1,764			6,857			5,464
Accretion of asset retirement obligations		143			100			395			275
(Gain) loss on derivative instruments		1,889			(10,639	)		(41,385	)		8,407
Net cash receipts (payments) on settled derivatives		1,585			4,612			(5,048	)		35,870
Interest expense, net		12,016			12,393			36,763			38,293
(Gain) loss on sale of assets		(13	)		102			(12	)		(944	)
(Gain) loss on early extinguishment of debt		—			—			—			(14,489	)
Other (income) expense		—			(4	)		19			137
Income tax (benefit) expense		—			—			—			540
Adjusted EBITDAX	$	45,879		$	22,575		$	135,679		$	59,885

Critical Accounting 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 U.S. GAAP. 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 Annual Report on Form 10-K for further discussion of our critical accounting policies.

Recent Accounting Pronouncements

The Company’s critical accounting policies are described in Note 3 – Summary of Significant Accounting Policies of the consolidated financial statements for the year ended December 31, 2016 contained in the Company’s Annual Report on Form 10-K. Information related to recent accounting pronouncements is described in Note 3 to our condensed consolidated financial statements and is incorporated herein by reference.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 82% of our December 31, 2016 proved reserves were natural gas.

For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, see “Note 5—Derivative Instruments.”

Interest Rate Risk

On July 6, 2015, we issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of the principal amount of the senior unsecured notes, plus accrued and unpaid interest, if any. At September 30, 2017, the cash interest rate with respect to the senior unsecured notes was fixed at 8.875%, and interest is due semi-annually from the date of issuance in January and July.

We will be exposed to interest rate risk in the future if we draw on our revolving credit facility. Interest on outstanding borrowings under our revolving credit facility will accrue based on, at our option, LIBOR or the alternate base rate, in each case, plus an applicable margin that is determined based on our utilization of commitments under our revolving credit facility. In August 2017, we entered into an additional amendment that increased the borrowing base from $175 million to $225 million.  As of September 30, 2017, the borrowing base was $225 million and we had no outstanding borrowings under our revolving credit facility.  After giving effect to our outstanding letters of credit, totaling $33.6 million, we had available borrowing capacity under our revolving credit facility of $191.4 million.  Subsequent to September 30, 2017, we borrowed $15 million under our revolving credit facility, which reduced the available borrowing capacity to $176.4 million.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts, the sale of our oil and gas production which we market to energy companies, end users and refineries, and joint interest receivables.

We are exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to periodic review. We have not experienced any issues of nonperformance by derivative counterparties. We believe that all of these institutions currently are acceptable credit risks. Other than as provided by our revolving credit facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of September 30, 2017, we did not have past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

We are also subject to credit risk due to concentration of our receivables from several significant customers for sales of natural gas. We, generally, do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s management carried out an evaluation (as required by Rule 13a-15(b) of the Exchange Act), with the participation of the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon this evaluation, the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q, such that the information relating to the Company and its consolidated subsidiaries required to be disclosed by the Company in the reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) during the period covered by this Quarterly Report that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Information regarding the Company’s legal proceedings is set forth in “Note 13—Commitments and Contingencies,” located in the Notes to the Condensed Consolidated Financial Statements included in Part I Item 1 of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, including the risk factor set forth below, you should carefully consider the factors discussed in “Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March 3, 2017, which could materially affect our business, financial condition, and/or future results. The risks described in our Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.

We may be unable to successfully negotiate or enter into definitive agreements regarding our proposed joint development transaction with Sequel Energy Group LLC, or to effectively implement that transaction, which failures could negatively affect our future financial performance or cause the market price of our securities to decline.

On August 1, 2017, we entered into an agreement and term sheet (collectively, the “Sequel Agreement”) with Sequel Energy Group LLC, a Delaware limited liability company, relating to the potential joint development of certain oil, gas and mineral interest assets we own in the Utica Shale in southeast Ohio within the counties of Harrison, Guernsey, Belmont, and Monroe.  The development plans set forth in those agreements will represent a significant portion of our development plans for our mineral interest assets for the next two to three years. Although the Sequel Agreement sets forth the material terms of the proposed transaction, it does not obligate either party to consummate such transaction. Rather, it requires the parties to negotiate in good faith for a period of time and to use their commercially reasonable efforts to document and enter into mutually agreeable definitive agreements relating to the proposed transaction. We cannot assure you that such negotiations will be successful, that we will enter into these definitive agreements and, if we do, what will be the final terms of such agreements.  Additionally, each party’s obligation to enter into these definitive agreements is subject to various conditions, including, without limitation, that all necessary consents and approvals have been received from applicable third parties and that no material adverse change has occurred with respect to the Company. Moreover, even if we do enter into definitive agreements, those agreements may require the parties to satisfy these and other conditions before the proposed transaction may be consummated. We cannot assure you as to when these conditions to proposed transaction will be satisfied or waived by the appropriate party, if at all. As a result, we cannot assure you that we will consummate this proposed transaction. If we are unable to successfully negotiate and enter into the definitive agreements or if we otherwise fail to consummate the proposed transaction, or if we are unable to effectively execute the terms of the definitive agreements, we may not be able to successfully develop a significant portion of our mineral interests or we may be forced to utilize more costly financing methods to do so.  Such failures could materially and adversely impact our future financial performance, our reputation and our prospects for capital in the future, which may cause investors to lose confidence in us and our strategies, and as a result, could cause the market price of our securities to decline.

Item 6. Exhibits

See the list of exhibits in the index to exhibits to this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

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ECLIPSE RESOURCES CORPORATION

INDEX TO EXHIBITS

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation of Eclipse Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2014).
3.2	Amended and Restated Bylaws of Eclipse Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2014).
4.1	Stockholders Agreement, dated June 25, 2014, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P. and Eclipse Management, L.P. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 30, 2014).
4.2	Amended and Restated Registration Rights Agreement, dated January 28, 2015, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Eclipse Management, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l., Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 29, 2015).
4.3	Indenture, dated as of July 6, 2015, between Eclipse Resources Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2015).
10.1	Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2017, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 1, 2017).
10.2†	Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Benjamin W. Hulburt (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).
10.3†	Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Matthew R. DeNezza (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).
10.4†	Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Christopher K. Hulburt (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certifications of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certifications of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.

48

Exhibit No.	Description
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* Filed herewith.

** These exhibits are furnished herewith and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.

† Management contract.

49

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.

November 9, 2017	ECLIPSE RESOURCES CORPORATION (Registrant)
	/s/ Benjamin W. Hulburt
	Benjamin W. Hulburt,
	Chairman, President and Chief Executive Officer
	/s/ Matthew R. DeNezza
	Matthew R. DeNezza,
	Executive Vice President and Chief Financial Officer

50

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Benjamin W. Hulburt, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Eclipse Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 9, 2017

/s/ Benjamin W. Hulburt

Benjamin W. Hulburt

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Matthew R. DeNezza, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Eclipse Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 9, 2017

/s/ Matthew R. DeNezza

Matthew R. DeNezza

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of Eclipse Resources Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Benjamin W. Hulburt, Chairman, President and Chief Executive Officer of the Company hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	ECLIPSE RESOURCES CORPORATION.
November 9, 2017	/s/ Benjamin W. Hulburt
	Benjamin W. Hulburt
	Chairman, President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of Eclipse Resources Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Matthew R. DeNezza, Executive Vice President and Chief Financial Officer of the Company hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	ECLIPSE RESOURCES CORPORATION.
November 9, 2017	/s/ Matthew R. DeNezza
	Matthew R. DeNezza
	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 09, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Trading Symbol	ECR
Entity Registrant Name	Eclipse Resources Corp
Entity Central Index Key	0001600470
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		262,740,355

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 28,795	$ 201,229
Accounts receivable	40,553	44,423
Assets held for sale	426	468
Other current assets	6,959	4,295
Total current assets	76,733	250,415
Oil and natural gas properties, successful efforts method:
Unproved properties	488,260	526,270
Proved oil and gas properties, net	636,023	414,482
Other property and equipment, net	7,190	6,748
Total property and equipment, net	1,131,473	947,500
OTHER NONCURRENT ASSETS
Other assets	2,040	729
TOTAL ASSETS	1,210,246	1,198,644
CURRENT LIABILITIES
Accounts payable	69,914	44,049
Accrued capital expenditures	19,319	11,083
Accrued liabilities	24,981	55,044
Accrued interest payable	9,973	21,098
Liabilities held for sale	189	245
Total current liabilities	124,376	131,519
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs	494,332	492,278
Asset retirement obligations	5,766	4,806
Other liabilities	2,740	13,434
Total liabilities	627,214	642,037
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, 50,000,000 authorized, no shares issued and outstanding
Common stock, $0.01 par value, 1,000,000,000 authorized, 262,740,355 and 260,591,893 shares issued and outstanding, respectively	2,637	2,607
Additional paid in capital	1,965,514	1,958,731
Treasury stock, shares at cost; 992,315 and 72,704 shares, respectively	(2,096)	(61)
Accumulated deficit	(1,383,023)	(1,404,670)
Total stockholders' equity	583,032	556,607
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 1,210,246	$ 1,198,644

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	262,740,355	260,591,893
Common stock, shares outstanding	262,740,355	260,591,893
Treasury stock, shares	992,315	72,704

XML

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited) - USD ($) shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES
Natural gas, oil and natural gas liquids sales	$ 91,549,000	$ 54,351,000	$ 277,174,000	$ 140,740,000
Brokered natural gas and marketing revenue		128,000	2,428,000	10,411,000
Total revenues	91,549,000	54,479,000	279,602,000	151,151,000
OPERATING EXPENSES
Lease operating	5,032,000	2,186,000	11,943,000	7,111,000
Transportation, gathering and compression	30,869,000	26,888,000	92,715,000	78,279,000
Production and ad valorem taxes	2,427,000	1,128,000	6,391,000	5,894,000
Brokered natural gas and marketing expense	8,000	42,000	2,474,000	11,604,000
Depreciation, depletion and amortization	35,588,000	28,225,000	86,929,000	64,287,000
Exploration	8,937,000	12,083,000	29,514,000	45,183,000
General and administrative	11,347,000	8,036,000	32,209,000	29,712,000
Rig termination and standby		(112,000)		3,843,000
Impairment of proved oil and gas properties				17,665,000
Accretion of asset retirement obligations	143,000	100,000	395,000	275,000
(Gain) loss on sale of assets	(13,000)	102,000	(12,000)	(944,000)
Total operating expenses	94,338,000	78,678,000	262,558,000	262,909,000
OPERATING INCOME (LOSS)	(2,789,000)	(24,199,000)	17,044,000	(111,758,000)
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments	(1,889,000)	10,639,000	41,385,000	(8,407,000)
Interest expense, net	(12,016,000)	(12,393,000)	(36,763,000)	(38,293,000)
Gain (loss) on early extinguishment of debt				14,489,000
Other income (expense)		4,000	(19,000)	(137,000)
Total other income (expense), net	(13,905,000)	(1,750,000)	4,603,000	(32,348,000)
INCOME (LOSS) BEFORE INCOME TAXES	(16,694,000)	(25,949,000)	21,647,000	(144,106,000)
INCOME TAX BENEFIT (EXPENSE)			0	(540,000)
NET INCOME (LOSS)	$ (16,694,000)	$ (25,949,000)	$ 21,647,000	$ (144,646,000)
NET INCOME (LOSS) PER COMMON SHARE
Basic	$ (0.06)	$ (0.10)	$ 0.08	$ (0.62)
Diluted	$ (0.06)	$ (0.10)	$ 0.08	$ (0.62)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	262,586	258,812	262,044	234,933
Diluted	262,586	258,812	264,717	234,933

XML

Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - 9 months ended Sep. 30, 2017 - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Accumulated Deficit [Member]
Beginning Balances at Dec. 31, 2016	$ 556,607	$ 2,607	$ 1,958,731	$ (61)	$ (1,404,670)
Beginning Balance, shares at Dec. 31, 2016		260,591,893
Stock-based compensation	6,857		6,857
Equity issuance costs	(44)		(44)
Issuance of restricted stock		$ 2	(2)
Issuance of restricted stock, shares		153,192
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	(2,035)	$ 28	(28)	(2,035)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares		1,995,270
Net income	21,647				21,647
Ending Balances at Sep. 30, 2017	$ 583,032	$ 2,637	$ 1,965,514	$ (2,096)	$ (1,383,023)
Ending Balance, shares at Sep. 30, 2017		262,740,355

XML

Condensed Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
Statement Of Stockholders Equity [Abstract]
Common stock, par value	$ 0.01	$ 0.01

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($)	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 21,647,000	$ (144,646,000)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion and amortization	86,929,000	64,287,000
Exploration expense	14,206,000	28,952,000
Stock-based compensation	6,857,000	5,464,000
Impairment of proved oil and gas properties		17,665,000
Accretion of asset retirement obligations	395,000	275,000
(Gain) loss on derivative instruments	(41,385,000)	8,407,000
Net cash receipts (payments) on settled derivatives	(5,048,000)	35,870,000
(Gain) loss on sale of assets	(12,000)	(944,000)
(Gain) loss on early extinguishment of debt		(14,489,000)
Deferred income taxes	0	540,000
Amortization of deferred financing costs	1,553,000	1,457,000
Amortization of debt discount	992,000	1,033,000
Changes in operating assets and liabilities:
Accounts receivable	4,357,000	(1,797,000)
Other assets	56,000	(1,902,000)
Accounts payable and accrued liabilities	(3,344,000)	(28,659,000)
Net cash provided by (used in) operating activities	87,203,000	(28,487,000)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties	(254,353,000)	(92,204,000)
Capital expenditures for other property and equipment	(1,901,000)	(852,000)
Proceeds from sale of assets	551,000	14,887,000
Net cash used in investing activities	(255,703,000)	(78,169,000)
CASH FLOWS FROM FINANCING ACTIVITIES
Debt issuance costs	(1,657,000)	40,000
Repayments of long-term debt	(198,000)	(23,936,000)
Proceeds from issuance of common stock		124,361,000
Equity issuance costs	(44,000)	(484,000)
Employee tax withholding for settlement of equity compensation awards	(2,035,000)	(61,000)
Net cash provided by (used in) financing activities	(3,934,000)	99,920,000
Net decrease in cash and cash equivalents	(172,434,000)	(6,736,000)
Cash and cash equivalents at beginning of period	201,229,000	184,405,000
Cash and cash equivalents at end of period	28,795,000	177,669,000
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	46,638,000	48,101,000
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	565,000	923,000
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures	$ 27,125,000	$ 26,055,000

XML

Organization and Nature of Operations

9 Months Ended

Sep. 30, 2017

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Organization and Nature of Operations

Note 1—Organization and Nature of Operations

Eclipse Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas.

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Basis of Presentation

Note 2—Basis of Presentation

The accompanying condensed consolidated financial statements are unaudited except the condensed consolidated balance sheet at December 31, 2016, which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. All such adjustments are of a normal recurring nature.  These interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements, and the notes to those statements, which are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2017.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2017 or any other future periods.

Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the condensed consolidated financial statements are the following:

• estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion and amortization and impairment of capitalized costs of oil and natural gas properties;

• estimates of asset retirement obligations;

• estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;

• impairment of undeveloped properties and other assets; and

• depreciation and depletion of property and equipment.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

XML

Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of September 30, 2017 or December 31, 2016.

The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $37.8 million and $41.4 million of accrued revenues, net of certain expenses, at September 30, 2017 and December 31, 2016, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets.

(c) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, Depletion and Amortization” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s consolidated statements of operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

	September 30, 2017			December 31, 2016
Oil and natural gas properties:
Unproved	$	488,260		$	526,270
Proved		1,852,828			1,545,860
Gross oil and natural gas properties		2,341,088			2,072,130
Less accumulated depreciation, depletion and amortization		(1,216,805	)		(1,131,378	)
Oil and natural gas properties, net		1,124,283			940,752
Other property and equipment		13,333			11,447
Less accumulated depreciation		(6,143	)		(4,699	)
Other property and equipment, net		7,190			6,748
Property and equipment, net	$	1,131,473		$	947,500

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

The Company capitalized interest expense totaling $0.9 million and $0.4 million for the three months ended September 30, 2017 and 2016, respectively.  The Company capitalized interest expense totaling $1.8 million and $0.8 million for the nine months ended September 30, 2017 and 2016, respectively.

Other Property and Equipment

Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

(d) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of September 30, 2017 or December 31, 2016.

In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.

Brokered natural gas and marketing revenues include revenues from brokered gas or revenue the Company receives as a result of selling and buying natural gas that is not related to its production and revenue from the release of transportation capacity. The Company realizes brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. The Company considers these activities as ancillary to its natural gas sales and thus, reports them within one operating segment.

(e) Concentration of Credit Risk

The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of September 30, 2017 and December 31, 2016 (in thousands):

	September 30, 2017		December 31, 2016
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	37,845	$	41,398
Joint interest owners		2,076		2,850
Derivatives		609		122
Other		23		53
Total	$	40,553	$	44,423

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s unsettled commodity derivative contracts was a net liability position of ($5.5) million and ($48.1) million at September 30, 2017 and December 31, 2016, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are such counterparties required to provide credit support to the Company. As of September 30, 2017 and December 31, 2016, the Company did not have past-due receivables from or payables to any of such counterparties.

(f) Depreciation, Depletion and Amortization

Oil and Natural Gas Properties

Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties totaled approximately $35.1 million and $27.7 million for the three months ended September 30, 2017 and 2016, respectively, and $85.4 million and $62.8 million for the nine months ended September 30, 2017 and 2016, respectively.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation totaled approximately $0.5 million for each of the three months ended September 30, 2017 and 2016 and $1.5 million for each of the nine months ended September 30, 2017 and 2016. This amount is included in DD&A expense in the condensed consolidated statements of operations.

(g) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review for impairment of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the nine months ended September 30, 2016 relating to proved properties in the Marcellus Shale. There were no impairments of proved properties for the three or nine months ended September 30, 2017 or the three months ended September 30, 2016.

The aforementioned impairment charge represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $4.1 million and $9.4 million for the three months ended September 30, 2017 and 2016, respectively, and approximately $12.4 million and $28.1 million for the nine months ended September 30, 2017 and 2016, respectively. The decrease in impairment charges during the three and nine months ended September 30, 2017 is the result of a decrease in expected lease expirations due to the increase in the Company’s planned future drilling activity. These costs are included in exploration expense in the condensed consolidated statements of operations.

(h) Income Taxes

The Company accounts for income taxes, as required, under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

(i) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.  The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

(j) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

(k) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 10.33% for each of the nine months ended September 30, 2017 and 2016.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2017 (in thousands):

	Nine Months Ended September 30, 2017
Asset retirement obligations, beginning of period	$	4,806
Additional liabilities incurred		565
Accretion		395
Asset retirement obligations, end of period	$	5,766

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(l) Lease Obligations

The Company leases office space under an operating lease that expires in 2024. The lease term begins on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

(m) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

(n) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(o) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

(p) Recent Accounting Pronouncements

The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to 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. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period with early adoption permitted.

The Company expects to adopt this standard effective January 1, 2018 using the modified retrospective method.  As part of the implementation process, the Company has substantially completed the detailed analysis of the impact of the standard on its contracts.  The Company does not expect this standard to have a significant impact on its financial position or results of operations but adopting this guidance will require that revenue recognition policy disclosures include further detail regarding performance obligations as to the nature, amount, timing and estimates of revenue and cash flows generated from the Company’s contracts with customers.  The Company continues to monitor relevant industry guidance regarding implementation of the standard and adjust its implementation strategies as necessary.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity will be required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.”  The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows.  These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company is evaluating the impact of the adoption on its statement of cash flows and related disclosures.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.”  Currently under the standard there are three elements of a business: inputs, processes and outputs.  The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets.  If that screen is met, the set of assets is not a business.  The new framework also specifies the minimum required inputs and processes necessary to be a business.  This amendment is effective for periods after December 15, 2017, with early adoption permitted.  The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

(q) Correction of Immaterial Error

During the three months ended March 31, 2017, the Company determined that its estimated accrual for production and ad valorem tax expense was overstated for prior periods. The Company evaluated the materiality of this error on both a quantitative and qualitative basis under the guidance of ASC 250 “Accounting Changes and Errors Corrections,” and determined that it did not have a material impact to previously issued financial statements.

Although the error was immaterial to prior periods, the prior period financial statements were revised, in accordance with SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, due to the significance of the out-of-period correction to the current period. Immaterial errors related to periods prior to the year ended December 31, 2016 are reflected as an adjustment to beginning accumulated deficit for that year. Periods not presented herein will be revised, as applicable, in future filings.

A reconciliation of the effects of the revision to amounts in the previously reported consolidated financial statements is as follows (in thousands, except per share amounts):

	As of  December 31, 2016
	As Reported			Adjustment			As Adjusted
Balance Sheet
Accounts receivable	$	43,638		$	785		$	44,423
Total current assets		249,630			785			250,415
Total assets		1,197,859			785			1,198,644
Accrued liabilities		64,150			(9,106	)		55,044
Total current liabilities		140,625			(9,106	)		131,519
Total liabilities		651,143			(9,106	)		642,037
Accumulated deficit		(1,414,561	)		9,891			(1,404,670	)
Total stockholders' equity		546,716			9,891			556,607
Total liabilities and stockholders' equity		1,197,859			785			1,198,644

	As of  December 31, 2016
	As Reported			Adjustment		As Adjusted
Statement of Stockholders' Equity
Accumulated deficit	$	(1,414,561	)	$	9,891	$	(1,404,670	)
Total stockholders' equity		546,716			9,891		556,607

	Three Months Ended September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations and Comprehensive Income    (Loss)
Production and ad valorem taxes	$	1,980		$	(852	)	$	1,128
Total operating expenses		79,530			(852	)		78,678
Operating loss		(25,051	)		852			(24,199	)
Loss before income taxes		(26,801	)		852			(25,949	)
Net loss		(26,801	)		852			(25,949	)
Basic and diluted loss per share	$	(0.10	)	$	(0.00	)	$	(0.10	)

	Nine Months Ended September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations and Comprehensive Income    (Loss)
Production and ad valorem taxes	$	1,747		$	4,147		$	5,894
Total operating expenses		258,762			4,147			262,909
Operating loss		(107,611	)		(4,147	)		(111,758	)
Loss before income taxes		(139,959	)		(4,147	)		(144,106	)
Net loss		(140,499	)		(4,147	)		(144,646	)
Basic and diluted loss per share	$	(0.60	)	$	(0.02	)	$	(0.62	)

	As of September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Cash Flows
Net loss	$	(140,499	)	$	(4,147	)	$	(144,646	)
Accounts receivable		(1,261	)		(536	)		(1,797	)
Accounts payable and accrued liabilities		(33,342	)		4,683			(28,659	)

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Sale of Oil and Natural Gas Property Interests

9 Months Ended

Sep. 30, 2017

Discontinued Operations And Disposal Groups [Abstract]

Sale of Oil and Natural Gas Property Interests

Note 4—Sale of Oil and Natural Gas Property Interests

During the three months ended September 30, 2016, the Company received $0.4 million from the sale of pipeline assets.  As a result of this sale, the Company recognized a loss of less than $0.1 million.

During the three months ended September 30, 2016, the Company received $1.1 million from acreage trades with various working interest owners totaling approximately 149.5 acres.

During the nine months ended September 30, 2016, the Company completed the sale of its Conventional oil and gas properties and related equipment for approximately $4.7 million. As a result of this sale, the Company recognized a gain of approximately $1.0 million.

During the nine months ended September 30, 2016, the Company received $3.9 million from the sale of mineral interests related primarily to unproved properties to a third party.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the nine months ended September 30, 2016, the Company received $4.8 million from the sale of unproved leases to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the nine months ended September 30, 2017, the Company received approximately $0.5 million from a completed asset sale with a third party totaling approximately 100 acres.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

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Derivative Instruments

9 Months Ended

Sep. 30, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Instruments

Note 5—Derivative Instruments

Commodity Derivatives

The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.

The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of September 30, 2017, the Company’s derivative instruments were with Bank of Montreal, Citibank, Goldman Sachs, Morgan Stanley, Capital One N.A., BP Energy Company and KeyBank N.A. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of September 30, 2017, for future production periods:

Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		10,000	October 2017 – December 2017	$	2.98
		10,000	October 2017 – December 2017	$	3.21
		30,000	October 2017 – March 2018	$	3.46
Natural Gas Three-way Collars:
Floor purchase price (put)		160,000	October 2017 – December 2017	$	2.83
Ceiling sold price (call)		160,000	October 2017 – December 2017	$	3.37
Floor sold price (put)		160,000	October 2017 – December 2017	$	2.31
Floor purchase price (put)		30,000	October 2017 – March 2019	$	3.00
Ceiling sold price (call)		30,000	October 2017 – March 2019	$	3.40
Floor sold price (put)		20,000	October 2017 – March 2019	$	2.40
Floor sold price (put)		10,000	October 2017 – March 2019	$	2.20
Floor purchase price (put)		40,000	October 2017 – December 2018	$	2.90
Ceiling sold price (call)		40,000	October 2017 – December 2018	$	3.38
Floor sold price (put)		40,000	October 2017 – December 2018	$	2.30
Floor purchase price (put)		60,000	January 2018 – March 2018	$	2.90
Ceiling sold price (call)		60,000	January 2018 – March 2018	$	3.75
Floor sold price (put)		60,000	January 2018 – March 2018	$	2.40
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.90
Ceiling sold price (call)		60,000	April 2018 – December 2018	$	3.25
Floor sold price (put)		60,000	April 2018 – December 2018	$	2.40
Floor purchase price (put)		60,000	January 2018 – December 2018	$	2.80
Ceiling sold price (call)		60,000	January 2018 – December 2018	$	3.35
Floor sold price (put)		60,000	January 2018 – December 2018	$	2.33
Natural Gas Call/Put Options:
Call sold		40,000	January 2018 – December 2018	$	3.75
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
TCO - Columbia		20,000	October 2017 – December 2017	$	(0.19	)
Appalachia - Dominion		80,000	October 2017 – November 2017	$	(1.02	)
Appalachia - Dominion		50,000	December 2017	$	(0.56	)
Appalachia - Dominion		50,000	January 2018 – March 2018	$	(0.43	)
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)

Oil Derivatives

Description	Volume (Bbls/d)		Production Period	WeightedAverage Price($/Bbl)
Oil Three-way Collars:
Floor purchase price (put)		2,000	October 2017 – December 2017	$	46.00
Ceiling sold price (call)		2,000	October 2017 – December 2017	$	60.00
Floor sold price (put)		2,000	October 2017 – December 2017	$	38.00

NGL Derivatives

Description	Volume (Gal/d)		Production Period	Weighted Average Price ($/Gal)
Propane Swaps:
		84,000	October 2017 – December 2017	$	0.60

Fair Values and Gains (Losses)

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the condensed consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.

As of September 30, 2017	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	6,358		$	(3,638	)	$	2,720		Other current assets
Commodity derivatives - noncurrent		976			(831	)		145		Other assets
Total assets	$	7,334		$	(4,469	)	$	2,865
Liabilities
Commodity derivatives - current	$	(9,844	)	$	3,638		$	(6,206	)	Accrued liabilities
Commodity derivatives - noncurrent		(3,006	)		831			(2,175	)	Other liabilities
Total liabilities	$	(12,850	)	$	4,469		$	(8,381	)

As of December 31, 2016	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	50		$	(50	)	$	—
Commodity derivatives - noncurrent		—			—			—
Total assets	$	50		$	(50	)	$	—
Liabilities
Commodity derivatives - current	$	(35,459	)	$	50		$	(35,409	)	Accrued liabilities
Commodity derivatives - noncurrent		(12,673	)		—			(12,673	)	Other liabilities
Total liabilities	$	(48,132	)	$	50		$	(48,082	)

(a) The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the condensed consolidated statements of operations for the periods presented (in thousands):

		Amount of Gain (Loss) Recognized in Income
Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss) Recognized in Income	Three Months Ended September 30,					Nine Months Ended September 30,
		2017			2016		2017		2016
Commodity derivatives	Gain (loss) on derivative instruments	$	(1,889	)	$	10,639	$	41,385	$	(8,407	)

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Fair Value Measurements

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 6—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the condensed consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are readily available in the public market, such as natural gas and crude oil forward curves. These values are compared to the values given by counterparties for reasonableness. Since the Company’s derivative instruments do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.

	Level 1		Level 2			Level 3		TotalFair Value
As of September 30, 2017: (in thousands)
Commodity derivative instruments	$	—	$	(5,516	)	$	—	$	(5,516	)
Total	$	—	$	(5,516	)	$	—	$	(5,516	)
As of December 31, 2016: (in thousands)
Commodity derivative instruments	$	—	$	(48,082	)	$	—	$	(48,082	)
Total	$	—	$	(48,082	)	$	—	$	(48,082	)

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3—Summary of Significant Accounting Policies).

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3—Summary of Significant Accounting Policies).

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 7—Debt).

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Debt

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Debt

Note 7—Debt

8.875% Senior Unsecured Notes Due 2023

On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of the principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding Senior PIK Notes. The Company used the remaining net proceeds to fund its capital expenditure plan and for general corporate purposes.

During the three and nine months ended September 30, 2017, the Company amortized $0.8 million and $2.5 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.  The Company amortized $0.7 million and $2.5 million of deferred financing costs and debt discount to interest expense using the effective interest method for the three and nine months ended September 30, 2016, respectively. 

The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the indenture at September 30, 2017.

During the nine months ended September 30, 2016, the Company repurchased $39.5 million of the outstanding senior unsecured notes in open market purchases for $23.4 million. The principal of the outstanding senior unsecured notes that were repurchased less cash proceeds and unamortized debt discount and deferred financing costs were charged to gain on early extinguishment of debt, totaling $14.5 million for the nine months ended September 30, 2016.  The Company repurchased all such senior unsecured notes with cash on hand. 

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at September 30, 2017 was $519.4 million.

Revolving Credit Facility

During the first quarter of 2014, the Company entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that matures in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October).

On February 24, 2016, the Company amended the Credit Amendment governing its revolving credit facility to, among other things, adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense, and to permit the sale of certain conventional properties. The amendment to the Credit Agreement governing the revolving credit facility increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5% and required the Company to, within 60 days of the effectiveness of the amendment, execute and deliver additional mortgages on the Company’s oil and gas properties that include at least 90% of its proved reserves.

On February 24, 2017, the Company entered into an additional amendment that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020.  In addition, the amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Net Debt to EBITDAX.  On August 1, 2017, the Company entered into an additional amendment that increased the borrowing base from $175 million to $225 million.  The Company’s next scheduled borrowing base redetermination is expected to be completed by April 2018.

At September 30, 2017, the borrowing base was $225 million and the Company had no outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $33.6 million, the Company had available borrowing capacity under the revolving credit facility of $191.4 million at September 30, 2017.  Subsequent to September 30, 2017, the Company borrowed $15 million under its revolving credit facility, which reduced the Company’s available borrowing capacity to $176.4 million.

The revolving credit facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the revolving credit facility as of September 30, 2017. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.5% of the unused facility based on utilization.

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Benefit Plans

9 Months Ended

Sep. 30, 2017

Compensation And Retirement Disclosure [Abstract]

Benefit Plans

Note 8—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense related to matching contributions, classified under general and administrative, of $0.2 million and $0.1 million for the three months ended September 30, 2017 and 2016, respectively, and $0.6 million and $0.5 million for the nine months ended September 30, 2017 and 2016, respectively.

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2017

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock-Based Compensation

Note 9—Stock-Based Compensation

The Company is authorized to grant up to 25,000,000 shares of common stock under its 2014 Long-Term Incentive Plan (as amended, the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 10,364,375 shares were available for future grants under the Plan as of September 30, 2017.

Our stock-based compensation expense was as follows for the three and nine months ended September 30, 2017 and 2016 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Restricted stock units	$	1,351	$	1,012	$	3,943	$	3,254
Performance units		987		651		2,627		1,708
Restricted stock issued to directors		90		101		287		454
Incentive units		—		—		—		48
Total expense	$	2,428	$	1,764	$	6,857	$	5,464

Restricted Stock Units

Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock and restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of September 30, 2017, there was $7.2 million of total unrecognized compensation cost related to outstanding restricted stock units. The weighted average period for the shares to vest is approximately 1 year. A summary of restricted stock unit awards activity during the nine months ended September 30, 2017 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2016		4,343,582		$	2.14	$	11,597
Granted		2,692,797			2.12
Vested		(2,914,881	)		1.65
Forfeited		(64,144	)		2.46
Total awarded and unvested, September 30, 2017		4,057,354		$	2.48	$	10,143

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of September 30, 2017, there was $6.0 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the shares to vest is approximately 2 years. A summary of performance stock unit awards activity during the nine months ended September 30, 2017 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2016		1,928,002		$	3.31	$	5,148
Granted		2,564,523			1.94
Vested		—			—
Forfeited		(78,130	)		2.75
Total awarded and unvested, September 30, 2017		4,414,395		$	2.52	$	10,646

The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s public peer group.

Restricted Stock Issued to Directors

On May 11, 2015, the Company issued an aggregate of 132,496 restricted shares of common stock to its seven non-employee members of its Board of Directors, which became fully vested on May 11, 2016. For the nine months ended September 30, 2016, the Company recognized expense of approximately $0.3 million related to these awards.

On May 18, 2016, the Company issued an aggregate of 149,448 restricted shares of common stock to its three non-employee  members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which became fully vested on May 18, 2017.  For the three and nine months ended September 30, 2016, the Company recognized expense of approximately $0.2 million related to these awards.  For the nine months ended September 30, 2017, the Company recognized expense of approximately $0.2 million related to these awards.

On May 17, 2017, the Company issued an aggregate of 153,192 restricted shares of common stock to its three non-employee members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which are scheduled to fully vest on May 17, 2018.  For the three and nine months ended September 30, 2017, the Company recognized expense of approximately $0.1 million and $0.3 million, respectively, related to these awards.  As of September 30, 2017, there was approximately $0.2 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s directors.

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Equity

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

Equity

Note 10—Equity

Public Offering of Common Stock

On June 28, 2016, the Company commenced an underwritten public offering of 37,500,000 shares of common stock, which was priced at $3.50 per share.  The Company closed the offering on July 5, 2016 and received net proceeds of approximately $123 million (after deducting underwriting discounts and commissions and estimated expenses), which the Company used to fund its capital expenditure plan and for general corporate purposes.  

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Earnings (Loss) Per Share

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Earnings (Loss) Per Share

Note 11—Earnings (Loss) Per Share

Earnings (Loss) Per Share

Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive.  The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three and nine months ended September 30, 2017 and 2016, respectively:

	Three Months Ended September 30,
(in thousands, except per share data)	2017								2016
	Income (Loss)			Shares		Per Share			Income (Loss)			Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(16,694	)		262,586	$	(0.06	)	$	(25,949	)		258,812	$	(0.10	)
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—			—
Diluted:
Net income (loss), shares, diluted	$	(16,694	)		262,586	$	(0.06	)	$	(25,949	)		258,812	$	(0.10	)

	Nine Months Ended September 30,
(in thousands, except per share data)	2017						2016
	Income (Loss)		Shares		Per Share		Income (Loss)			Shares		Per Share
Basic:
Net income (loss), shares, basic	$	21,647		262,044	$	0.08	$	(144,646	)		234,933	$	(0.62	)
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—		2,673				—			—
Diluted:
Net income (loss), shares, diluted	$	21,647		264,717	$	0.08	$	(144,646	)		234,933	$	(0.62	)

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Related Party Transactions

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Related Party Transactions

Note 12—Related Party Transactions

During the three and nine months ended September 30, 2017, the Company incurred approximately $0.2 million and $0.4 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which are owned by the Company’s Chairman, President and Chief Executive Officer.  The Company incurred approximately $0.1 million and $0.4 million related to such services during the three and nine months ended September 30, 2016, respectively.  The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 13—Commitments and Contingencies

(a) Legal Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

(b) Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

(c) Leases

The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.

The Company leases office space under an operating lease that expires in 2024. The Company recognized rent expense of $0.2 million and $0.1 million for the three months ended September 30, 2017 and 2016, respectively, and $0.5 million and $0.7 million for the nine months ended September 30, 2017 and 2016, respectively.

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Income Tax

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Tax

Note 14—Income Tax

For the year ending December 31, 2017, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company recorded no income tax expense for the period due to a reduction of previously recorded valuation allowance in the amount of $7.5 million, which is net of a discrete item in the amount of $0.6 million related to an income tax for a share based compensation windfall settled in the first quarter of 2017.  

The Company is forecasting positive pretax income for the year and as a result plans on reducing its valuation allowance to the extent the Company records pretax income cumulatively year to date in the quarter.  At this time, the Company does not believe that the weight of evidence allows the release of its valuation allowance (due to a preponderance of negative evidence as to future realizability) and accordingly reflect a current deferred tax benefit of zero.  The Company continues to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.  No current federal income taxes are anticipated to be paid in the next twelve months. For the nine months ended September 30, 2017, the Company’s overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to valuation allowances and other permanent differences.

During the second quarter of 2017, the Internal Revenue Service completed its examination of Eclipse Resources Corporation for its tax year 2014.  There were no adjustments to the Company’s tax returns as a result of the examination.

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Subsidiary Guarantors

9 Months Ended

Sep. 30, 2017

Text Block [Abstract]

Subsidiary Guarantors

Note 15—Subsidiary Guarantors

The Company’s wholly-owned subsidiaries each have fully and unconditionally, joint and severally, guaranteed the Company’s 8.875% senior unsecured notes (See Note 7—Debt). The Parent company has no independent assets or operations. The Company’s wholly-owned subsidiaries are not restricted from transferring funds to the Parent or other wholly-owned subsidiaries. The Company’s wholly-owned subsidiaries do not have any restricted net assets.

A subsidiary guarantor may be released from its obligations under the guarantee:

• in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or

• if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture governing the senior unsecured notes.

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Subsequent Events

9 Months Ended

Sep. 30, 2017

Subsequent Events [Abstract]

Subsequent Events

Note 16—Subsequent Events

Management has evaluated subsequent events and believes there are no events that would have a material impact on the aforementioned financial statements and related disclosures, other than those disclosed in the accompanying notes to the condensed consolidated financial statements (See Note 7—Debt).

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Cash and Cash Equivalents

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

Accounts Receivable

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of September 30, 2017 or December 31, 2016.

The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $37.8 million and $41.4 million of accrued revenues, net of certain expenses, at September 30, 2017 and December 31, 2016, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets.

Property and Equipment

(c) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, Depletion and Amortization” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s consolidated statements of operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

	September 30, 2017			December 31, 2016
Oil and natural gas properties:
Unproved	$	488,260		$	526,270
Proved		1,852,828			1,545,860
Gross oil and natural gas properties		2,341,088			2,072,130
Less accumulated depreciation, depletion and amortization		(1,216,805	)		(1,131,378	)
Oil and natural gas properties, net		1,124,283			940,752
Other property and equipment		13,333			11,447
Less accumulated depreciation		(6,143	)		(4,699	)
Other property and equipment, net		7,190			6,748
Property and equipment, net	$	1,131,473		$	947,500

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

The Company capitalized interest expense totaling $0.9 million and $0.4 million for the three months ended September 30, 2017 and 2016, respectively.  The Company capitalized interest expense totaling $1.8 million and $0.8 million for the nine months ended September 30, 2017 and 2016, respectively.

Other Property and Equipment

Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

Revenue Recognition

(d) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of September 30, 2017 or December 31, 2016.

In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.

Brokered natural gas and marketing revenues include revenues from brokered gas or revenue the Company receives as a result of selling and buying natural gas that is not related to its production and revenue from the release of transportation capacity. The Company realizes brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. The Company considers these activities as ancillary to its natural gas sales and thus, reports them within one operating segment.

Concentration of Credit Risk

(e) Concentration of Credit Risk

The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of September 30, 2017 and December 31, 2016 (in thousands):

	September 30, 2017		December 31, 2016
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	37,845	$	41,398
Joint interest owners		2,076		2,850
Derivatives		609		122
Other		23		53
Total	$	40,553	$	44,423

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s unsettled commodity derivative contracts was a net liability position of ($5.5) million and ($48.1) million at September 30, 2017 and December 31, 2016, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are such counterparties required to provide credit support to the Company. As of September 30, 2017 and December 31, 2016, the Company did not have past-due receivables from or payables to any of such counterparties.

Depreciation, Depletion and Amortization

(f) Depreciation, Depletion and Amortization

Oil and Natural Gas Properties

Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties totaled approximately $35.1 million and $27.7 million for the three months ended September 30, 2017 and 2016, respectively, and $85.4 million and $62.8 million for the nine months ended September 30, 2017 and 2016, respectively.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation totaled approximately $0.5 million for each of the three months ended September 30, 2017 and 2016 and $1.5 million for each of the nine months ended September 30, 2017 and 2016. This amount is included in DD&A expense in the condensed consolidated statements of operations.

Impairment of Long-Lived Assets

(g) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review for impairment of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the nine months ended September 30, 2016 relating to proved properties in the Marcellus Shale. There were no impairments of proved properties for the three or nine months ended September 30, 2017 or the three months ended September 30, 2016.

The aforementioned impairment charge represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $4.1 million and $9.4 million for the three months ended September 30, 2017 and 2016, respectively, and approximately $12.4 million and $28.1 million for the nine months ended September 30, 2017 and 2016, respectively. The decrease in impairment charges during the three and nine months ended September 30, 2017 is the result of a decrease in expected lease expirations due to the increase in the Company’s planned future drilling activity. These costs are included in exploration expense in the condensed consolidated statements of operations.

Income Taxes

(h) Income Taxes

The Company accounts for income taxes, as required, under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

Fair Value of Financial Instruments

(i) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.  The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Derivative Financial Instruments

(j) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

Asset Retirement Obligation

(k) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 10.33% for each of the nine months ended September 30, 2017 and 2016.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2017 (in thousands):

	Nine Months Ended September 30, 2017
Asset retirement obligations, beginning of period	$	4,806
Additional liabilities incurred		565
Accretion		395
Asset retirement obligations, end of period	$	5,766

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

Lease Obligations

(l) Lease Obligations

The Company leases office space under an operating lease that expires in 2024. The lease term begins on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

Off-Balance Sheet Arrangements

(m) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

Segment Reporting

(n) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

Debt Issuance Costs

(o) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

Recent Accounting Pronouncements

(p) Recent Accounting Pronouncements

The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to 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. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period with early adoption permitted.

The Company expects to adopt this standard effective January 1, 2018 using the modified retrospective method.  As part of the implementation process, the Company has substantially completed the detailed analysis of the impact of the standard on its contracts.  The Company does not expect this standard to have a significant impact on its financial position or results of operations but adopting this guidance will require that revenue recognition policy disclosures include further detail regarding performance obligations as to the nature, amount, timing and estimates of revenue and cash flows generated from the Company’s contracts with customers.  The Company continues to monitor relevant industry guidance regarding implementation of the standard and adjust its implementation strategies as necessary.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity will be required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.”  The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows.  These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company is evaluating the impact of the adoption on its statement of cash flows and related disclosures.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.”  Currently under the standard there are three elements of a business: inputs, processes and outputs.  The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets.  If that screen is met, the set of assets is not a business.  The new framework also specifies the minimum required inputs and processes necessary to be a business.  This amendment is effective for periods after December 15, 2017, with early adoption permitted.  The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

Correction of Immaterial Error

(q) Correction of Immaterial Error

During the three months ended March 31, 2017, the Company determined that its estimated accrual for production and ad valorem tax expense was overstated for prior periods. The Company evaluated the materiality of this error on both a quantitative and qualitative basis under the guidance of ASC 250 “Accounting Changes and Errors Corrections,” and determined that it did not have a material impact to previously issued financial statements.

Although the error was immaterial to prior periods, the prior period financial statements were revised, in accordance with SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, due to the significance of the out-of-period correction to the current period. Immaterial errors related to periods prior to the year ended December 31, 2016 are reflected as an adjustment to beginning accumulated deficit for that year. Periods not presented herein will be revised, as applicable, in future filings.

A reconciliation of the effects of the revision to amounts in the previously reported consolidated financial statements is as follows (in thousands, except per share amounts):

	As of  December 31, 2016
	As Reported			Adjustment			As Adjusted
Balance Sheet
Accounts receivable	$	43,638		$	785		$	44,423
Total current assets		249,630			785			250,415
Total assets		1,197,859			785			1,198,644
Accrued liabilities		64,150			(9,106	)		55,044
Total current liabilities		140,625			(9,106	)		131,519
Total liabilities		651,143			(9,106	)		642,037
Accumulated deficit		(1,414,561	)		9,891			(1,404,670	)
Total stockholders' equity		546,716			9,891			556,607
Total liabilities and stockholders' equity		1,197,859			785			1,198,644

	As of  December 31, 2016
	As Reported			Adjustment		As Adjusted
Statement of Stockholders' Equity
Accumulated deficit	$	(1,414,561	)	$	9,891	$	(1,404,670	)
Total stockholders' equity		546,716			9,891		556,607

	Three Months Ended September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations and Comprehensive Income    (Loss)
Production and ad valorem taxes	$	1,980		$	(852	)	$	1,128
Total operating expenses		79,530			(852	)		78,678
Operating loss		(25,051	)		852			(24,199	)
Loss before income taxes		(26,801	)		852			(25,949	)
Net loss		(26,801	)		852			(25,949	)
Basic and diluted loss per share	$	(0.10	)	$	(0.00	)	$	(0.10	)

	Nine Months Ended September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations and Comprehensive Income    (Loss)
Production and ad valorem taxes	$	1,747		$	4,147		$	5,894
Total operating expenses		258,762			4,147			262,909
Operating loss		(107,611	)		(4,147	)		(111,758	)
Loss before income taxes		(139,959	)		(4,147	)		(144,106	)
Net loss		(140,499	)		(4,147	)		(144,646	)
Basic and diluted loss per share	$	(0.60	)	$	(0.02	)	$	(0.62	)

	As of September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Cash Flows
Net loss	$	(140,499	)	$	(4,147	)	$	(144,646	)
Accounts receivable		(1,261	)		(536	)		(1,797	)
Accounts payable and accrued liabilities		(33,342	)		4,683			(28,659	)

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2017

Summary of Property and Equipment Including Oil and Natural Gas Properties

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

	September 30, 2017			December 31, 2016
Oil and natural gas properties:
Unproved	$	488,260		$	526,270
Proved		1,852,828			1,545,860
Gross oil and natural gas properties		2,341,088			2,072,130
Less accumulated depreciation, depletion and amortization		(1,216,805	)		(1,131,378	)
Oil and natural gas properties, net		1,124,283			940,752
Other property and equipment		13,333			11,447
Less accumulated depreciation		(6,143	)		(4,699	)
Other property and equipment, net		7,190			6,748
Property and equipment, net	$	1,131,473		$	947,500

Changes in Company's Asset Retirement Obligation Liability

The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2017 (in thousands):

	Nine Months Ended September 30, 2017
Asset retirement obligations, beginning of period	$	4,806
Additional liabilities incurred		565
Accretion		395
Asset retirement obligations, end of period	$	5,766

Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements

A reconciliation of the effects of the revision to amounts in the previously reported consolidated financial statements is as follows (in thousands, except per share amounts):

	As of  December 31, 2016
	As Reported			Adjustment			As Adjusted
Balance Sheet
Accounts receivable	$	43,638		$	785		$	44,423
Total current assets		249,630			785			250,415
Total assets		1,197,859			785			1,198,644
Accrued liabilities		64,150			(9,106	)		55,044
Total current liabilities		140,625			(9,106	)		131,519
Total liabilities		651,143			(9,106	)		642,037
Accumulated deficit		(1,414,561	)		9,891			(1,404,670	)
Total stockholders' equity		546,716			9,891			556,607
Total liabilities and stockholders' equity		1,197,859			785			1,198,644

	As of  December 31, 2016
	As Reported			Adjustment		As Adjusted
Statement of Stockholders' Equity
Accumulated deficit	$	(1,414,561	)	$	9,891	$	(1,404,670	)
Total stockholders' equity		546,716			9,891		556,607

	Three Months Ended September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations and Comprehensive Income    (Loss)
Production and ad valorem taxes	$	1,980		$	(852	)	$	1,128
Total operating expenses		79,530			(852	)		78,678
Operating loss		(25,051	)		852			(24,199	)
Loss before income taxes		(26,801	)		852			(25,949	)
Net loss		(26,801	)		852			(25,949	)
Basic and diluted loss per share	$	(0.10	)	$	(0.00	)	$	(0.10	)

	Nine Months Ended September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations and Comprehensive Income    (Loss)
Production and ad valorem taxes	$	1,747		$	4,147		$	5,894
Total operating expenses		258,762			4,147			262,909
Operating loss		(107,611	)		(4,147	)		(111,758	)
Loss before income taxes		(139,959	)		(4,147	)		(144,106	)
Net loss		(140,499	)		(4,147	)		(144,646	)
Basic and diluted loss per share	$	(0.60	)	$	(0.02	)	$	(0.62	)

	As of September 30, 2016
	As Reported			Adjustment			As Adjusted
Statement of Cash Flows
Net loss	$	(140,499	)	$	(4,147	)	$	(144,646	)
Accounts receivable		(1,261	)		(536	)		(1,797	)
Accounts payable and accrued liabilities		(33,342	)		4,683			(28,659	)

Accounts Receivable [Member] | Product Concentration Risk [Member]

Concentration Risk

The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of September 30, 2017 and December 31, 2016 (in thousands):

	September 30, 2017		December 31, 2016
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	37,845	$	41,398
Joint interest owners		2,076		2,850
Derivatives		609		122
Other		23		53
Total	$	40,553	$	44,423

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary of Derivative Instrument Positions for Future Production Periods

Below is a summary of the Company’s derivative instrument positions, as of September 30, 2017, for future production periods:

Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		10,000	October 2017 – December 2017	$	2.98
		10,000	October 2017 – December 2017	$	3.21
		30,000	October 2017 – March 2018	$	3.46
Natural Gas Three-way Collars:
Floor purchase price (put)		160,000	October 2017 – December 2017	$	2.83
Ceiling sold price (call)		160,000	October 2017 – December 2017	$	3.37
Floor sold price (put)		160,000	October 2017 – December 2017	$	2.31
Floor purchase price (put)		30,000	October 2017 – March 2019	$	3.00
Ceiling sold price (call)		30,000	October 2017 – March 2019	$	3.40
Floor sold price (put)		20,000	October 2017 – March 2019	$	2.40
Floor sold price (put)		10,000	October 2017 – March 2019	$	2.20
Floor purchase price (put)		40,000	October 2017 – December 2018	$	2.90
Ceiling sold price (call)		40,000	October 2017 – December 2018	$	3.38
Floor sold price (put)		40,000	October 2017 – December 2018	$	2.30
Floor purchase price (put)		60,000	January 2018 – March 2018	$	2.90
Ceiling sold price (call)		60,000	January 2018 – March 2018	$	3.75
Floor sold price (put)		60,000	January 2018 – March 2018	$	2.40
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.90
Ceiling sold price (call)		60,000	April 2018 – December 2018	$	3.25
Floor sold price (put)		60,000	April 2018 – December 2018	$	2.40
Floor purchase price (put)		60,000	January 2018 – December 2018	$	2.80
Ceiling sold price (call)		60,000	January 2018 – December 2018	$	3.35
Floor sold price (put)		60,000	January 2018 – December 2018	$	2.33
Natural Gas Call/Put Options:
Call sold		40,000	January 2018 – December 2018	$	3.75
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
TCO - Columbia		20,000	October 2017 – December 2017	$	(0.19	)
Appalachia - Dominion		80,000	October 2017 – November 2017	$	(1.02	)
Appalachia - Dominion		50,000	December 2017	$	(0.56	)
Appalachia - Dominion		50,000	January 2018 – March 2018	$	(0.43	)
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)

Oil Derivatives

Description	Volume (Bbls/d)		Production Period	WeightedAverage Price($/Bbl)
Oil Three-way Collars:
Floor purchase price (put)		2,000	October 2017 – December 2017	$	46.00
Ceiling sold price (call)		2,000	October 2017 – December 2017	$	60.00
Floor sold price (put)		2,000	October 2017 – December 2017	$	38.00

NGL Derivatives

Description	Volume (Gal/d)		Production Period	Weighted Average Price ($/Gal)
Propane Swaps:
		84,000	October 2017 – December 2017	$	0.60

Fair Value of Derivative Instruments on a Gross Basis and on a Net basis as Presented in Consolidated Balance Sheets

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the condensed consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.

As of September 30, 2017	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	6,358		$	(3,638	)	$	2,720		Other current assets
Commodity derivatives - noncurrent		976			(831	)		145		Other assets
Total assets	$	7,334		$	(4,469	)	$	2,865
Liabilities
Commodity derivatives - current	$	(9,844	)	$	3,638		$	(6,206	)	Accrued liabilities
Commodity derivatives - noncurrent		(3,006	)		831			(2,175	)	Other liabilities
Total liabilities	$	(12,850	)	$	4,469		$	(8,381	)

As of December 31, 2016	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	50		$	(50	)	$	—
Commodity derivatives - noncurrent		—			—			—
Total assets	$	50		$	(50	)	$	—
Liabilities
Commodity derivatives - current	$	(35,459	)	$	50		$	(35,409	)	Accrued liabilities
Commodity derivatives - noncurrent		(12,673	)		—			(12,673	)	Other liabilities
Total liabilities	$	(48,132	)	$	50		$	(48,082	)

(a) The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

Summary of Gains and Losses on Derivative Instruments

The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the condensed consolidated statements of operations for the periods presented (in thousands):

		Amount of Gain (Loss) Recognized in Income
Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss) Recognized in Income	Three Months Ended September 30,					Nine Months Ended September 30,
		2017			2016		2017		2016
Commodity derivatives	Gain (loss) on derivative instruments	$	(1,889	)	$	10,639	$	41,385	$	(8,407	)

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Assets and Liabilities that are Measured at Fair Value on a Recurring Basis

The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are readily available in the public market, such as natural gas and crude oil forward curves. These values are compared to the values given by counterparties for reasonableness. Since the Company’s derivative instruments do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.

	Level 1		Level 2			Level 3		TotalFair Value
As of September 30, 2017: (in thousands)
Commodity derivative instruments	$	—	$	(5,516	)	$	—	$	(5,516	)
Total	$	—	$	(5,516	)	$	—	$	(5,516	)
As of December 31, 2016: (in thousands)
Commodity derivative instruments	$	—	$	(48,082	)	$	—	$	(48,082	)
Total	$	—	$	(48,082	)	$	—	$	(48,082	)

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2017

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Schedule of Stock Based Compensation Expense

Our stock-based compensation expense was as follows for the three and nine months ended September 30, 2017 and 2016 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Restricted stock units	$	1,351	$	1,012	$	3,943	$	3,254
Performance units		987		651		2,627		1,708
Restricted stock issued to directors		90		101		287		454
Incentive units		—		—		—		48
Total expense	$	2,428	$	1,764	$	6,857	$	5,464

Summary of Restricted Stock Unit Awards Activity

A summary of restricted stock unit awards activity during the nine months ended September 30, 2017 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2016		4,343,582		$	2.14	$	11,597
Granted		2,692,797			2.12
Vested		(2,914,881	)		1.65
Forfeited		(64,144	)		2.46
Total awarded and unvested, September 30, 2017		4,057,354		$	2.48	$	10,143

Summary of Performance Stock Unit Awards Activity

A summary of performance stock unit awards activity during the nine months ended September 30, 2017 is as follows

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2016		1,928,002		$	3.31	$	5,148
Granted		2,564,523			1.94
Vested		—			—
Forfeited		(78,130	)		2.75
Total awarded and unvested, September 30, 2017		4,414,395		$	2.52	$	10,646

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Earnings (Loss) Per Share (Tables)

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three and nine months ended September 30, 2017 and 2016, respectively:

	Three Months Ended September 30,
(in thousands, except per share data)	2017								2016
	Income (Loss)			Shares		Per Share			Income (Loss)			Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(16,694	)		262,586	$	(0.06	)	$	(25,949	)		258,812	$	(0.10	)
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—			—
Diluted:
Net income (loss), shares, diluted	$	(16,694	)		262,586	$	(0.06	)	$	(25,949	)		258,812	$	(0.10	)

	Nine Months Ended September 30,
(in thousands, except per share data)	2017						2016
	Income (Loss)		Shares		Per Share		Income (Loss)			Shares		Per Share
Basic:
Net income (loss), shares, basic	$	21,647		262,044	$	0.08	$	(144,646	)		234,933	$	(0.62	)
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—		2,673				—			—
Diluted:
Net income (loss), shares, diluted	$	21,647		264,717	$	0.08	$	(144,646	)		234,933	$	(0.62	)

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Summary of Significant Accounting Policies - Additional Information (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) Segment	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 40,553,000		$ 40,553,000		$ 44,423,000
Capitalized interest expense	900,000	$ 400,000	1,800,000	$ 800,000
Depreciation, depletion and amortization	35,588,000	28,225,000	$ 86,929,000	64,287,000
Impairment of oil and gas properties				$ 17,665,000
Asset retirement obligations credit adjusted discount rates			10.33%	10.33%
Operating lease expiration year			2024
Number of operating segment | Segment			1
Oil and Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciation, depletion and amortization	35,100,000	27,700,000	$ 85,400,000	$ 62,800,000
Other property and equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciation	500,000	500,000	$ 1,500,000	1,500,000
Other property and equipment [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Property and equipment, expected lives			5 years
Other property and equipment [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Property and equipment, expected lives			40 years
Proved Oil And Gas Properties [Member] | Utica Shale [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties	0	0	$ 0	17,700,000
Unproved Oil And Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties	4,100,000	$ 9,400,000	12,400,000	$ 28,100,000
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Summary Of Significant Accounting Policies [Line Items]
Fair value of commodity derivative contracts	(5,500,000)		(5,500,000)		(48,100,000)
Unbilled Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 37,800,000		$ 37,800,000		$ 41,400,000

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Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Oil and natural gas properties:
Unproved properties	$ 488,260	$ 526,270
Proved properties	1,852,828	1,545,860
Gross oil and natural gas properties	2,341,088	2,072,130
Less accumulated depreciation, depletion and amortization	(1,216,805)	(1,131,378)
Total oil and natural gas properties, net	1,124,283	940,752
Other property and equipment	13,333	11,447
Less accumulated depreciation	(6,143)	(4,699)
Other property and equipment, net	7,190	6,748
Total property and equipment, net	$ 1,131,473	$ 947,500

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Summary of Significant Accounting Policies - Summary for Concentration of Receivables, Net of Allowances, By Product or Service (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	$ 40,553	$ 44,423
Product Concentration Risk [Member] | Oil and Natural Gas and Related Products and Services [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	37,845	41,398
Product Concentration Risk [Member] | Joint Interest Owners [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	2,076	2,850
Product Concentration Risk [Member] | Derivatives [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	609	122
Product Concentration Risk [Member] | Other [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	$ 23	$ 53

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Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Asset Retirement Obligation [Abstract]
Asset retirement obligations, beginning of period			$ 4,806
Additional liabilities incurred			565
Accretion	$ 143	$ 100	395	$ 275
Asset retirement obligations, end of period	$ 5,766		$ 5,766

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Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Balance Sheet (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Accounts receivable	$ 40,553	$ 44,423
Total current assets	76,733	250,415
Total assets	1,210,246	1,198,644
Accrued liabilities	24,981	55,044
Total current liabilities	124,376	131,519
Total liabilities	627,214	642,037
Accumulated deficit	(1,383,023)	(1,404,670)
Total stockholders' equity	583,032	556,607
Total liabilities and stockholders' equity	$ 1,210,246	1,198,644
As Reported [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Accounts receivable		43,638
Total current assets		249,630
Total assets		1,197,859
Accrued liabilities		64,150
Total current liabilities		140,625
Total liabilities		651,143
Accumulated deficit		(1,414,561)
Total stockholders' equity		546,716
Total liabilities and stockholders' equity		1,197,859
Adjustment [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Accounts receivable		785
Total current assets		785
Total assets		785
Accrued liabilities		(9,106)
Total current liabilities		(9,106)
Total liabilities		(9,106)
Accumulated deficit		9,891
Total stockholders' equity		9,891
Total liabilities and stockholders' equity		$ 785

XML

Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Statement of Stockholders' Equity (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Accumulated deficit	$ (1,383,023)	$ (1,404,670)
Total stockholders' equity	$ 583,032	556,607
As Reported [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Accumulated deficit		(1,414,561)
Total stockholders' equity		546,716
Adjustment [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Accumulated deficit		9,891
Total stockholders' equity		$ 9,891

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Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Statement of Operations and Comprehensive Income (Loss) (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Production and ad valorem taxes	$ 2,427	$ 1,128	$ 6,391	$ 5,894
Total operating expenses	94,338	78,678	262,558	262,909
Operating loss	(2,789)	(24,199)	17,044	(111,758)
Loss before income taxes	(16,694)	(25,949)	21,647	(144,106)
Net loss	$ (16,694)	$ (25,949)	$ 21,647	$ (144,646)
Basic and diluted loss per share		$ (0.10)		$ (0.62)
As Reported [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Production and ad valorem taxes		$ 1,980		$ 1,747
Total operating expenses		79,530		258,762
Operating loss		(25,051)		(107,611)
Loss before income taxes		(26,801)		(139,959)
Net loss		$ (26,801)		$ (140,499)
Basic and diluted loss per share		$ (0.10)		$ (0.60)
Adjustment [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Production and ad valorem taxes		$ (852)		$ 4,147
Total operating expenses		(852)		4,147
Operating loss		852		(4,147)
Loss before income taxes		852		(4,147)
Net loss		$ 852		$ (4,147)
Basic and diluted loss per share		$ 0.00		$ (0.02)

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Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Statement of Cash Flows (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Net loss	$ (16,694)	$ (25,949)	$ 21,647	$ (144,646)
Accounts receivable			4,357	(1,797)
Accounts payable and accrued liabilities			$ (3,344)	(28,659)
As Reported [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Net loss		(26,801)		(140,499)
Accounts receivable				(1,261)
Accounts payable and accrued liabilities				(33,342)
Adjustment [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Net loss		$ 852		(4,147)
Accounts receivable				(536)
Accounts payable and accrued liabilities				$ 4,683

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Sale of Oil and Natural Gas Property Interests - Additional Information (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($) a	Sep. 30, 2016 USD ($) a	Sep. 30, 2017 USD ($) a	Sep. 30, 2016 USD ($) a
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of conventional oil and gas properties and related equipment				$ 4,700,000
Gain (loss) on sale of assets	$ 13,000	$ (102,000)	$ 12,000	944,000
Gain or loss on sale of conventional oil and gas properties and related equipment				1,000,000
Proceeds from sale of unproved lease properties				3,900,000
Gain or Loss on sale of oil and natural gas properties				0
Proceeds from sale of unproved lease properties				4,800,000
Gain (loss) on sale of unproved properties				$ 0
Asset Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale of assets			0
Proceeds from sale of asset			$ 500,000
Area of land | a	100		100
Acreage Trades [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of asset		$ 1,100,000
Area of land | a		149.5		149.5
Pipelines [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of conventional oil and gas properties and related equipment		$ 400,000
Pipelines [Member] | Maximum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale of assets		$ (100,000)

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Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail)	9 Months Ended
	Sep. 30, 2017 MMBTU $ / MMBTU $ / gal bbl gal
Natural Gas Swaps Production Period October 2017 – December 2017 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	10,000
Weighted Average Price ($/MMBtu)	2.98
Natural Gas Swaps Production Period October 2017 – December 2017 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	10,000
Weighted Average Price ($/MMBtu)	3.21
Natural Gas Swaps Production Period October 2017 – March 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price ($/MMBtu)	3.46
Propane Swaps Production Period October 2017 – December 2017 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (Gal/d) | gal	84,000
Weighted Average Price ($/Gal) | $ / gal	0.60
Appalachia [Member] | Dominion Resources, Inc [Member] | Basis Swaps Production Period October 2017 – November 2017 [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	80,000
Weighted Average Price ($/MMBtu)	(1.02)
Appalachia [Member] | Dominion Resources, Inc [Member] | Basis Swaps Production Period December 2017 [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price ($/MMBtu)	(0.56)
Appalachia [Member] | Dominion Resources, Inc [Member] | Basis Swaps Production Period January 2018 - March 2018 [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price ($/MMBtu)	(0.43)
Appalachia [Member] | Dominion Resources, Inc [Member] | Basis Swaps Production Period April 2019 - October 2019 [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	12,500
Weighted Average Price ($/MMBtu)	(0.52)
Appalachia [Member] | Dominion Resources, Inc [Member] | Basis Swaps Production Period April 2020 - October 2020 [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	12,500
Weighted Average Price ($/MMBtu)	(0.52)
Put Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – December 2017 [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	160,000
Weighted Average Price, Floor ($/MMBtu)	2.83
Put Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – December 2017 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	160,000
Weighted Average Price, Floor ($/MMBtu)	2.31
Put Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – March 2019 [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price, Floor ($/MMBtu)	3.00
Put Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – March 2019 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price, Floor ($/MMBtu)	2.40
Put Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – March 2019 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	10,000
Weighted Average Price, Floor ($/MMBtu)	2.20
Put Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – December 2018 [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price, Floor ($/MMBtu)	2.90
Put Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – December 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price, Floor ($/MMBtu)	2.30
Put Option [Member] | Natural Gas Three-way Collars Production Period January 2018 – March 2018 [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Floor ($/MMBtu)	2.90
Put Option [Member] | Natural Gas Three-way Collars Production Period January 2018 – March 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Floor ($/MMBtu)	2.40
Put Option [Member] | Natural Gas Three-way Collars Production Period April 2018 – December 2018 [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Floor ($/MMBtu)	2.90
Put Option [Member] | Natural Gas Three-way Collars Production Period April 2018 – December 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Floor ($/MMBtu)	2.40
Put Option [Member] | Natural Gas Three-way Collars Production Period January 2018 – December 2018 [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Floor ($/MMBtu)	2.80
Put Option [Member] | Natural Gas Three-way Collars Production Period January 2018 – December 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Floor ($/MMBtu)	2.33
Put Option [Member] | Oil Three-way Collars Production Period October 2017 – December 2017 [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor ($/MMBtu)	46.00
Volume (Bbls/d) | bbl	2,000
Put Option [Member] | Oil Three-way Collars Production Period October 2017 – December 2017 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor ($/MMBtu)	38.00
Volume (Bbls/d) | bbl	2,000
Call Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – December 2017 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	160,000
Weighted Average Price, Ceiling ($/MMBtu)	3.37
Call Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – March 2019 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price, Ceiling ($/MMBtu)	3.40
Call Option [Member] | Natural Gas Call/Put Options Production Period January 2018 – December 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price ($/MMBtu)	3.75
Call Option [Member] | Natural Gas Call/Put Options Production Period January 2019 – December 2019 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	10,000
Weighted Average Price ($/MMBtu)	4.75
Call Option [Member] | Natural Gas Three-way Collars Production Period October 2017 – December 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price, Ceiling ($/MMBtu)	3.38
Call Option [Member] | Natural Gas Three-way Collars Production Period January 2018 – March 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Ceiling ($/MMBtu)	3.75
Call Option [Member] | Natural Gas Three-way Collars Production Period April 2018 – December 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Ceiling ($/MMBtu)	3.25
Call Option [Member] | Natural Gas Three-way Collars Production Period January 2018 – December 2018 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Ceiling ($/MMBtu)	3.35
Call Option [Member] | Oil Three-way Collars Production Period October 2017 – December 2017 [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling ($/MMBtu)	60.00
Volume (Bbls/d) | bbl	2,000
TCO Columbia [Member] | Basis Swaps Production Period October 2017 – December 2017 [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price ($/MMBtu)	(0.19)

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Derivative Instruments - Fair Value of Derivative Instruments on a Gross basis and on a Net Basis as Presented in Consolidated Balance Sheets (Detail) - Commodity Contract [Member] - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Gross Amount		$ 7,334	$ 50
Netting Adjustments	[1]	(4,469)	(50)
Net Amount Presented in Balance Sheets		2,865
Gross Amount		(12,850)	(48,132)
Netting Adjustments	[1]	4,469	50
Net Amount Presented in Balance Sheets		(8,381)	(48,082)
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		6,358	50
Netting Adjustments	[1]	(3,638)	(50)
Net Amount Presented in Balance Sheets		2,720
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		976
Netting Adjustments	[1]	(831)
Net Amount Presented in Balance Sheets		145
Current Liabilities [Member] | Accrued Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(9,844)	(35,459)
Netting Adjustments	[1]	3,638	50
Net Amount Presented in Balance Sheets		(6,206)	(35,409)
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(3,006)	(12,673)
Netting Adjustments	[1]	831
Net Amount Presented in Balance Sheets		$ (2,175)	$ (12,673)

[1] The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

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Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ (1,889)	$ 10,639	$ 41,385	$ (8,407)
Commodity Contract [Member] | Gain (Loss) on Derivative Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ (1,889)	$ 10,639	$ 41,385	$ (8,407)

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Fair Value Measurements - Schedule of Fair Value Measured on a Recurring Basis (Detail) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Total fair value	$ (5,516)	$ (48,082)
Commodity Contract [Member]
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Total fair value	(5,516)	(48,082)
Level 2 [Member]
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Total fair value	(5,516)	(48,082)
Level 2 [Member] | Commodity Contract [Member]
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Total fair value	$ (5,516)	$ (48,082)

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Debt - Additional Information (Detail) - USD ($)			3 Months Ended		9 Months Ended
	Feb. 24, 2016	Jul. 06, 2015	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Nov. 09, 2017	Aug. 01, 2017	Feb. 24, 2017	Feb. 23, 2017	Mar. 31, 2014
Debt Instrument [Line Items]
Debt instrument interest rate			8.875%		8.875%
Debt instrument, covenant description					The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries.
Gain on early extinguishment of debt						$ 14,489,000
Outstanding letters of credit			$ 33,600,000		$ 33,600,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility											$ 500,000,000
Credit facility maturity year					2018
Applicable Margin	0.50%
Percentage of additional mortgage to be delivered	90.00%
Additional Period for the effectiveness of amendment	60 days
Borrowing base			225,000,000		$ 225,000,000			$ 225,000,000	$ 175,000,000	$ 125,000,000
Revolving credit facility, extended maturity month and year					2020-02
Outstanding borrowings			0		$ 0
Available capacity on the Revolving Credit Facility			191,400,000		$ 191,400,000
Commitment fees on unused portion of revolving credit facility					0.50%
Revolving Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Outstanding borrowings							$ 15,000,000
Available capacity on the Revolving Credit Facility							$ 176,400,000
8.875% Senior Unsecured Notes Due 2023 [Member]
Debt Instrument [Line Items]
Issuance date		Jul. 06, 2015
Debt instrument, outstanding principal balance amount		$ 550,000,000
Debt instrument interest rate		8.875%
Debt instrument maturity year					2023
Notes issued percentage price		97.903%
Debt instrument, proceeds		$ 525,500,000
Amortization of deferred financing costs and debt discount			800,000	$ 700,000	$ 2,500,000	2,500,000
Principal amount outstanding				39,500,000		39,500,000
Gain on early extinguishment of debt						14,500,000
Debt instrument, fair value			$ 519,400,000		$ 519,400,000
8.875% Senior Unsecured Notes Due 2023 [Member] | Open Market [Member]
Debt Instrument [Line Items]
Debt instrument repurchase amount				$ 23,400,000		$ 23,400,000
Senior PIK Notes [Member]
Debt Instrument [Line Items]
Debt instrument repurchase amount		$ 510,700,000

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Benefit Plans - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Pension Plans And Defined Benefit Postretirement Plans Disclosure [Abstract]
Matching contribution by the company to the plan			100.00%
Percentage of employees' eligible compensation			6.00%
Defined contribution plan, general and administrative expenses	$ 0.2	$ 0.1	$ 0.6	$ 0.5
Plan name			401(K) plan

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Stock-Based Compensation - Additional Information (Detail) $ in Millions				3 Months Ended		9 Months Ended
	May 17, 2017 Director shares	May 18, 2016 Director shares	May 11, 2015 Director shares	Sep. 30, 2017 USD ($) shares	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) shares	Sep. 30, 2016 USD ($)
May Two Thousand Fifteen [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock expense							$ 0.3
May Two Thousand Sixteen [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock expense					$ 0.2	$ 0.2	$ 0.2
May Two Thousand Seventeen [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock expense				$ 0.1		$ 0.3
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation awards, requisite service period						3 years
Restricted Stock [Member] | May Two Thousand Fifteen [Member] | Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares of common stock issued | shares			132,496
Number of non employee directors | Director			7
Restricted Stock [Member] | May Two Thousand Sixteen [Member] | Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares of common stock issued | shares		149,448
Number of non employee directors | Director		3
Restricted Stock [Member] | May Two Thousand Seventeen [Member] | Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost				0.2		$ 0.2
Restricted shares of common stock issued | shares	153,192
Number of non employee directors | Director	3
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation awards, requisite service period						3 years
Unrecognized compensation cost				7.2		$ 7.2
Weighted average period for shares to vest						1 year
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost				$ 6.0		$ 6.0
Weighted average period for shares to vest						2 years
2014 Long-Term Incentive as Amended Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be issue | shares				25,000,000		25,000,000
Number of shares are available for future grants | shares				10,364,375		10,364,375

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Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	$ 2,428	$ 1,764	$ 6,857	$ 5,464
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	1,351	1,012	3,943	3,254
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	987	651	2,627	1,708
Restricted Stock Issued to Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	$ 90	$ 101	$ 287	454
Incentive Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense				$ 48

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Stock-Based Compensation - Summary of Restricted Stock and Restricted Stock Unit Awards Activity (Detail) - Restricted Stock Units [Member] - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, Beginning Balance	4,343,582
Number of shares, Granted	2,692,797
Number of shares, Vested	(2,914,881)
Number of shares, Forfeited	(64,144)
Number of shares, Ending Balance	4,057,354
Weighted average grant date fair value, Beginning Balance	$ 2.14
Weighted average grant date fair value, Granted	2.12
Weighted average grant date fair value, Vested	1.65
Weighted average grant date fair value, Forfeited	2.46
Weighted average grant date fair value, Ending Balance	$ 2.48
Aggregate intrinsic value	$ 10,143	$ 11,597

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Stock-Based Compensation - Summary of Performance Stock Unit Awards Activity (Detail) - Performance Units [Member] - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, Beginning Balance	1,928,002
Number of shares, Granted	2,564,523
Number of shares, Vested	0
Number of shares, Forfeited	(78,130)
Number of shares, Ending Balance	4,414,395
Weighted average grant date fair value, Beginning Balance	$ 3.31
Weighted average grant date fair value, Granted	1.94
Weighted average grant date fair value, Vested	0
Weighted average grant date fair value, Forfeited	2.75
Weighted average grant date fair value, Ending Balance	$ 2.52
Aggregate intrinsic value	$ 10,646	$ 5,148

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Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Jul. 05, 2016	Jun. 28, 2016
Equity [Abstract]
Shares Issued		37,500,000
Stock price, per share		$ 3.50
Proceeds from initial public offering	$ 123

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Earnings Per Share - Schedule of Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Basic:
Net income (loss), basic	$ (16,694)	$ (25,949)	$ 21,647	$ (144,646)
Net income (loss), shares, basic	262,586	258,812	262,044	234,933
Net income (loss), per share, basic	$ (0.06)	$ (0.10)	$ 0.08	$ (0.62)
Weighted-average number of shares of common stock-diluted:
Restricted stock and performance unit awards			2,673
Diluted:
Net income (loss), diluted	$ (16,694)	$ (25,949)	$ 21,647	$ (144,646)
Net income (loss), shares, diluted	262,586	258,812	264,717	234,933
Net income (loss), per share, diluted	$ (0.06)	$ (0.10)	$ 0.08	$ (0.62)

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Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Chairman President and Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Flight charter services fees	$ 0.2	$ 0.1	$ 0.4	$ 0.4

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Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Lease agreement, term			The Company leases office space under an operating lease that expires in 2024.
Rent expense	$ 0.2	$ 0.1	$ 0.5	$ 0.7

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Income Tax - Additional Information (Detail) - USD ($)	3 Months Ended	9 Months Ended		12 Months Ended
	Mar. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2017
Income Tax [Line Items]
Income tax benefit (expense)		$ 0	$ (540,000)
Reduction of previously recorded valuation allowance		7,500,000
Income tax related to share based compensation windfall settled	$ 600,000
Deferred tax benefit		$ 0	$ 540,000
Federal statutory rate		35.00%
Income taxes paid		$ 0
Scenario, Forecast [Member]
Income Tax [Line Items]
Percentage of annual effective income tax rate				0.00%

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Subsidiary Guarantors - Additional Information (Detail)	Sep. 30, 2017
Guarantees [Abstract]
Debt instrument interest rate	8.875%