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 March 31, 2018

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 May 4, 2018: 302,092,885 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	38
Item 4.	Controls and Procedures	38
PART II - Other Information		40
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 6.	Exhibits	40
Index to Exhibits		41
Signatures		42

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 2, 2018.

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;

• marketing of natural gas, NGLs and oil;

• leasehold and business acquisitions and joint ventures;

• leasehold terms expiring before production can be established and our costs to extend such terms;

• 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 significant decline of the price of natural gas, NGLs and oil from historic highs, inflation, lack of availability of drilling, production and processing equipment and services, 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 2, 2018.

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)

	March 31, 2018			December 31, 2017
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	21,801		$	17,224
Accounts receivable		113,208			77,609
Assets held for sale		—			206
Other current assets		8,350			12,023
Total current assets		143,359			107,062
PROPERTY AND EQUIPMENT AT COST
Oil and natural gas properties, successful efforts method:
Unproved properties		537,958			459,549
Proved oil and gas properties, net		694,599			647,881
Other property and equipment, net		6,785			6,942
Total property and equipment, net		1,239,342			1,114,372
OTHER NONCURRENT ASSETS
Other assets		5,617			2,093
TOTAL ASSETS	$	1,388,318		$	1,223,527
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	96,048		$	76,174
Accrued capital expenditures		12,689			10,658
Accrued liabilities		39,423			41,662
Accrued interest payable		10,433			21,100
Total current liabilities		158,593			149,594
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs		495,707			495,021
Credit facility		65,000			—
Asset retirement obligations		6,269			6,029
Other liabilities		2,100			529
Total liabilities		727,669			651,173
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, 301,771,111    and 262,740,355 shares issued and outstanding, respectively		3,033			2,637
Additional paid in capital		2,059,418			1,967,958
Treasury stock, shares at cost; 1,499,566 and 992,315 shares, respectively		(3,031	)		(2,096	)
Accumulated deficit		(1,398,771	)		(1,396,145	)
Total stockholders' equity		660,649			572,354
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,388,318		$	1,223,527

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 March 31,
	2018			2017
REVENUES
Natural gas, oil and natural gas liquids sales	$	110,184		$	99,432
Brokered natural gas and marketing revenue		8			2,431
Total revenues		110,192			101,863
OPERATING EXPENSES
Lease operating		9,390			2,343
Transportation, gathering and compression		27,689			32,877
Production and ad valorem taxes		2,445			1,931
Brokered natural gas and marketing expense		48			2,460
Depreciation, depletion and amortization		31,156			26,189
Exploration		15,278			11,581
General and administrative		9,757			10,132
Accretion of asset retirement obligations		155			124
(Gain) loss on sale of assets		(267	)		(5	)
Total operating expenses		95,651			87,632
OPERATING INCOME (LOSS)		14,541			14,231
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		(4,215	)		25,097
Interest expense, net		(12,952	)		(12,462	)
Other income (expense)		—			(19	)
Total other income (expense), net		(17,167	)		12,616
INCOME (LOSS) BEFORE INCOME TAXES		(2,626	)		26,847
INCOME TAX BENEFIT (EXPENSE)		—			—
NET INCOME (LOSS)	$	(2,626	)	$	26,847
NET INCOME (LOSS) PER COMMON SHARE
Basic	$	(0.01	)	$	0.10
Diluted	$	(0.01	)	$	0.10
WEIGHTED AVERAGE COMMON SHARES    OUTSTANDING
Basic		293,450			261,105
Diluted		293,450			264,215

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,    2017		262,740,355	$	2,637	$	1,967,958		$	(2,096	)	$	(1,396,145	)	$	572,354
Stock-based compensation		—		—		1,981			—			—			1,981
Equity issuance costs		—		—		(145	)		—			—			(145	)
Shares of common stock    issued in asset acquisition,    net of equity issuance costs		37,823,596		378		89,642			—			—			90,020
Issuance of common stock    upon vesting of  equity-    based compensation    awards, net of shares    withheld for income    tax withholdings		1,207,160		18		(18	)		(935	)		—			(935	)
Net income (loss)		—		—		—			—			(2,626	)		(2,626	)
Balances, March 31,    2018		301,771,111	$	3,033	$	2,059,418		$	(3,031	)	$	(1,398,771	)	$	660,649

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 Three Months Ended March 31,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(2,626	)	$	26,847
Adjustments to reconcile net income (loss) to net cash provided by    (used in) operating activities
Depreciation, depletion and amortization		31,156			26,189
Exploration expense		6,790			4,988
Stock-based compensation		1,981			2,081
Accretion of asset retirement obligations		155			124
(Gain) loss on derivative instruments		4,215			(25,097	)
Net cash receipts (payments) on settled derivatives		141			(3,989	)
(Gain) loss on sale of assets		(267	)		(5	)
Amortization of deferred financing costs		554			502
Amortization of debt discount		332			330
Changes in operating assets and liabilities:
Accounts receivable		(35,499	)		10,478
Other assets		(459	)		943
Accounts payable and accrued liabilities		(3,179	)		(14,992	)
Net cash provided by operating activities		3,294			28,399
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties		(66,441	)		(66,005	)
Capital expenditures for other property and equipment		(155	)		(178	)
Proceeds from sale of assets		4,099			24
Net cash used in investing activities		(62,497	)		(66,159	)
CASH FLOWS FROM FINANCING ACTIVITIES
Debt issuance costs		(48	)		(1,231	)
Repayments of long-term debt		(92	)		(74	)
Proceeds from credit facility		65,000			—
Equity issuance costs		(145	)		—
Employee tax withholding for settlement of equity compensation awards		(935	)		(1,706	)
Net cash provided by (used in) financing activities		63,780			(3,011	)
Net increase (decrease) in cash and cash equivalents		4,577			(40,771	)
Cash and cash equivalents at beginning of period		17,224			201,229
Cash and cash equivalents at end of period	$	21,801		$	160,458
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	$	23,638		$	23,066
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	$	85		$	124
Additions of other property through debt financing	$	174		$	—
Additions to oil and natural gas properties - changes in accounts payable,    accrued liabilities, and accrued capital expenditures	$	8,864		$	13,126
Asset acquisition through stock issuance	$	90,020		$	—

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, 2017, 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 2, 2018.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2018 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 March 31, 2018 or December 31, 2017.

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 $51.3 million and $52.9 million of accrued revenues, net of certain expenses, at March 31, 2018 and December 31, 2017, 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 the 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 the 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):

	March 31, 2018			December 31, 2017
Oil and natural gas properties:
Unproved	$	537,958		$	459,549
Proved		1,973,468			1,896,081
Gross oil and natural gas properties		2,511,426			2,355,630
Less accumulated depreciation, depletion and amortization		(1,278,869	)		(1,248,200	)
Oil and natural gas properties, net		1,232,557			1,107,430
Other property and equipment		13,837			13,508
Less accumulated depreciation		(7,052	)		(6,566	)
Other property and equipment, net		6,785			6,942
Property and equipment, net	$	1,239,342		$	1,114,372

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 $0.5 million and $0.4 million for the three months ended March 31, 2018 and 2017, 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

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas.  The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company delivers the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials.  The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to further process and transport NGLs are recorded as transportation, gathering and compression expense.

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks near central stabilization facilities and collect a contractually agreed upon index price, net of pricing differentials. The Company transfers control of the product from the central stabilization facilities to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs.  The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

  The following table illustrates the revenue disaggregated by type for the three months ended March 31, 2018 and 2017:

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	Three Months Ended March 31,
	2018		2017
Revenues (in thousands)
Natural gas sales	$	58,483	$	61,420
NGL sales		19,743		17,063
Oil sales		31,958		20,949
Brokered natural gas and marketing revenue		8		2,431
Total revenues	$	110,192	$	101,863

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations is part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.  Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.  Accounts receivable attributable to the Company’s revenue contracts with customers was $51.3 million and $52.9 million at March 31, 2018 and December 31, 2017, respectively.

(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 March 31, 2018 and December 31, 2017 (in thousands):

	March 31, 2018		December 31, 2017
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	51,298	$	52,908
Joint interest owners		60,263		23,154
Derivatives		1,628		1,528
Other		19		19
Total	$	113,208	$	77,609

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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 ($8.9) million and ($5.1) million at March 31, 2018 and December 31, 2017, 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 March 31, 2018 and December 31, 2017, 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 $30.7 million and $25.7 million for the three months ended March 31, 2018 and 2017, 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 March 31, 2018 and 2017. 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.  There were no impairments of proved properties for the three months ended March 31, 2018 or the three months ended March 31, 2017.

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is 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 $6.7 million and $4.1 million for the three months ended March 31, 2018 and 2017, respectively. The increase in impairment charges during the three months ended March 31, 2018 is the result of an increase in expected lease expirations due to the reduction in the Company’s planned future drilling activity due to the current commodity price environment. 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.

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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 three months ended March 31, 2018 and 2017.

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 three months ended March 31, 2018 (in thousands):

	Three Months Ended March 31, 2018
Asset retirement obligations, beginning of period	$	6,029
Additional liabilities incurred		85
Accretion		155
Asset retirement obligations, end of period	$	6,269

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.

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(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.  The Company adopted this standard effective January 1, 2018 using the modified retrospective method.  The Company did not recognize a significant impact on its financial position or results of operations.  Upon adoption of this new standard, the Company did not record a cumulative effect adjustment nor did the Company alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify the impact of future revenue contracts entered into by the Company.  Additional disclosures have been included to provide further detail regarding the Company’s revenue recognition policies.  

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 plans to adopt this standard effective January 1, 2019 using the modified retrospective transition method and is evaluating the standard’s applicability to its various contractual arrangements.  Although the Company believes that the adoption of the standard will result in increases to its assets and liabilities on its consolidated balance sheet as well as changes to the presentation of certain operating expenses on its consolidated statement of operations, the Company has not yet determined the extent of the adjustments that will be required upon implementation of the standard.  The Company continues to monitor relevant industry guidance regarding the implementation of the standard.

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 adopted this standard effective January 1, 2018 and did not recognize a significant impact on its financial position, results of operations, or statement of cash flows.

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 adopted this standard effective January 1, 2018 and considered the new guidance in its assessment of the accounting treatment for the Flat Castle Acquisition. (See Note 4—Acquisition).

Note 4—Acquisition

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, one producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 37.8 million shares of the Company’s common stock (the “Flat Castle Acquisition”).  The transaction was accounted for as an asset acquisition.  Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired.  In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.  

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Note 5—Sale of Oil and Natural Gas Property Interests

During the three months ended March 31, 2018, the Company received approximately $3.8 million from a completed asset sale to a third party totaling approximately 400 acres.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the three months ended March 31, 2018, the Company received approximately $0.3 million from an additional completed asset sale to a third party totaling approximately 50 acres.  As a result of this sale, the Company recognized a gain of approximately $0.3 million.

Note 6—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 March 31, 2018, 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 March 31, 2018, for future production periods:

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Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		30,000	April 2018 – March 2019	$	2.90
		20,000	April 2018 – December 2018	$	2.80
		20,000	July 2018 – September 2018	$	2.81
		40,000	October 2018 – December 2019	$	2.80
		50,000	January 2019 – December 2019	$	2.87
Natural Gas Three-way Collars:
Floor purchase price (put)		30,000	April 2018 – March 2019	$	3.00
Ceiling sold price (call)		30,000	April 2018 – March 2019	$	3.40
Floor sold price (put)		30,000	April 2018 – March 2019	$	2.50
Floor purchase price (put)		40,000	April 2018 – December 2018	$	3.11
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.80
Ceiling sold price (call)		100,000	April 2018 – December 2018	$	3.36
Floor sold price (put)		100,000	April 2018 – December 2018	$	2.50
Floor purchase price (put)		20,000	October 2018 – December 2019	$	2.75
Ceiling sold price (call)		20,000	October 2018 – December 2019	$	3.10
Floor sold price (put)		20,000	October 2018 – December 2019	$	2.30
Floor purchase price (put)		57,500	January 2019 – December 2019	$	2.72
Ceiling sold price (call)		57,500	January 2019 – December 2019	$	3.02
Floor sold price (put)		57,500	January 2019 – December 2019	$	2.30
Natural Gas Call/Put Options:
Call sold		40,000	April 2018 – December 2018	$	3.75
Call sold		30,000	January 2019 – March 2019	$	3.50
Call sold		30,000	April 2019 – December 2019	$	3.00
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
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 Swaps:
		1,000	July 2018 – March 2019	$	61.00
Oil Three-way Collars:
Floor purchase price (put)		4,000	April 2018 – December 2018	$	45.00
Ceiling sold price (call)		4,000	April 2018 – December 2018	$	53.47
Floor sold price (put)		4,000	April 2018 – December 2018	$	35.00
Floor purchase price (put)		2,000	January 2019 – December 2019	$	50.00
Ceiling sold price (call)		2,000	January 2019 – December 2019	$	60.56
Floor sold price (put)		2,000	January 2019 – December 2019	$	40.00

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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 March 31, 2018	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	11,768		$	(6,258	)	$	5,510		Other current assets
Commodity derivatives - noncurrent		3,931			(14	)		3,917		Other assets
Total assets	$	15,699		$	(6,272	)	$	9,427
Liabilities
Commodity derivatives - current	$	(23,012	)	$	6,258		$	(16,754	)	Accrued liabilities
Commodity derivatives - noncurrent		(1,603	)		14			(1,589	)	Other liabilities
Total liabilities	$	(24,615	)	$	6,272		$	(18,343	)

As of December 31, 2017	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	15,971		$	(6,380	)	$	9,591		Other current assets
Commodity derivatives - noncurrent		469			(176	)		293		Other assets
Total assets	$	16,440		$	(6,556	)	$	9,884
Liabilities
Commodity derivatives - current	$	(21,256	)	$	6,380		$	(14,876	)	Accrued liabilities
Commodity derivatives - noncurrent		(252	)		176			(76	)	Other liabilities
Total liabilities	$	(21,508	)	$	6,556		$	(14,952	)

(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 March 31,
		2018			2017
Commodity derivatives	Gain (loss) on derivative instruments	$	(4,215	)	$	25,097

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Note 7—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 March 31, 2018: (in thousands)
Commodity derivative instruments	$	—	$	(8,916	)	$	—	$	(8,916	)
Total	$	—	$	(8,916	)	$	—	$	(8,916	)
As of December 31, 2017: (in thousands)
Commodity derivative instruments	$	—	$	(5,068	)	$	—	$	(5,068	)
Total	$	—	$	(5,068	)	$	—	$	(5,068	)

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 8—Debt).

Note 8—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 months ended March 31, 2018 and 2017, the Company amortized $0.9 million and $0.8 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.

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

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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 March 31, 2018.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at March 31, 2018 was $482.0 million.

Revolving Credit Facility

During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”), entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature 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).

In January 2015, the credit agreement governing the revolving credit facility was amended and restated (as amended and restated, the “Credit Agreement”), primarily to add Eclipse Resources Corporation as a party thereto and thereby subject the Company to the representations, warranties, covenants and events of default provisions therein.  Relative to Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Eclipse Resources Corporation rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I.  Other terms of the Credit Agreement remained generally consistent with Eclipse I’s previous credit agreement.

On February 24, 2016, the Company amended the Credit Amendment 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 also 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 such 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 to the Credit Agreement 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, this 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 to the Credit Agreement that increased the borrowing base from $175 million to $225 million.  

At March 31, 2018, the borrowing base was $225 million and the Company had $65 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $33.6 million and the outstanding borrowings of $65 million, the Company had available borrowing capacity under the revolving credit facility of $126.4 million at March 31, 2018.  Subsequent to March 31, 2018, the Company repaid $20 million on the revolving credit facility, which reduced the outstanding borrowings to $45 million and resulted in available borrowing capacity of $146.4 million.  In April 2018, the Company completed its most recent borrowing base redetermination, which resulted in no change to the borrowing base of $225 million.  The Company’s next scheduled borrowing base redetermination is expected to be completed by October 2018.

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 March 31, 2018. 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 9—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 $0.2 million for the three months ended March 31, 2018 and 2017, respectively.

Note 10—Stock-Based Compensation

The Company is authorized to grant up to 25,000,000 shares of common stock under its Amended and Restated 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 7,199,257 shares were available for future grants under the Plan as of March 31, 2018.

Our stock-based compensation expense was as follows for the three months ended March 31, 2018 and 2017 (in thousands):

	Three Months Ended March 31,
	2018		2017
Restricted stock units	$	1,164	$	1,247
Performance units		728		734
Restricted stock issued to directors		89		100
Total expense	$	1,981	$	2,081

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 March 31, 2018, there was $7.0 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 three months ended March 31, 2018 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2017		4,057,354		$	2.48	$	9,738
Granted		1,498,524			1.70
Vested		(1,378,403	)		3.17
Forfeited		(6,512	)		2.15
Total awarded and unvested, March 31, 2018		4,170,963		$	1.97	$	6,006

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return, 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 March 31, 2018, there was $6.4 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 three months ended March 31, 2018 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2017		3,966,377		$	1.82	$	11,257
Granted		1,498,524			1.92
Vested		—			—
Forfeited		(9,768	)		1.94
Total awarded and unvested, March 31, 2018		5,455,133		$	1.84	$	2,856

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 stock price.  Prior to 2018, the volatility estimate was tied to the Company’s public peer group.  The following table presents the

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assumptions used to determine the fair value for performance stock units granted during the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018			2017
Volatility		89.70	%		50.41	%
Risk-free interest rate		2.37	%		1.34	%

Restricted Stock Issued to Directors

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 months ended March 31, 2017, the Company recognized expense of approximately $0.1 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 months ended March 31, 2018, the Company recognized expense of approximately $0.1 million related to these awards.  As of March 31, 2018, there was approximately less than $0.1 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s directors.

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 months ended March 31, 2018 and 2017, respectively:

	Three Months Ended March 31,
(in thousands, except per share data)	2018								2017
	Income (Loss)			Shares		Per Share			Income (Loss)		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(2,626	)		293,450	$	(0.01	)	$	26,847		261,105	$	0.10
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		3,110
Diluted:
Net income (loss), shares, diluted	$	(2,626	)		293,450	$	(0.01	)	$	26,847		264,215	$	0.10

Note 12—Related Party Transactions

During the three months ended March 31, 2018, the Company incurred approximately $0.2 million 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 related to such services during the three months ended March 31, 2017.  The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms.

Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap.  EnCap has representatives on the Board, and affiliates of EnCap collectively beneficially own a majority of the outstanding shares of our common stock. (See Note 4—Acquisition).

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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 $0.2 million for the three months ended March 31, 2018 and 2017, respectively.

Note 14—Income Tax

For the year ending December 31, 2018, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company expects to incur both a book and tax loss in fiscal year 2018, and thus, no current federal income taxes are anticipated to be paid.  The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to the Company’s year-to-date loss.  On December 22, 2017, the Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, resulted in the reduction in the U.S. statutory rate from 35% to 21%.For the three months ended March 31, 2018, the Company’s overall effective tax rate on operations was different than the federal statutory rate of 21% due primarily to valuation allowances and other permanent differences.

The Company’s interest expense deduction has the potential to be limited as a result of the enactment of the Tax Cuts and Jobs Act; however, the impact is anticipated to be minimal as a result of its full valuation allowance.  Future interpretations relating to the passage of the Tax Cuts and Jobs Act which vary from our current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on our future taxable position.  The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

In forecasting the 2018 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2018. Management reached this conclusion considering several factors such as: (i) the Company’s short tax history, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s balance sheet. At this time, the estimated valuation allowance to be recorded in 2018 is $5.3 million.

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 8—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.

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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 8—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, 2017 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 March 31, 2018, we had assembled an acreage position approximating 199,000 net acres in Eastern Ohio and 43,000 net acres in Pennsylvania, which excludes any acreage currently pending title.  As used in this Quarterly Report, unless the context indicates or otherwise requires, “Eclipse,” “Eclipse Resources,” the “Company,” “we,” “our,” “us” and like terms refer collectively to Eclipse Resources Corporation and its consolidated subsidiaries.

Approximately 135,000 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 15,500 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 95% 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 March 31, 2018, we, or our operating partners, had commenced drilling 242 gross wells within the Utica Core Area and our Marcellus Area, of which 7 gross were top holed, 7 gross were drilling, 12 gross were awaiting completion or were in the process of being completed, and 216 gross had been turned to sales.

As of March 31, 2018, we were operating 2 horizontal rigs in the Utica Core Area. We had average daily production for the three months ended March 31, 2018 of approximately 315.2 MMcfe comprised of approximately 72% natural gas, 16% NGLs and 12% 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 on a per well basis.

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Overview of Results for the Three Months Ended March 31, 2018

During the three months ended March 31, 2018, we achieved the following financial and operating results:

• our average daily net production for the three months ended March 31, 2018 was 315.2 MMcfe per day representing an increase of 9% over the comparable period of the prior year;

• commenced drilling 8 gross (3.7 net) operated Utica Shale wells, commenced completions of 8 gross (5.8 net) operated Utica Shale wells and turned-to-sales 5 gross (3.7 net) operated Utica and Marcellus Shale wells;

• recognized net loss of ($2.6) million for the three months ended March 31, 2018 compared to net income of $26.8 million for the three months ended March 31, 2017; and

• realized Adjusted EBITDAX of $63.0 million for the three months ended March 31, 2018 compared to $50.2 million for three months ended March 31, 2017. 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 daily, high, low and average monthly settled NYMEX Henry Hub prices for natural gas and average daily, high and low NYMEX WTI prices for oil for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018		2017
NYMEX Henry Hub High ($/MMBtu)	$	6.24	$	3.71
NYMEX Henry Hub Low ($/MMBtu)		2.49		2.44
Average Daily NYMEX Henry Hub ($/MMBtu)		3.08		3.02
Average Monthly Settled NYMEX Henry Hub ($/MMBtu)		3.00		3.32
NYMEX WTI High ($/Bbl)	$	66.27	$	54.48
NYMEX WTI Low ($/Bbl)		59.20		47.00
Average Daily NYMEX WTI ($/Bbl)		62.91		51.62

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.

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, 2017.  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 March 31, 2018 and held all other factors constant, then our estimated net proved reserves at December 31, 2017 would have increased by approximately 5% from our previously reported estimated net proved reserves at such time, including a 7% addition of proved undeveloped reserves.  The foregoing estimate is based upon an average SEC price of $2.99 per MMBtu for natural gas and $53.59 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, 2017. There are also numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and

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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 March 31, 2018, cash flows from operations, borrowings under our revolving credit facility, proceeds from asset sales, and proceeds from additional debt and/or equity offerings.

Results of Operations

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

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 March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018		2017		Change
Revenues (in thousands)
Natural gas sales	$	58,483	$	61,420	$	(2,937	)
NGL sales		19,743		17,063		2,680
Oil sales		31,958		20,949		11,009
Brokered natural gas and marketing revenue		8		2,431		(2,423	)
Total revenues	$	110,192	$	101,863	$	8,329

Our production grew by approximately 2.3 Bcfe for the three months ended March 31, 2018 over the same period in 2017 due to new wells that we placed into production. Our production for the three months ended March 31, 2018 and 2017 is set forth in the following table:

	Three Months Ended March 31,
	2018		2017		Change
Production:
Natural gas (MMcf)		20,343.3		19,381.6		961.7
NGLs (Mbbls)		772.7		665.0		107.7
Oil (Mbbls)		565.4		454.1		111.3
Total (MMcfe)		28,371.9		26,096.2		2,275.7
Average daily production volume:
Natural gas (Mcf/d)		226,037		215,351		10,686
NGLs (Bbls/d)		8,586		7,389		1,197
Oil (Bbls/d)		6,282		5,046		1,236
Total (Mcfe/d)		315,243		289,958		25,285

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Our average realized price (including cash derivative settlements and firm third-party transportation costs) received during the three months ended March 31, 2018 was $3.62 per Mcfe compared to $3.23 per Mcfe during the three months ended March 31, 2017. 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 March 31, 2018 and 2017 are shown below:

	Three Months Ended March 31,
	2018		2017		Change
Average realized price (excluding cash settled derivatives    and firm transportation)
Natural gas ($/Mcf)	$	2.87	$	3.17	$	(0.30	)
NGLs ($/Bbl)		25.55		25.66		(0.11	)
Oil ($/Bbl)		56.52		46.13		10.39
Total average prices ($/Mcfe)		3.88		3.81		0.07
Average realized price (including cash settled derivatives,    excluding firm transportation)
Natural gas ($/Mcf)	$	3.05	$	3.01	$	0.04
NGLs ($/Bbl)		24.33		24.07		0.26
Oil ($/Bbl)		52.30		46.28		6.02
Total average prices ($/Mcfe)		3.89		3.66		0.23
Average realized price (including firm transportation,    excluding cash settled derivatives)
Natural gas ($/Mcf)	$	2.49	$	2.60	$	(0.11	)
NGLs ($/Bbl)		25.55		25.66		(0.11	)
Oil ($/Bbl)		56.52		46.13		10.39
Total average prices ($/Mcfe)		3.61		3.39		0.22
Average realized price (including cash settled derivatives    and firm transportation)
Natural gas ($/Mcf)	$	2.67	$	2.44	$	0.23
NGLs ($/Bbl)		24.33		24.07		0.26
Oil ($/Bbl)		52.30		46.28		6.02
Total average prices ($/Mcfe)		3.62		3.23		0.39

Brokered natural gas and marketing revenue was $2.4 million for the three months ended March 31, 2017.  There was less than $0.1 million of brokered natural gas and marketing revenue for the three months ended March 31, 2018.  Brokered natural gas and marketing revenue includes revenue we receive as a result of selling natural gas that is not related to our 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 March 31, 2018, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.  

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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 March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018		2017		Change
Operating expenses (in thousands):
Lease operating	$	9,390	$	2,343	$	7,047
Transportation, gathering and compression		27,689		32,877		(5,188	)
Production and ad valorem taxes		2,445		1,931		514
Depreciation, depletion and amortization		31,156		26,189		4,967
General and administrative		9,757		10,132		(375	)
Operating expenses per Mcfe:
Lease operating	$	0.33	$	0.09	$	0.24
Transportation, gathering and compression		0.97		1.27		(0.30	)
Production and ad valorem taxes		0.09		0.07		0.02
Depreciation, depletion and amortization		1.10		1.00		0.10
General and administrative		0.34		0.39		(0.05	)

Lease operating expense was $9.4 million in the three months ended March 31, 2018 compared to $2.3 million in the three months ended March 31, 2017.  Lease operating expense per Mcfe was $0.33 in the three months ended March 31, 2018 compared to $0.09 in the three months ended March 31, 2017.  The increase of $7.0 million and $0.24 per Mcfe is attributable to an increase in the number of producing wells during the three months ended March 31, 2018 as well as increases in salt water disposal and workover expenses incurred during the three months ended March 31, 2018, in each case, as compared to the three months ended March 31, 2017.  Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.  

Transportation, gathering and compression expense was $27.7 million during the three months ended March 31, 2018 compared to $32.9 million during the three months ended March 31, 2017.  Transportation, gathering and compression expense per Mcfe was $0.97 in the three months ended March 31, 2018 compared to $1.27 in the three months ended March 31, 2017.  The following table details our transportation, gathering and compression expenses for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018		2017		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	9,661	$	10,748	$	(1,087	)
Processing and fractionation		8,501		8,317		184
Liquids transportation and stabilization		1,783		2,761		(978	)
Marketing		7		12		(5	)
Firm transportation		7,737		11,039		(3,302	)
	$	27,689	$	32,877	$	(5,188	)
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.34	$	0.42	$	(0.08	)
Processing and fractionation		0.30		0.32		(0.02	)
Liquids transportation and stabilization		0.06		0.11		(0.05	)
Marketing		—		—		—
Firm transportation		0.27		0.42		(0.15	)
	$	0.97	$	1.27	$	(0.30	)

The decrease of $5.2 million to transportation, gathering and compression expense in the three months ended March 31, 2018 was due to our lower contracted firm transportation and utilization of third party volumes.  The decrease of $0.30 per Mcfe was primarily related to lower contractual rates, utilization of third party volumes and fixed costs spread over increased production.

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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 March 31, 2018 compared to $1.9 million in the three months ended March 31, 2017. Production and ad valorem taxes per Mcfe was $0.09 in the three months ended March 31, 2018 compared to $0.07 in the three months ended March 31, 2017.  The increase in production and ad valorem taxes is due to increased production for the three months ended March 31, 2018.  The $0.02 increase on a per unit basis is due to the increased percentage of condensate production.

Depreciation, depletion and amortization was approximately $31.2 million in the three months ended March 31, 2018 compared to $26.2 million in the three months ended March 31, 2017. The increase in the three months ended March 31, 2018 when compared to the three months ended March 31, 2017 is due to the increase in production for the three months ended March 31, 2018.  On a per Mcfe basis, DD&A increased to $1.10 in the three months ended March 31, 2018 from $1.00 in the three months ended March 31, 2017, which was predominantly driven by the higher depletion rate resulting from increased proved property costs for the three months ended March 31, 2018.

General and administrative expense was $9.8 million for the three months ended March 31, 2018 compared to $10.1 million for the three months ended March 31, 2017.  General and administrative expense per Mcfe was $0.34 in the three months ended March 31, 2018 compared to $0.39 in the three months ended March 31, 2017.  The decrease of $0.4 million during the three months ended March 31, 2018 when compared to three months ended March 31, 2017 was primarily due to reduced personnel costs compared to the prior year period.  The decrease of $0.05 per Mcfe is due to fixed costs being spread across higher production as of March 31, 2018 as compared to March 31, 2017.  General and administrative expense includes $2.0 million and $2.1 million of stock-based compensation expense for the three months ended March 31, 2018 and 2017, 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 March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018			2017			Change
Other operating expenses (in thousands):
Brokered natural gas and marketing expense	$	48		$	2,460		$	(2,412	)
Exploration		15,278			11,581			3,697
Accretion of asset retirement obligations		155			124			31
(Gain) loss on sale of assets		(267	)		(5	)		(262	)

Brokered natural gas and marketing expense was less than $0.1 million for the three months ended March 31, 2018 compared to $2.5 million for the three months ended March 31, 2017.  Brokered natural gas and marketing expenses relate to gas purchases for brokered natural gas that we buy and sell that is not related to our 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 March 31, 2018, 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 $15.3 million for the three months ended March 31, 2018 compared to $11.6 million for the three months ended March 31, 2017. The following table details our exploration-related expenses for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018		2017		Change
Exploration expenses (in thousands):
Geological and geophysical	$	665	$	415	$	250
Delay rentals		7,823		6,177		1,646
Impairment of unproved properties		6,696		4,125		2,571
Dry hole and other		94		864		(770	)
	$	15,278	$	11,581	$	3,697

Delay rentals were $7.8 million for the three months ended March 31, 2018 compared to $6.2 million for the three months ended March 31, 2017.  The increase in delay rental expenses relates to converting of future lump-sum extension payments into annual delay rentals during the three months ended March 31, 2018.

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Impairment of unproved properties was $6.7 million for the three months ended March 31, 2018 compared to $4.1 million for the three months ended March 31, 2017. The increase in impairment charges during the three months ended March 31, 2018 is the result of an increase in expected lease expirations due to the reduction 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 $0.2 million for the three months ended March 31, 2018 compared to $0.1 million for three months ended March 31, 2017. The increase in accretion expense primarily relates to the asset retirement obligations associated with the increase in the number of our producing wells during the three months ended March 31, 2018.

(Gain) loss on sale of assets was ($0.3) million for the three months ended March 31, 2018 compared to less than $0.1 million for the three months ended March 31, 2017.  The increase is due to the sale of pipeline assets during the three months ended March 31, 2018.

Other Income (Expense)

Gain (loss) on derivative instruments was ($4.2) million for the three months ended March 31, 2018 compared to $25.1 million for the three months ended March 31, 2017, primarily due to changes in commodity prices during each year. Cash receipts (payments) were approximately $0.1 million and ($4.0) million for derivative instruments that settled during the three months ended March 31, 2018 and March 31, 2017, respectively.

Interest expense, net was $13.0 million for the three months ended March 31, 2018 compared to $12.5 million for three months ended March 31, 2017.  The increase in interest expense primarily relates to our increased credit facility utilization during the three months ended March 31, 2018.

Income tax benefit (expense) was not recognized for the three months ended March 31, 2018 and 2017 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income, respectively.

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, and proceeds from issuances of debt and equity securities.

Three Months Ended March 31, 2018 Compared to the Three Months Ended March 31, 2017

Net cash provided by operations in the three months ended March 31, 2018 was $3.3 million compared to $28.4 million in the three months ended March 31, 2017. The decrease in cash provided by operators reflects changes in working capital and the timing of cash receipts and disbursements, partially offset by higher revenues.

Net cash used in investing activities in the three months ended March 31, 2018 was $62.5 million compared to $66.2 million in the three months ended March 31, 2017.

During the three months ended March 31, 2018, we:

• spent $66.4 million on capital expenditures for oil and natural gas properties;

• spent $0.2 million on property and equipment; and

• received $4.1 million of proceeds relating to the sale of assets.

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During the three months ended March 31, 2017, we:

• spent $66.0 million on capital expenditures for oil and gas properties; and

• spent $0.2 million on property and equipment.

Net cash provided by (used in) financing activities in the three months ended March 31, 2018 was $63.8 million compared to ($3.0) million in the three months ended March 31, 2017.

During the three months ended March 31, 2018, we:

• borrowed $65 million against our revolving credit facility;

• paid $0.1 million in equity issuance costs associated with the Flat Castle Acquisition; and

• withheld from employees shares totaling $0.9 million related to the settlement of equity compensation awards.

During the three months ended March 31, 2017, we:

• spent $1.2 million related to the incurrence of debt issuance costs from the amendment to the credit agreement governing our revolving credit facility; and

• withheld from employees shares totaling $1.7 million related to the settlement of equity compensation awards.

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 2018.

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 March 31, 2018, 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.

Credit Arrangements

Long-term debt at March 31, 2018 and December 31, 2017, excluding discount, totaled $510.5 million. Information related to our credit arrangements is described in “Note 8—Debt” to our consolidated financial statements and is incorporated herein by reference.

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

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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 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 March 31, 2018, we had entered into the following derivative contracts:

Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		30,000	April 2018 – March 2019	$	2.90
		20,000	April 2018 – December 2018	$	2.80
		20,000	July 2018 – September 2018	$	2.81
		40,000	October 2018 – December 2019	$	2.80
		50,000	January 2019 – December 2019	$	2.87
Natural Gas Three-way Collars:
Floor purchase price (put)		30,000	April 2018 – March 2019	$	3.00
Ceiling sold price (call)		30,000	April 2018 – March 2019	$	3.40
Floor sold price (put)		30,000	April 2018 – March 2019	$	2.50
Floor purchase price (put)		40,000	April 2018 – December 2018	$	3.11
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.80
Ceiling sold price (call)		100,000	April 2018 – December 2018	$	3.36
Floor sold price (put)		100,000	April 2018 – December 2018	$	2.50
Floor purchase price (put)		20,000	October 2018 – December 2019	$	2.75
Ceiling sold price (call)		20,000	October 2018 – December 2019	$	3.10
Floor sold price (put)		20,000	October 2018 – December 2019	$	2.30
Floor purchase price (put)		57,500	January 2019 – December 2019	$	2.72
Ceiling sold price (call)		57,500	January 2019 – December 2019	$	3.02
Floor sold price (put)		57,500	January 2019 – December 2019	$	2.30
Natural Gas Call/Put Options:
Call sold		40,000	April 2018 – December 2018	$	3.75
Call sold		30,000	January 2019 – March 2019	$	3.50
Call sold		30,000	April 2019 – December 2019	$	3.00
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)

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Oil Derivatives

Description	Volume (Bbls/d)		Production Period	WeightedAverage Price($/Bbl)
Oil Swaps:
		1,000	July 2018 – March 2019	$	61.00
Oil Three-way Collars:
Floor purchase price (put)		4,000	April 2018 – December 2018	$	45.00
Ceiling sold price (call)		4,000	April 2018 – December 2018	$	53.47
Floor sold price (put)		4,000	April 2018 – December 2018	$	35.00
Floor purchase price (put)		2,000	January 2019 – December 2019	$	50.00
Ceiling sold price (call)		2,000	January 2019 – December 2019	$	60.56
Floor sold price (put)		2,000	January 2019 – December 2019	$	40.00

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 March 31, 2018, 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 March 31, 2018. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $25.1 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $27.2 million. A hypothetical 10 percent decrease in future oil prices would increase future earnings related to derivatives by $9.7 million. Similarly, a hypothetical 10 percent increase in future oil prices would decrease future earnings related to derivatives by $10.7 million.

Subsequent to March 31, 2018, we entered into the following derivative instruments to mitigate our exposure to natural gas and oil prices:

Description	Volume (MMbtu/d)		Production Period	Weighted Average Price ($/MMbtu)
Basis Swaps:
Appalachia - Dominion		20,000	January 2020 – December 2020	$	(0.59	)

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 2018 of between approximately $300 - $320 million, allocated approximately 84% for drilling and completions activities, 8% for midstream activities, 6% for land activities and 2% for other capital requirements.  Following the end of the first quarter, Eclipse reduced its 2018 capital expenditure budget to approximately $250 million due to the current negative outlook of natural gas prices.  The revised 2018 capital budget is expected to be substantially funded through internally generated cash flows and the Company’s current cash balance, borrowings under the revolving credit facility and/or other debt and equity offerings.  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, additional borrowings under our revolving credit facility 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.

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Capitalization

As of March 31, 2018 and December 31, 2017, our total debt, excluding debt discount and capitalization were as follows (in millions):

	March 31, 2018		December 31, 2017
Senior unsecured notes	$	510.5	$	510.5
Stockholders' equity		660.6		572.4
Total capitalization	$	1,171.1	$	1,082.9

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 March 31, 2018 and December 31, 2017, 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 March 31, 2018 reflects accrued interest payable of $10.4 million, compared to $21.1 million as of December 31, 2017.

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 March 31, 2018 and December 31, 2017, 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.

Information related to our interest rates is described in “Note 8—Debt” to our consolidated financial statements and is incorporated herein by reference.

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 2018 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 2018 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;

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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 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 March 31,
$ thousands	2018			2017
Net income (loss)	$	(2,626	)	$	26,847
Depreciation, depletion and amortization		31,156			26,189
Exploration expense		15,278			11,581
Stock-based compensation		1,981			2,081
Accretion of asset retirement obligations		155			124
(Gain) loss on sale of assets		(267	)		(5	)
(Gain) loss on derivative instruments		4,215			(25,097	)
Net cash receipts (payments) on settled derivatives		141			(3,989	)
Interest expense, net		12,952			12,462
Other (income) expense		—			19
Adjusted EBITDAX	$	62,985		$	50,212

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, 2017 contained in the Company’s Annual Report on Form 10-K. Information related to recent accounting pronouncements is described in “Note 3—Summary of Significant Accounting Policies” to our condensed consolidated financial statements in this Quarterly Report on Form 10-Q 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 75% of our December 31, 2017 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 6—Derivative Instruments.”

Interest Rate Risk

Information related to our interest rates is described in “Note 8—Debt” to our consolidated financial statements and is incorporated herein by reference.

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 March 31, 2018, 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.

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.

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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, you should carefully consider the factors discussed in “Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March 2, 2018, 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.

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).
4.4	Registration Rights Agreement, dated as of January 18, 2018, by and among Eclipse Resources Corporation, Eclipse Resources-PA, LP, and Travis Peak Resources, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 22, 2018).
10.1*†	Eclipse Resources Corporation Amended and Restated 2014 Long-Term Incentive Plan, dated February 22, 2018.
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.
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 or compensatory plan or arrangement.

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SIGNATURES

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

May 4, 2018	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

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EX-10.1

 Exhibit 10.1

ECLIPSE RESOURCES CORPORATION 2014 LONG-TERM INCENTIVE PLAN,

AS AMENDED BY THE FIRST AMENDMENT

Table of Contents

ARTICLE I	GENERAL	1
Section 1.01	Purposes	1
Section 1.02	Definitions	1
Section 1.03	Administration	3
(a)	Authority of the Committee	3
(b)	Manner of Exercise of Committee Authority	3
(c)	Limitation of Liability	3
Section 1.04	Stock Subject to Plan	4
(a)	Total Shares Available	4
(b)	Stock Offered	4
Section 1.05	Eligibility	4
Section 1.06	Award Limitations	4
(a)	Annual Limit on Qualified Performance-Based Awards	4
(b)	Plan Limit on Awards of Incentive Stock Options	4
(c)	Annual Limit on Options and SARs	4
(d)	Annual Limit on Awards to Non-Employee Directors	4
ARTICLE II	AWARDS UNDER THE PLAN	4
Section 2.01	General	4
Section 2.02	Options	4
(a)	Exercise Price	4
(b)	Time and Conditions of Exercise	5
(c)	Payment	5
(d)	Exercise Term	5
(e)	ISOs	5
(f)	Prohibition on Repricing	5
Section 2.03	Stock Appreciation Rights	5
(a)	Right to Payment	5
(b)	Time and Conditions of Exercise	5
(c)	Prohibition on Repricing	6
Section 2.04	Restricted Stock	6
(a)	Restrictions	6
(b)	Rights as Stockholder	6
(c)	Certificates for Stock	6
(d)	Dividends and Splits	6
Section 2.05	Restricted Stock Units	6
Section 2.06	Dividend Equivalent Rights	6
Section 2.07	Stock or Other Stock-Based Awards	7
Section 2.08	Performance Awards	7
(a)	Performance Conditions	7
(b)	Performance Awards Granted to Covered Employees	7
(c)	Written Determinations	7
ARTICLE III	PROVISIONS APPLICABLE TO AWARDS	8
Section 3.01	Term of Awards	8
Section 3.02	Forfeiture Events	8
Section 3.03	No Rights as a Stockholder	8
Section 3.04	Form and Timing of Payment under Awards; Deferrals	8
Section 3.05	Existence of Plans and Awards	8
Section 3.06	Change of Control	9
(a)	General	9
(b)	Options and SARs	9
Section 3.07	Adjustments	9
Section 3.08	Substitute Awards	9
Section 3.09	Transferability of Awards	10

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Section 3.10	Taxes	10
Section 3.11	Amendment, Modification and Termination	10
Section 3.12	Correction of Errors	10
Section 3.13	Limitation on Rights Conferred under Plan	11
Section 3.14	Unfunded Status of Awards	11
Section 3.15	Nonexclusivity of this Plan	11
Section 3.16	Fractional Shares	11
Section 3.17	Severability	11
Section 3.18	Governing Law	11
Section 3.19	Conditions to Delivery of Stock	11
Section 3.20	Special Provisions Related Section 409A of the Code	11
Section 3.21	Plan Establishment and Term	12

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ARTICLE I

GENERAL

Section 1.01 Purposes. The purposes of the Eclipse Resources Corporation 2014 Long-Term Incentive Plan (the “Plan”) are to assist the Company and its Affiliates to attract, retain and motivate officers, directors, employees (including prospective employees) and consultants, and to promote the alignment of their interests with those of the Company’s stockholders.

Section 1.02Definitions. Wherever the following terms are used they will have the meanings set forth below, unless the context clearly indicates otherwise:

(a) “Affiliate” means a corporation, partnership, business trust, limited liability company, or other form of business organization at least a majority of the total combined voting power of all classes of stock or other equity interests of which is directly or indirectly owned by the Company.

(b) “Award” means any Option, SAR, Restricted Stock Award, Restricted Stock Unit, Dividend Equivalent Right, Other Stock-Based Award or Performance Award, together with any other right or interest granted under the Plan to a Participant.

(c) “Award Agreement” means the written document or documents by which each Award is evidenced.

(d) “Beneficial Owner” has the meaning set forth in Rule 13d-3 under the Exchange Act.

(e) “Beneficiary” means one or more persons, trusts or other entities designated by a Participant, in his or her most recent written beneficiary designation filed with the Committee (pursuant to a form prescribed by the Committee), to receive the benefits specified under this Plan upon such Participant’s death, or to which Awards or other rights are transferred as permitted under Section 3.09. If upon a Participant’s death there is no designated Beneficiary or surviving designated Beneficiary, the term Beneficiary means the Participant’s estate.

(f) “Board” means the Company’s Board of Directors.

(g) “Change of Control” means, except as otherwise provided in an Award Agreement, the occurrence of any of the following:

(i) A transaction or series of related transactions (other than an offering of Stock to the general public through a registration statement filed with the Securities and Exchange Commission) whereby any “person” or related “group” of “persons” (as such terms are used in Sections 13(d) and 14(d)(2) of the Exchange Act) (other than the Company, any subsidiary of the Company, any employee benefits plan (or related trust) sponsored or maintained by the Company or any subsidiary of the Company, or any “person” that, prior to such transaction, directly or indirectly controls, is controlled by, or is under common control with, the Company (collectively, “Excluded Persons”)) directly or indirectly becomes the Beneficial Owner of securities of the Company representing fifty percent (50%) or more of the combined voting power of the Company’s then outstanding securities with respect to the election of directors of the Company; or

(ii) During any twenty-four (24) consecutive month period, the individuals who, at the beginning of such period, constitute the Board (the “Incumbent Directors”) cease for any reason other than death to constitute at least a majority of the Board; provided, however, that except as set forth in the following sentence, an individual who becomes a member of the Board subsequent to the beginning of the twenty-four (24) month period will be deemed to have satisfied such twenty-four (24) month requirement (and be an Incumbent Director) if such director was elected by, or on the recommendation of or with the approval of, at least two-thirds (2/3) of the directors who then qualified as Incumbent Directors;

(iii) The consummation of a sale or disposition of all or substantially all the Company’s assets in one or a series of related transactions;

(iv) The consummation of a merger, consolidation, or reorganization of the Company or the acquisition of outstanding Stock and as a result of or in connection with such transaction (A) fifty (50%) or more of the outstanding Stock or the voting securities of the Company outstanding immediately prior thereto or the outstanding shares of common stock or the combined voting power of the outstanding voting securities of the surviving entity are owned, directly or indirectly, by any other person other than an Excluded Person, or (B) the voting securities of

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the Company outstanding immediately prior thereto do not immediately after such transaction continue to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) more than fifty percent (50%) of the combined voting power of the voting securities of the Company (or such surviving entity) outstanding immediately after such merger, consolidation, or reorganization; or

(v) The stockholders of the Company approve a plan of complete liquidation or dissolution of the Company.

(h) “Code” means the Internal Revenue Code of 1986, as amended. Any reference herein to a section of the Code includes any successor provision to such section.

(i) “Committee” means a committee of two or more directors designated by the Board to administer this Plan, and which, to the extent the Board determines it is appropriate for Awards under the Plan to qualify for the exemption available under Rule 16b-3, will be a committee or subcommittee of the Board composed of two or more members, each of whom is a “non-employee director” within the meaning of Rule 16b-3. With respect to any Committee action affecting a Qualified Performance-Based Award outstanding as of November 2, 2017, the Committee shall be composed of two or more members, each of whom is an “outside director” within the meaning of section 162(m) of the Code as in effect as of November 1, 2017 (herein “Prior Section 162(m)”).

(j) “Dividend Equivalent Right” means a right granted under Section 2.06, which represents an unfunded and unsecured promise to pay to the recipient amounts equal to all or any portion of the regular cash dividends that would be paid on shares of Stock covered by an Award if such shares had been delivered pursuant to an Award.

(k) “Effective Date” means, notwithstanding the Plan’s establishment date described in Section 3.21, the first date on which Awards may be granted pursuant to the Plan, which date will be immediately prior to the closing of the initial public offering of the Company.

(l) “Eligible Person” means an individual described in Section 1.05.

(m) “Exchange Act” means the Securities Exchange Act of 1934, as amended.

(n) “Exercise Price” means (i) the case of Options, the price specified in the recipient’s Award Agreement as the price-per-share of Stock at which such share can be purchased pursuant to the Option, or (ii) in the case of SARs, the price specified in the recipient’s Award Agreement as the reference price-per-share of Stock used to calculate the amount payable upon settlement of the SAR.

(o) “Fair Market Value” means, with respect to Stock as of any specified date, (i) if the Stock is traded on a national securities exchange, the closing price of the Stock on the immediately preceding date (or if no sales occur on that date, on the last preceding date on which such sales of the Stock are so reported); (ii) if the Stock is not traded on a national securities exchange but is traded over the counter, the average between the reported high and low or closing bid and asked prices of the Stock on the most recent date on which Stock was publicly traded; (iii) if the Stock is not publicly traded, the amount determined by the Committee in its discretion in such manner as it deems appropriate; or (iii) if the specified date is the date of an initial public offering of Stock, the offering price under such initial public offering. In all events, Fair Market Value will be determined pursuant to a method that complies with the requirements of section 409A of the Code.

(p) “Incentive Stock Option” or “ISO” means an Option that is intended to qualify for special Federal income tax treatment pursuant to sections 421 and 422 of the Code, and which is so designated in the applicable Award Agreement.

(q) “Non-Employee Director” means a member of the Board who is not an employee of the Company or any of its subsidiaries.

(r) “Nonqualified Stock Option” means an Option that is not an Incentive Stock Option.

(s) “Option” means a right granted to a Participant under Section 2.02 to purchase Stock at a specified price during specified time periods.

(t) “Other Stock-Based Award” means an Award granted to a Participant under Section 2.07.

(u) “Participant” means, as of a specified date, a person who holds an Award that is outstanding as of such specified date.

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(v) “Performance Award” means a right, granted to a Participant under Section 2.08, to receive a cash payment, Stock or other Award based upon performance criteria specified by the Committee.

(w) “Qualified Performance-Based Award” means a Performance Award granted to a Covered Person that is intended to qualify as “performance-based compensation” within the meaning of Prior Section 162(m).

(x) “Restricted Stock” means Stock granted to a Participant under Section 2.03, that is subject to certain restrictions and to a risk of forfeiture.

(y) “Restricted Stock Unit” means an unfunded and unsecured right granted to a Participant under Section 2.05, to receive Stock, cash or a combination thereof at the end of a specified period, which right is subject to certain restrictions and to a risk of forfeiture.

(x) “Rule 16b-3” means Rule 16b-3, promulgated by the Securities and Exchange Commission under section 16 of the Exchange Act, applicable to the Plan and Participants.

(aa) “Securities Act” means the Securities Act of 1933, as amended.

(bb) “Stock” means the Company’s common stock, par value $0.01 per share, and such other securities as may be substituted for Stock pursuant to Section 3.07.

(cc) “Stock Appreciation Right” or “SAR” means a right to receive, upon exercise thereof, the excess of (i) the Fair Market Value of one share of Stock on the date of exercise over (ii) the exercise price of the SAR.

Section 1.03Administration.

(a) Authority of the Committee. The Plan will be administered by the Committee except to the extent the Board elects to administer the Plan, in which case references herein to the “Committee” are deemed to be references to the “Board.” The Committee has complete control over the administration of the Plan and has the authority in its sole discretion to (i) exercise all of the powers granted to it under the Plan, (ii) to the extent not inconsistent with the Plan, prescribe, amend and rescind rules and regulations relating to the Plan including rules governing its own operations, (iii) make all determinations necessary or advisable in administering the Plan, (iv) correct any defect, supply any omission and reconcile any inconsistency in the Plan, (v) grant Awards and determine who will receive Awards, when such Awards will be granted and the terms of such Awards, including setting forth provisions with regard to the termination of a recipient’s employment or service, (vi) accelerate the time or times at which an Award becomes vested, unrestricted or may be exercised, and (vii) waive or amend any goals, restrictions or conditions set forth in an Award Agreement, unless otherwise provided in the Award Agreement. The determinations of the Committee will be final, binding and conclusive. By accepting any Award under the Plan, each Participant and each person claiming under or through him or her will be conclusively deemed to have indicated his or her acceptance and ratification of, and consent to, any action taken under the Plan by the Committee.

(b) Manner of Exercise of Committee Authority. Actions of the Committee may be taken by the vote of a majority of its members present at a meeting (which may be held telephonically). Any action taken by written instrument signed by a majority of the Committee members, and action so taken, will be fully as effective as if it had been taken by a vote at a meeting. The Committee may allocate among its members and delegate to any person who is not a member of the Committee, any of its powers, responsibilities or duties. In delegating its authority the Committee will consider the extent to which any delegation may cause an Award to fail to be deductible under Prior Section 162(m) or to fail to meet the requirements of Rule 16b-3.

(c) Limitation of Liability. The Committee and each member thereof will be entitled to, in good faith, rely or act upon any report or other information furnished to him or her by any officer or employee of the Company, the Company’s legal counsel, independent auditors, consultants or any other agents assisting in the administration of this Plan. Members of the Committee and any officer or employee of the Company acting at the direction or on behalf of the Committee will not be personally liable for any action or determination taken or made in good faith with respect to this Plan, and will, to the fullest extent permitted by law, be indemnified and held harmless by the Company with respect to any such action or determination. The foregoing right of indemnification is not exclusive of any other rights of indemnification to which the member may be entitled under the Company’s certificate of incorporation or by-laws, each as may be amended from time to time, or otherwise.

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Section 1.04Stock Subject to Plan.

(a) Total Shares Available. Subject to adjustment as provided in Section 3.07, the aggregate number of shares of Stock reserved and available for issuance under the Plan will be 25,000,000. No Award may be granted if the number of shares of Stock to be delivered in connection with such Award exceeds the number of shares of Stock remaining available under the Plan minus the aggregate number of shares of Stock to be delivered in connection with then-outstanding Awards. If an Award is forfeited or otherwise terminates or is canceled without the delivery of shares of Stock, shares of Stock are surrendered or withheld from an Award to satisfy any obligation of the Participant (including Federal or state taxes) or shares of Stock owned by a Participant are tendered to pay the exercise price of an Award, then the shares of Stock covered by such forfeited, terminated or canceled Award or which are equal to the number of shares of Stock surrendered, withheld or tendered, will again become available for issuance under the Plan.

(b) Stock Offered. The shares of Stock that may be delivered pursuant to Awards may be authorized but unissued Stock or authorized and issued Stock held in the Company’s treasury, or otherwise acquired for purposes of the Plan.

Section 1.05Eligibility. Awards under the Plan may be made to current, former (solely with respect to their final year of service) and prospective officers, directors, employees and consultants of the Company or an Affiliate as the Committee may select.

Section 1.06Award Limitations. Except as provided under this Section 1.06, there is no limit on the amount of cash and securities (other than the overall Plan limit on shares of Stock as provided in Section 1.04) that may be subject to Awards to any Eligible Person under the Plan.

(a) Plan Limit on Awards of Incentive Stock Options. Subject to adjustment as provided in Section 3.07, no more than 16,000,000 shares of Stock that can be delivered under the Plan may be deliverable pursuant to the exercise of Incentive Stock Options.

(b) Annual Limit on Options and SARs. In any single calendar year an employee may not be granted Options or SARs covering or relating to more than 4,000,000 shares of Stock, subject to adjustment in a manner consistent with any adjustment made pursuant to Section 3.07.

(c) Annual Limit on Awards to Non-Employee Directors. The maximum number of shares of Stock with respect to which Awards may be granted during any calendar year to any Non-Employee Director shall be 500,000 (as adjusted pursuant to the provisions of Section 3.07). The maximum payment under any Award denominated in dollars that may be granted during any calendar year to any Non-Employee Director shall be $1,000,000.

ARTICLE II

AWARDS UNDER THE PLAN

Section 2.01 General. Options, SARs, Restricted Stock Units, Restricted Stock, Performance Awards, Other Stock-Based Awards, or any combination thereof, may be granted to such Eligible Persons and for, covering or relating to, such number of shares of Stock as the Committee may determine. Determinations made by the Committee under the Plan need not be uniform and Awards may be made selectively among Eligible Persons under the Plan, whether or not such Eligible Persons are similarly situated.

Section 2.02 Options. The Committee is authorized to grant Options to Eligible Persons on the following terms and conditions:

(a) Exercise Price. The exercise price per share of Stock under an Option will be determined by the Committee, provided that the exercise price for any Option (other than an Option issued as a substitute Award pursuant to Section 3.08) will not be less than the Fair Market Value per share of Stock on the date of grant (or in the case of an Incentive Stock Option granted to an individual who possesses more than 10 percent of the total combined voting power of all classes of stock of the Company or its parent or any subsidiary, 110% of the Fair Market Value per share of Stock on the date of grant).

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(b) Time and Conditions of Exercise. The Committee will determine the time or times at which an Option may be exercised in whole or in part. Except as otherwise determined by the Committee or provided in an Award Agreement or other written agreement between the Participant and the Company or an Affiliate, in the event that the employment of a Participant with the Company and its Affiliates (or the Participant’s service to the Company and its Affiliates) terminates for any reason, (i) all of the Participant’s Options that were exercisable on the date of such termination of employment or service will remain exercisable for, and will otherwise terminate at the end of, a period of 90 days after the date of such termination, but in no event after the expiration date of the Options, and (ii) all of the Participant’s Options that were not exercisable on the date of such termination will be forfeited immediately; provided, however, that such Options may become fully vested and exercisable in the discretion of the Committee.

(c) Payment. The Committee will determine the methods by which the exercise price of any Option may be paid, the form of payment, and the methods by which shares of Stock will be delivered or deemed to be delivered to a Participant upon his or her exercise of the Option. As determined by the Committee at or after the date of grant of an Option, the payment of the exercise price of an Option may be made, in whole or in part, in the form of (i) cash or cash equivalents, (ii) delivery (by either actual deliver or attestation) of previously-acquired shares of Stock based on the Fair Market Value of such Stock on the date of exercise, (iii) withholding of shares of Stock from the Option based on the Fair Market Value of such Stock on the date of exercise, (iv) broker-assisted market sales, or (v) any other cashless exercise arrangement.

(d) Exercise Term. No Option granted under the Plan may be exercisable for more than ten years following the date of grant of the Option.

(e) ISOs. The Committee may grant Incentive Stock Options only to eligible employees of the Company or its subsidiaries (as defined for this purpose in section 424(f) of the Code). The terms of any ISO granted under this Plan will comply in all respects with the provisions of section 422 of the Code. ISOs may not be granted more than ten years after the earlier of the adoption of this Plan or the approval of this Plan by the Company’s stockholders. Notwithstanding the foregoing, the Fair Market Value of the shares of Stock subject to an ISO and the aggregate Fair Market Value of the shares of stock of any parent or subsidiary corporation (within the meaning of sections 424(e) and (f) of the Code) subject to any other ISO (within the meaning of section 422 of the Code) of the Company or a parent or subsidiary corporation (within the meaning of sections 424(e) and (f) of the Code) that first becomes purchasable by a Participant in any calendar year may not (with respect to that Participant) exceed $100,000, or such other amount as may be prescribed under section 422 of the Code. Failure to comply with this provision will cause the excess to be reclassified as Nonqualified Stock Options in accordance with the Code.

(f) Prohibition on Repricing. Except as otherwise provided in Section 3.07, without the prior approval of the stockholders of the Company: (i) the exercise price of an Option may not be reduced, directly or indirectly, (ii) an Option may not be cancelled in exchange for cash in an amount, or other Awards with a value, that exceeds the excess, if any, of the Fair Market Value of the shares of Stock subject to the Option at the time of the cancellation or exchange over the exercise price of such Option, or for Options or SARs with an exercise price that is less than the exercise price of the original Option, except as permitted in accordance with Section 3.06, and (iii) the Company may not repurchase an Option for value (in cash, substitutions, cash buyouts, or otherwise) from a Participant if the current Fair Market Value of the Stock underlying the Option is lower than the exercise price of the Option.

Section 2.03 Stock Appreciation Rights. The Committee is authorized to grant SARs to Eligible Persons on the following terms and conditions:

(a) Right to Payment. Upon the exercise of a SAR the Participant has the right to receive, for each share of Stock with respect to which the SAR is being exercised, the excess, if any, of (i) the Fair Market Value of one share of Stock on the date of exercise, over (ii) the exercise price of the SAR as determined by the Committee and set forth in the Award Agreement, which exercise price will not be less than the Fair Market Value of the Stock on the date of grant of the SAR.

(b) Time and Conditions of Exercise. The Committee will determine the time or times at which and the circumstances under which a SAR may be exercised in whole or in part (including based on achievement of performance goals or future service requirements), the method of exercise, method of settlement, form of consideration payable in settlement, method by or forms in which Stock will be delivered or deemed to be delivered

5

to Participants, and any other terms and conditions of the SAR. Except as otherwise determined by the Committee or provided in an Award Agreement or other written agreement between the Participant and the Company or an Affiliate, in the event that the employment of a Participant with the Company and its Affiliates (or the Participant’s service to the Company and its Affiliates) terminates for any reason, (i) all of the Participant’s SARs that were exercisable on the date of such termination of employment or service will remain exercisable for, and will otherwise terminate at the end of, a period of 90 days after the date of such termination, but in no event after the expiration date of the SARs, and (ii) all of the Participant’s SARs that were not exercisable on the date of such termination will be forfeited immediately; provided, however, that such SARs may become fully vested and exercisable in the discretion of the Committee.

(c) Prohibition on Repricing. Except as otherwise provided in Section 3.07, without the prior approval of the stockholders of the Company: (i) the exercise price of a SAR may not be reduced, directly or indirectly, (ii) a SAR may not be cancelled in exchange for cash in an amount, or other Awards with a value, that exceeds the excess, if any, of the Fair Market Value of the shares of Stock subject to the SAR at the time of the cancellation or exchange over the exercise price of such SAR, or for Options or SARs with an exercise price that is less than the exercise price of the original SAR, except as permitted in accordance with Section 3.06, and (iii) the Company may not repurchase a SAR for value (in cash, substitutions, cash buyouts, or otherwise) from a Participant if the current Fair Market Value of the Stock underlying the SAR is lower than the exercise price of the SAR.

Section 2.04 Restricted Stock. The Committee may grant Awards of Restricted Stock to Eligible Persons on the following terms and conditions:

(a) Restrictions. Shares of Restricted Stock will be subject to such restrictions on transferability, risk of forfeiture and other restrictions, if any, as the Committee may impose, which restrictions may lapse separately or in combination at such times, under such circumstances (including based on achievement of performance goals or future service requirements), in such installments or otherwise, as the Committee may determine. During the restricted period applicable to the Restricted Stock, the Restricted Stock may not be sold, transferred, pledged, hypothecated, margined or otherwise encumbered by the Participant, except as permitted pursuant to Section 3.09.

(b) Rights as Stockholder. Upon the issuance of shares of Restricted Stock in the name of a Participant the Participant will have the rights of a stockholder with respect to the shares of Restricted Stock and will become the record holder of such shares, subject to the provisions of the Plan and the Award Agreement.

(c) Certificates for Stock. Restricted Stock granted under this Plan may be evidenced in such manner as the Committee may determine. If certificates representing Restricted Stock are registered in the name of the Participant, the Committee may require that such certificates bear an appropriate legend referring to the terms, conditions and restrictions applicable to such Restricted Stock, that the Company retain physical possession of the certificates, and that the Participant deliver a stock power to the Company, endorsed in blank, relating to the Restricted Stock.

(d) Dividends and Splits. As a condition to the grant of an Award of Restricted Stock, the Committee may require or permit a Participant to elect that any cash dividends paid on a share of Restricted Stock be automatically reinvested in additional shares of Restricted Stock, applied to the purchase of additional Awards, or deferred without interest to the date of vesting of the associated Restricted Stock. Unless otherwise determined by the Committee, Stock distributed in connection with a stock split or stock dividend, and other property (other than cash) distributed as a dividend, will be subject to restrictions and a risk of forfeiture to the same extent as the Restricted Stock with respect to which such Stock or other property has been distributed.

Section 2.05 Restricted Stock Units. The Committee may at any time and from time to time grant Restricted Stock Units under the Plan to such Eligible Persons and in such amounts as it determines. Each Restricted Stock Unit will entitle the recipient to receive upon vesting one share of Stock from the Company or an amount of cash equal to the Fair Market Value of one share of Stock, or a combination thereof, as determined by the Committee. Restricted Stock Units granted to a Participant will be subject to risk of forfeiture and other restrictions, if any, as the Committee may impose, which restrictions may lapse separately or in combination at such times, under such circumstances (including based on achievement of performance goals or future service requirements), in such installments or otherwise, as the Committee may determine.

Section 2.06 Dividend Equivalent Rights. The Committee may grant Dividend Equivalent Rights to a Participant, entitling the Participant to receive cash, Stock, other Awards, or other property equal in value to

6

dividends paid with respect to a specified number of shares of Stock. Dividend Equivalent Rights may be awarded on a free-standing basis or in connection with another Award, and may be subject to such restrictions on transferability and risks of forfeiture as the Committee may specify. The Committee may provide that Dividend Equivalent Rights will be paid or distributed when accrued or deemed reinvested in additional Stock, other Awards or other investment vehicles.

Section 2.07 Stock or Other Stock-Based Awards. The Committee is authorized, subject to the limitations under applicable law, to make such other Awards that are payable in, valued in whole or in part by reference to, or otherwise based on or related to shares of Stock, as deemed by the Committee to be consistent with the purposes of the Plan, including without limitation shares of Stock awarded purely as a “bonus” and not subject to any restrictions or conditions, convertible or exchangeable debt securities, other rights convertible or exchangeable into shares of Stock, and Awards valued by reference to the book value of shares of Stock. The Committee will determine the terms and conditions of such Awards.

Section 2.08 Performance Awards.

(a) Performance Conditions. The right of a Participant to exercise or receive a grant or settlement of any Award, and the timing thereof, may be subject to such performance conditions as may be specified by the Committee. The Committee may use such business criteria and other measures of performance as it may deem appropriate in establishing any performance conditions, and may exercise its discretion to reduce or increase the amounts payable under any Award subject to performance conditions.  The Committee may provide that one or more objectively determinable adjustments will be made to one or more of the performance goals. Such adjustments may include one or more of the following: (1) items related to a change in accounting principle; (2) items relating to financing activities; (3) expenses for restructuring or productivity initiatives; (4) other non-operating items; (5) items related to acquisitions; (6) items attributable to the business operations of any entity acquired by the Company during the applicable performance period; (7) items related to the disposal of a business or segment of a business; (8) asset write downs; (9) items related to discontinued operations that do not qualify as a segment of a business under applicable accounting standards; (10) items attributable to any stock dividend, stock split, combination or exchange of stock occurring during the applicable performance period; (11) any other items of significant income or expense which are determined to be appropriate adjustments; (12) items relating to unusual or extraordinary corporate transactions, events or developments, (13) items related to amortization of acquired intangible assets; (14) items that are outside the scope of the Company’s core, on-going business activities; (15) items relating to changes in tax laws; (16) items relating to major licensing or partnership arrangements; (17) items relating to asset impairment charges; (18) items relating to gains or losses for litigation, arbitration and contractual settlements; or (19) items relating to any other unusual or nonrecurring events or changes in applicable law, accounting principles or business conditions identified by the Committee.

(b) Performance Award Pool. The Committee may establish a Performance Award pool, which will be an unfunded pool, for purposes of measuring performance of the Company in connection with Performance Awards. The amount of such Performance Award pool will be based upon the achievement of one or more performance conditions during the given performance period, as specified by the Committee. The Committee may specify the amount of the Performance Award pool as a percentage of any of such criteria, a percentage thereof in excess of a threshold amount, or as another amount which need not bear a strictly mathematical relationship to such criteria.

(c) Settlement of Performance Awards; Other Terms. After the end of each performance period, the Committee will determine the amount, if any, of (i) the Performance Award pool and the maximum amount of the potential Performance Award payable to each Participant in the Performance Award pool, or (ii) the amount of the potential Performance Award otherwise payable to each Participant. Settlement of such Performance Awards will be in cash, Stock, other Awards or other property, in the discretion of the Committee. The Committee will specify the circumstances in which such Performance Awards will be paid or forfeited in the event of a Participant’s termination of employment before the end of a performance period or settlement date.

(c) Written Determinations. All determinations by the Committee as to the achievement of performance goals relating to Qualified Performance Based Awards outstanding as of November 1, 2017, will be made in writing. The Committee may not delegate any responsibility relating to such Qualified Performance Based Performance Awards.

7

ARTICLE III

PROVISIONS APPLICABLE TO AWARDS

Section 3.01Term of Awards. Except as specified herein, the term of each Award will be for such period as may be determined by the Committee; provided, however, that in no event will the term of any Option or SAR exceed a period of ten years (or such shorter term as may be required in respect of an ISO under section 422 of the Code).

Section 3.02Forfeiture Events. Awards under the Plan are subject to any compensation recoupment policy that the Company may adopt from time to time that is applicable by its terms to the Participant. In addition, the Committee may specify in an Award Agreement that the Participant’s rights, payments and benefits with respect to an Award will be subject to reduction, cancellation, forfeiture or recoupment upon the occurrence of certain specified events, in addition to any otherwise applicable vesting or performance conditions of an Award. Such events may include, but will not be limited to, (i) termination of employment or service for cause, (ii) violation of a material policy of the Company or an Affiliate, (iii) breach of noncompetition, confidentiality or other restrictive covenants that may apply to the Participant, (iv) other conduct by the Participant that is detrimental to the business or reputation of the Company or an Affiliate, or (v) a later determination that the vesting of, or amount realized from, a Performance Award was based on materially inaccurate financial statements or any other materially inaccurate performance metric criteria, whether or not the Participant caused or contributed to such material inaccuracy. The Company will seek to recover any Award as required by the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act or any other “clawback” provision required by law or exchange listing standards.

Section 3.03 No Rights as a Stockholder. No Participant (or other person having rights pursuant to an Award) will have any of the rights of a stockholder of the Company with respect to shares of Stock subject to an Award until the delivery of such shares. Except as otherwise provided in Section 3.07, no adjustments will be made for dividends or distributions (whether ordinary or extraordinary, and whether in cash, shares of Stock, other securities or other property) on, or other events relating to, shares of Stock subject to an Award for which the record date is before the date such shares of Stock are delivered.

Section 3.04 Form and Timing of Payment under Awards; Deferrals. Subject to the terms of this Plan and any applicable Award Agreement, payments to be made by the Company or a subsidiary upon the exercise of an Option or SAR or settlement of any other Award may be made in such forms as the Committee may determine, including without limitation cash, Stock, other Awards or other property, and may be made in a single payment or transfer, in installments, or on a deferred basis; provided, however, that any such deferred payment will be set forth in the Award Agreement or otherwise made in a manner that will not result in additional taxes under section 409A of the Code. Except as otherwise provided herein, the Committee may provide that the settlement of any Award be accelerated, and cash paid in lieu of Stock in connection with such settlement or upon occurrence of one or more specified events (in addition to a Change of Control). Installment or deferred payments may be required by the Committee (subject to Section 3.11, including the consent provisions thereof in the case of any deferral of an outstanding Award not provided for in the existing Award Agreement) or permitted at the election of the Participant on terms and conditions established by the Committee and in compliance with the requirements of section 409A of the Code.

Section 3.05Existence of Plans and Awards. The existence of this Plan and the Awards granted hereunder will not affect in any way the right or power of the Company or the stockholders of the Company to make or authorize any adjustment, recapitalization, reorganization or other change in the Company’s capital structure or its business, any merger or consolidation of the Company, any issue of stock or of options, warrants or rights to purchase stock or of bonds, debentures, preferred or prior preference stocks where rights are superior to or affect the Stock or the rights thereof or which are convertible into or exchangeable for Stock, or the dissolution or liquidation of the Company or any sale, lease, exchange or other disposition of all or any part of its assets or business or any other corporate act or proceeding, whether of a similar character or otherwise.

8

Section 3.06Change of Control.

(a) General. Except as otherwise provided in an Award Agreement, in connection with a Change of Control the Committee may, acting in its sole discretion and without the consent of any holder of an Award, accelerate the vesting, delivery or exercisability of, or the lapse of restrictions or deemed satisfaction of performance goals with respect to, any Award. The exercise of the Committee’s discretion under the preceding sentence may vary among individual holders and may vary among Awards. Unless otherwise provided in the applicable Award Agreement and except as otherwise determined by the Committee, in the event of a merger, consolidation, mandatory share exchange or other similar business combination of the Company with or into any other entity (“successor entity”) or any transaction in which another person or entity acquires all of the issued and outstanding Stock, or all or substantially all of the assets of the Company, outstanding Awards may be assumed or a substantially equivalent Award may be substituted by such successor entity or a parent or subsidiary of such successor entity, and such an assumption or substitution will not be deemed to violate this Plan (including, without limitation, Section 2.02(f) or Section 2.03(c)), or any provision of any Award Agreement.

(b) Options and SARs. Upon a Change of Control described in Section 1.02(g)(iii) or (iv) (a “Covered Transaction”), the Committee, acting in its sole discretion, may:

(i) Terminate and cancel any outstanding and unexercised Option or SAR, immediately following which all rights of the holder thereunder will terminate, provided that no Option or SAR may be terminated and canceled without the consent of the holder before the expiration of ten (10) days following the later of date on which the Option or SAR is exercisable or the date on which the holder receives written notice of the Covered Transaction; or

(ii) Require the mandatory surrender to the Company any outstanding and unexercised Option or SAR (irrespective of whether such Option or SAR is then exercisable) at, preceding or following the time of the Covered Transaction, upon which surrender the Committee will cancel such Option or SAR and pay to the holder an amount of cash (or other consideration including securities or other property) per share equal to the excess, if any, of the Fair Market Value of the shares of Stock subject to the Option or SAR immediately prior to the Covered Transaction (the “Change of Control Price”) over the exercise price of such Option or SAR, provided, that, if the exercise price equals or exceeds the Change of Control Price no amount will be payable upon surrender of the Option or SAR.

(c) Dissolution or Liquidation. To the extent not previously exercised, settled or assumed, Options, SARs and Performance Awards shall terminate immediately prior to the dissolution or liquidation of the Company.

Section 3.07Adjustments. The Committee may adjust the number of shares of Stock authorized pursuant to Section 1.04(a) and will adjust (including, without limitation, by payment of cash) the terms of any Awards (including, without limitation, the number of shares of Stock covered by each Award, the type of property to which the Award relates and the exercise price of any Award), in such manner as it deems appropriate to prevent the enlargement or dilution of rights, for any increase or decrease in the number of issued shares of Stock (or issuance of shares of stock other than shares of Stock) resulting from a recapitalization, stock split, reverse stock split, stock dividend, spinoff, splitup, combination, reclassification or exchange of shares of Stock, merger, consolidation, rights offering, separation, reorganization or any other change in the corporate structure or event, the Committee determines affects the capitalization of the Company; provided, however, that no such adjustment will be required if the Committee determines that such action would cause an Award to fail to satisfy the conditions of an applicable exception from the requirements of Section 409A or otherwise would subject a Participant to an additional tax imposed under Section 409A in respect of an Award. After any adjustment made pursuant to this Section 3.06, the number of shares of Stock subject to each outstanding Award will be rounded down to the nearest whole number as determined by the Committee.

Section 3.08Substitute Awards. The Committee may grant Awards under the Plan in substitution for stock and stock-based awards held by employees of another entity who become employees of the Company or an Affiliate as a result of a merger or consolidation of the former employing entity with the Company or a Subsidiary or the acquisition by the Company or a Subsidiary of property or stock of the former employing entity. The Committee may direct that the substitute awards be made on such terms and conditions as the Committee determines appropriate in the circumstances.

9

Section 3.09Transferability of Awards. No Award (or any rights and obligations thereunder) may be sold, exchanged, transferred or assigned, whether voluntarily or involuntarily, other than by will or by the laws of descent and distribution, and all such Awards (and any rights thereunder) will be exercisable during the life of the Participant only by the Participant or the Participant’s legal representative. Notwithstanding the preceding sentence, the Committee may permit, under such terms and conditions that it deems appropriate in its sole discretion, (a) that a Participant may transfer an Award in whole or in part without payment of consideration to a member of the Participant’s immediate family, to a trust established for the benefit of a member of the Participant’s immediate family, or to a partnership whose only partners are members of the Participant’s immediate family, or (b) that except as prohibited by Rule 16b-3, a Participant may transfer all or a portion of an Award to a person for which the Participant is entitled to a deduction for a “charitable contribution” under section 170(a)(i) of the Code, provided in either case that no further transfer by such permitted transferee will be permitted, and providedfurther that the exercise of the Award remains the power and responsibility of the Participant or his or her legal representative. Any sale, exchange, transfer or assignment violation of the provisions of this Section 3.09 will be null and void. All of the terms and conditions of this Plan and the Award Agreements will be binding upon any permitted successors and assigns.

Section 3.10Taxes. As a condition to the delivery of any shares Stock, other property or cash pursuant to any Award or the lifting or lapse of restrictions on any Award, or in connection with any other event that gives rise to a Federal or other governmental tax withholding obligation on the part of the Company or an Affiliate relating to an Award (including, without limitation, FICA tax), (a) the Company or Affiliate may deduct or withhold (or cause to be deducted or withheld) from any payment or distribution to the Participant, whether or not pursuant to the Plan, (b) the Committee will be entitled to require that the Participant remit cash to the Company or Affiliate (through payroll deduction or otherwise) or (c) the Company or Affiliate may enter into any other suitable arrangements to withhold, in each case in an amount sufficient in the opinion of the Company or Affiliate to satisfy such withholding obligation. If the event giving rise to the withholding obligation involves a transfer of shares of Stock, then, at the discretion of the Committee, the Participant may satisfy the withholding obligation by electing to have the Company withhold shares of Stock (which withholding, unless otherwise provided in the applicable Award Agreement, will be at a rate not in excess of the statutory minimum rate) or by tendering previously owned shares of Stock, in each case having a Fair Market Value equal to the amount of tax to be withheld (or by any other mechanism as may be required or appropriate to conform with local tax and other rules). The Company and any Affiliate is authorized to withhold from any Award granted, or any payment relating to an Award under this Plan, including from a distribution of Stock, amounts of withholding and other taxes due or potentially payable in connection with any transaction involving an Award, and to take such other action as the Committee may deem advisable to enable the Company and Participants to satisfy obligations for the payment of withholding taxes and other tax obligations relating to any Award. This authority includes, without limitation, the authority to withhold or receive Stock or other property and to make cash payments in respect thereof in satisfaction of a Participant’s tax obligations, either on a mandatory or elective basis.

Section 3.11Amendment, Modification and Termination. The Board may amend, alter, suspend, discontinue or terminate this Plan or the Committee’s authority to grant Awards under this Plan without the consent of the Company’s stockholders; provided, however, that if an amendment to the Plan would, in the reasonable opinion of the Board, (i) increase the number of shares of Stock available for issuance under the Plan, (ii) expand the types of Awards under the Plan, (iii) materially expand the class of individuals eligible to participate in the Plan, (iv) materially extend the term of the Plan, or (v) otherwise constitute a material change requirement stockholder approval under applicable laws, policies or regulations or the applicable listing or other requirements of the national securities exchange on which the shares of Stock are then listed, then such amendment will be subject to stockholder approval; and providedfurther, that the Board may condition any other amendment or modification on the approval of the Company’s stockholders for any reason. No Board action under this Section 3.11 may materially and adversely affect the rights of a Participant under any outstanding Award held by such Participant immediately prior to the effective time of such Board action.

Section 3.12Correction of Errors. Notwithstanding anything in this Plan or an Award Agreement to the contrary, the Committee may amend an Award, to take effective retroactively or otherwise, as deemed necessary or advisable for the purpose of correcting errors occurring in connection with the grant or documentation of an Award, including rescinding an Award erroneously granted, including, but not limited to, an Award erroneously granted to an individual who does not qualify as an Eligible Person on the date of grant of the Award. By accepting an Award

10

under the Plan, each Participant agrees to any amendment made pursuant to this Section 3.12 to any Award made under the Plan without further consideration or action.

Section 3.13Limitation on Rights Conferred under Plan. Neither this Plan nor any action taken hereunder may be construed as (i) giving any Eligible Person or Participant the right to continue as an Eligible Person or Participant or in the employ or service of the Company or an Affiliate, (ii) interfering in any way with the right of the Company or an Affiliate to terminate any Eligible Person’s or Participant’s employment or service relationship at any time, (iii) giving an Eligible Person or Participant any claim to be granted any Award under this Plan or to be treated uniformly with other Participants or employees or other service providers, or (iv) conferring on a Participant any of the rights of a stockholder of the Company unless and until the Participant is duly issued or transferred shares of Stock in accordance with the terms of an Award Agreement and the Plan.

Section 3.14Unfunded Status of Awards. This Plan is intended to constitute an “unfunded” plan and nothing in the Plan or any Award Agreement will give the Participant any rights that are greater than those of a general creditor of the Company. The Plan will not constitute an “employee benefit plan” for purposes of section 3(3) of the Employee Retirement Income Security Act of 1974, as amended.

Section 3.15Nonexclusivity of this Plan. Neither the adoption of this Plan by the Board nor its submission to the stockholders of the Company for approval may be construed as creating any limitations on the power of the Board or a committee thereof to adopt such other incentive arrangements as it may deem desirable. Nothing contained in this Plan may be construed to prevent the Company or an Affiliate from taking any corporate action which is deemed by the Company or such Affiliate to be appropriate or in its best interest, whether or not such action would have an adverse effect on this Plan or any Award made under this Plan. No employee, beneficiary or other person will have any claim against the Company or any Subsidiary as a result of any such action.

Section 3.16Fractional Shares. No fractional shares of Stock will be issued or delivered pursuant to this Plan or any Award. The Committee may determine whether cash, other Awards or other property will be issued or paid in lieu of such fractional shares or whether such fractional shares or any rights thereto will be forfeited or otherwise eliminated.

Section 3.17Severability. If any provision of this Plan is held to be illegal or invalid for any reason, the illegality or invalidity will not affect the remaining provisions hereof, but such provision will be fully severable and the Plan will be construed and enforced as if the illegal or invalid provision had never been included herein. If any of the terms or provisions of this Plan or any Award agreement conflict with the requirements of Rule 16b-3 (as those terms or provisions are applied to Eligible Persons who are subject to section 16(b) of the Exchange Act) or section 422 of the Code (with respect to Incentive Stock Options), then those conflicting terms or provisions will be deemed inoperative to the extent they so conflict with the requirements of Rule 16b-3 (unless the Board or the Committee, as appropriate, has expressly determined that the Plan or such Award should not comply with Rule 16b-3) or section 422 of the Code.

Section 3.18Governing Law. All questions arising with respect to the provisions of the Plan and Awards shall be determined by application of the laws of the State of Delaware, without giving effect to any conflict of law provisions thereof, except to the extent Delaware law is preempted by federal law. The obligation of the Company to sell and deliver Stock hereunder is subject to applicable federal and state laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or delivery of such Stock.

Section 3.19Conditions to Delivery of Stock. Nothing herein or in any Award granted hereunder or any Award agreement will require the Company to issue any shares with respect to any Award if that issuance would, in the opinion of counsel for the Company, constitute a violation of the Securities Act or any similar or superseding statute or statutes, any other applicable statute or regulation, or the rules of any applicable securities exchange or securities association, as then in effect.

Section 3.20Special Provisions Related Section 409A of the Code. It is intended that the payments and benefits provided under the Plan and any Award will either be exempt from the application of, or comply with, the requirements of section 409A of the Code. The Plan and all Award Agreements will be construed in a manner that

11

effects such intent. Nevertheless, the tax treatment of the benefits provided under the Plan or any Award is not warranted or guaranteed. Neither the Company, its Affiliates, nor their respective directors, officers, employees or advisers (other than in his or her capacity as a Participant) will be held liable for any taxes, interest, penalties or other amounts owed by any Participant or other taxpayer as a result of the Plan or any Award.

Section 3.21Plan Establishment and Term. This Plan was adopted by the Board and approved by the Company’s stockholders on June 6, 2014. Awards may be granted under this Plan no earlier than the Effective Date specified in Section 1.02(l), and no Awards may be granted under this Plan on or after June 6, 2024.

12

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) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) 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

(d) 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.

May 4, 2018

/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) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) 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

(d) 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.

May 4, 2018

/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 March 31, 2018, 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.
May 4, 2018	/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 March 31, 2018, 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.
May 4, 2018	/s/ Matthew R. DeNezza
	Matthew R. DeNezza
	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 04, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
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		302,092,885

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 21,801	$ 17,224
Accounts receivable	113,208	77,609
Assets held for sale		206
Other current assets	8,350	12,023
Total current assets	143,359	107,062
Oil and natural gas properties, successful efforts method:
Unproved properties	537,958	459,549
Proved oil and gas properties, net	694,599	647,881
Other property and equipment, net	6,785	6,942
Total property and equipment, net	1,239,342	1,114,372
OTHER NONCURRENT ASSETS
Other assets	5,617	2,093
TOTAL ASSETS	1,388,318	1,223,527
CURRENT LIABILITIES
Accounts payable	96,048	76,174
Accrued capital expenditures	12,689	10,658
Accrued liabilities	39,423	41,662
Accrued interest payable	10,433	21,100
Total current liabilities	158,593	149,594
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs	495,707	495,021
Credit facility	65,000
Asset retirement obligations	6,269	6,029
Other liabilities	2,100	529
Total liabilities	727,669	651,173
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, 301,771,111 and 262,740,355 shares issued and outstanding, respectively	3,033	2,637
Additional paid in capital	2,059,418	1,967,958
Treasury stock, shares at cost; 1,499,566 and 992,315 shares, respectively	(3,031)	(2,096)
Accumulated deficit	(1,398,771)	(1,396,145)
Total stockholders' equity	660,649	572,354
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 1,388,318	$ 1,223,527

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
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	301,771,111	262,740,355
Common stock, shares outstanding	301,771,111	262,740,355
Treasury stock, shares	1,499,566	992,315

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Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
REVENUES
Natural gas, oil and natural gas liquids sales	$ 110,184	$ 99,432
Brokered natural gas and marketing revenue	8	2,431
Total revenues	110,192	101,863
OPERATING EXPENSES
Lease operating	9,390	2,343
Transportation, gathering and compression	27,689	32,877
Production and ad valorem taxes	2,445	1,931
Brokered natural gas and marketing expense	48	2,460
Depreciation, depletion and amortization	31,156	26,189
Exploration	15,278	11,581
General and administrative	9,757	10,132
Accretion of asset retirement obligations	155	124
(Gain) loss on sale of assets	(267)	(5)
Total operating expenses	95,651	87,632
OPERATING INCOME (LOSS)	14,541	14,231
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments	(4,215)	25,097
Interest expense, net	(12,952)	(12,462)
Other income (expense)		(19)
Total other income (expense), net	(17,167)	12,616
INCOME (LOSS) BEFORE INCOME TAXES	(2,626)	26,847
NET INCOME (LOSS)	$ (2,626)	$ 26,847
NET INCOME (LOSS) PER COMMON SHARE
Basic	$ (0.01)	$ 0.10
Diluted	$ (0.01)	$ 0.10
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	293,450	261,105
Diluted	293,450	264,215

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - 3 months ended Mar. 31, 2018 - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Accumulated Deficit [Member]
Beginning Balances at Dec. 31, 2017	$ 572,354	$ 2,637	$ 1,967,958	$ (2,096)	$ (1,396,145)
Beginning Balance, shares at Dec. 31, 2017		262,740,355
Stock-based compensation	1,981		1,981
Equity issuance costs	(145)		(145)
Shares of common stock issued in asset acquisition, net of equity issuance costs	90,020	$ 378	89,642
Shares of common stock issued in asset acquisition, net of equity issuance costs, shares		37,823,596
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	(935)	$ 18	(18)	(935)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares		1,207,160
Net income (loss)	(2,626)				(2,626)
Ending Balances at Mar. 31, 2018	$ 660,649	$ 3,033	$ 2,059,418	$ (3,031)	$ (1,398,771)
Ending Balance, shares at Mar. 31, 2018		301,771,111

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Statement Of Stockholders Equity [Abstract]
Common stock, par value	$ 0.01	$ 0.01

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (2,626)	$ 26,847
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion and amortization	31,156	26,189
Exploration expense	6,790	4,988
Stock-based compensation	1,981	2,081
Accretion of asset retirement obligations	155	124
(Gain) loss on derivative instruments	4,215	(25,097)
Net cash receipts (payments) on settled derivatives	141	(3,989)
(Gain) loss on sale of assets	(267)	(5)
Amortization of deferred financing costs	554	502
Amortization of debt discount	332	330
Changes in operating assets and liabilities:
Accounts receivable	(35,499)	10,478
Other assets	(459)	943
Accounts payable and accrued liabilities	(3,179)	(14,992)
Net cash provided by operating activities	3,294	28,399
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties	(66,441)	(66,005)
Capital expenditures for other property and equipment	(155)	(178)
Proceeds from sale of assets	4,099	24
Net cash used in investing activities	(62,497)	(66,159)
CASH FLOWS FROM FINANCING ACTIVITIES
Debt issuance costs	(48)	(1,231)
Repayments of long-term debt	(92)	(74)
Proceeds from credit facility	65,000
Equity issuance costs	(145)
Employee tax withholding for settlement of equity compensation awards	(935)	(1,706)
Net cash provided by (used in) financing activities	63,780	(3,011)
Net increase (decrease) in cash and cash equivalents	4,577	(40,771)
Cash and cash equivalents at beginning of period	17,224	201,229
Cash and cash equivalents at end of period	21,801	160,458
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	23,638	23,066
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	85	124
Additions of other property through debt financing	174
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures	8,864	$ 13,126
Asset acquisition through stock issuance	$ 90,020

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Organization and Nature of Operations

3 Months Ended

Mar. 31, 2018

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.

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Basis of Presentation

3 Months Ended

Mar. 31, 2018

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, 2017, 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 2, 2018.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2018 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.

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2018

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 March 31, 2018 or December 31, 2017.

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 $51.3 million and $52.9 million of accrued revenues, net of certain expenses, at March 31, 2018 and December 31, 2017, 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 the 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 the 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):

	March 31, 2018			December 31, 2017
Oil and natural gas properties:
Unproved	$	537,958		$	459,549
Proved		1,973,468			1,896,081
Gross oil and natural gas properties		2,511,426			2,355,630
Less accumulated depreciation, depletion and amortization		(1,278,869	)		(1,248,200	)
Oil and natural gas properties, net		1,232,557			1,107,430
Other property and equipment		13,837			13,508
Less accumulated depreciation		(7,052	)		(6,566	)
Other property and equipment, net		6,785			6,942
Property and equipment, net	$	1,239,342		$	1,114,372

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 $0.5 million and $0.4 million for the three months ended March 31, 2018 and 2017, 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

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas.  The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company delivers the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials.  The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to further process and transport NGLs are recorded as transportation, gathering and compression expense.

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks near central stabilization facilities and collect a contractually agreed upon index price, net of pricing differentials. The Company transfers control of the product from the central stabilization facilities to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs.  The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

  The following table illustrates the revenue disaggregated by type for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018		2017
Revenues (in thousands)
Natural gas sales	$	58,483	$	61,420
NGL sales		19,743		17,063
Oil sales		31,958		20,949
Brokered natural gas and marketing revenue		8		2,431
Total revenues	$	110,192	$	101,863

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations is part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.  Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.  Accounts receivable attributable to the Company’s revenue contracts with customers was $51.3 million and $52.9 million at March 31, 2018 and December 31, 2017, respectively.

(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 March 31, 2018 and December 31, 2017 (in thousands):

	March 31, 2018		December 31, 2017
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	51,298	$	52,908
Joint interest owners		60,263		23,154
Derivatives		1,628		1,528
Other		19		19
Total	$	113,208	$	77,609

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 ($8.9) million and ($5.1) million at March 31, 2018 and December 31, 2017, 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 March 31, 2018 and December 31, 2017, 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 $30.7 million and $25.7 million for the three months ended March 31, 2018 and 2017, 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 March 31, 2018 and 2017. 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.  There were no impairments of proved properties for the three months ended March 31, 2018 or the three months ended March 31, 2017.

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is 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 $6.7 million and $4.1 million for the three months ended March 31, 2018 and 2017, respectively. The increase in impairment charges during the three months ended March 31, 2018 is the result of an increase in expected lease expirations due to the reduction in the Company’s planned future drilling activity due to the current commodity price environment. 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 three months ended March 31, 2018 and 2017.

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 three months ended March 31, 2018 (in thousands):

	Three Months Ended March 31, 2018
Asset retirement obligations, beginning of period	$	6,029
Additional liabilities incurred		85
Accretion		155
Asset retirement obligations, end of period	$	6,269

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.  The Company adopted this standard effective January 1, 2018 using the modified retrospective method.  The Company did not recognize a significant impact on its financial position or results of operations.  Upon adoption of this new standard, the Company did not record a cumulative effect adjustment nor did the Company alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify the impact of future revenue contracts entered into by the Company.  Additional disclosures have been included to provide further detail regarding the Company’s revenue recognition policies.  

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 plans to adopt this standard effective January 1, 2019 using the modified retrospective transition method and is evaluating the standard’s applicability to its various contractual arrangements.  Although the Company believes that the adoption of the standard will result in increases to its assets and liabilities on its consolidated balance sheet as well as changes to the presentation of certain operating expenses on its consolidated statement of operations, the Company has not yet determined the extent of the adjustments that will be required upon implementation of the standard.  The Company continues to monitor relevant industry guidance regarding the implementation of the standard.

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 adopted this standard effective January 1, 2018 and did not recognize a significant impact on its financial position, results of operations, or statement of cash flows.

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 adopted this standard effective January 1, 2018 and considered the new guidance in its assessment of the accounting treatment for the Flat Castle Acquisition. (See Note 4—Acquisition).

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Acquisition

3 Months Ended

Mar. 31, 2018

Business Combinations [Abstract]

Acquisition

Note 4—Acquisition

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, one producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 37.8 million shares of the Company’s common stock (the “Flat Castle Acquisition”).  The transaction was accounted for as an asset acquisition.  Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired.  In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.  

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Sale of Oil and Natural Gas Property Interests

3 Months Ended

Mar. 31, 2018

Discontinued Operations And Disposal Groups [Abstract]

Sale of Oil and Natural Gas Property Interests

Note 5—Sale of Oil and Natural Gas Property Interests

During the three months ended March 31, 2018, the Company received approximately $3.8 million from a completed asset sale to a third party totaling approximately 400 acres.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the three months ended March 31, 2018, the Company received approximately $0.3 million from an additional completed asset sale to a third party totaling approximately 50 acres.  As a result of this sale, the Company recognized a gain of approximately $0.3 million.

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Derivative Instruments

3 Months Ended

Mar. 31, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Instruments

Note 6—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 March 31, 2018, 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 March 31, 2018, for future production periods:

Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		30,000	April 2018 – March 2019	$	2.90
		20,000	April 2018 – December 2018	$	2.80
		20,000	July 2018 – September 2018	$	2.81
		40,000	October 2018 – December 2019	$	2.80
		50,000	January 2019 – December 2019	$	2.87
Natural Gas Three-way Collars:
Floor purchase price (put)		30,000	April 2018 – March 2019	$	3.00
Ceiling sold price (call)		30,000	April 2018 – March 2019	$	3.40
Floor sold price (put)		30,000	April 2018 – March 2019	$	2.50
Floor purchase price (put)		40,000	April 2018 – December 2018	$	3.11
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.80
Ceiling sold price (call)		100,000	April 2018 – December 2018	$	3.36
Floor sold price (put)		100,000	April 2018 – December 2018	$	2.50
Floor purchase price (put)		20,000	October 2018 – December 2019	$	2.75
Ceiling sold price (call)		20,000	October 2018 – December 2019	$	3.10
Floor sold price (put)		20,000	October 2018 – December 2019	$	2.30
Floor purchase price (put)		57,500	January 2019 – December 2019	$	2.72
Ceiling sold price (call)		57,500	January 2019 – December 2019	$	3.02
Floor sold price (put)		57,500	January 2019 – December 2019	$	2.30
Natural Gas Call/Put Options:
Call sold		40,000	April 2018 – December 2018	$	3.75
Call sold		30,000	January 2019 – March 2019	$	3.50
Call sold		30,000	April 2019 – December 2019	$	3.00
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
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 Swaps:
		1,000	July 2018 – March 2019	$	61.00
Oil Three-way Collars:
Floor purchase price (put)		4,000	April 2018 – December 2018	$	45.00
Ceiling sold price (call)		4,000	April 2018 – December 2018	$	53.47
Floor sold price (put)		4,000	April 2018 – December 2018	$	35.00
Floor purchase price (put)		2,000	January 2019 – December 2019	$	50.00
Ceiling sold price (call)		2,000	January 2019 – December 2019	$	60.56
Floor sold price (put)		2,000	January 2019 – December 2019	$	40.00

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 March 31, 2018	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	11,768		$	(6,258	)	$	5,510		Other current assets
Commodity derivatives - noncurrent		3,931			(14	)		3,917		Other assets
Total assets	$	15,699		$	(6,272	)	$	9,427
Liabilities
Commodity derivatives - current	$	(23,012	)	$	6,258		$	(16,754	)	Accrued liabilities
Commodity derivatives - noncurrent		(1,603	)		14			(1,589	)	Other liabilities
Total liabilities	$	(24,615	)	$	6,272		$	(18,343	)

As of December 31, 2017	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	15,971		$	(6,380	)	$	9,591		Other current assets
Commodity derivatives - noncurrent		469			(176	)		293		Other assets
Total assets	$	16,440		$	(6,556	)	$	9,884
Liabilities
Commodity derivatives - current	$	(21,256	)	$	6,380		$	(14,876	)	Accrued liabilities
Commodity derivatives - noncurrent		(252	)		176			(76	)	Other liabilities
Total liabilities	$	(21,508	)	$	6,556		$	(14,952	)

(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 March 31,
		2018			2017
Commodity derivatives	Gain (loss) on derivative instruments	$	(4,215	)	$	25,097

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Fair Value Measurements

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 7—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 March 31, 2018: (in thousands)
Commodity derivative instruments	$	—	$	(8,916	)	$	—	$	(8,916	)
Total	$	—	$	(8,916	)	$	—	$	(8,916	)
As of December 31, 2017: (in thousands)
Commodity derivative instruments	$	—	$	(5,068	)	$	—	$	(5,068	)
Total	$	—	$	(5,068	)	$	—	$	(5,068	)

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 8—Debt).

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Debt

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Debt

Note 8—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 months ended March 31, 2018 and 2017, the Company amortized $0.9 million and $0.8 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.

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 March 31, 2018.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at March 31, 2018 was $482.0 million.

Revolving Credit Facility

During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”), entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature 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).

In January 2015, the credit agreement governing the revolving credit facility was amended and restated (as amended and restated, the “Credit Agreement”), primarily to add Eclipse Resources Corporation as a party thereto and thereby subject the Company to the representations, warranties, covenants and events of default provisions therein.  Relative to Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Eclipse Resources Corporation rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I.  Other terms of the Credit Agreement remained generally consistent with Eclipse I’s previous credit agreement.

On February 24, 2016, the Company amended the Credit Amendment 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 also 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 such 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 to the Credit Agreement 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, this 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 to the Credit Agreement that increased the borrowing base from $175 million to $225 million.  

At March 31, 2018, the borrowing base was $225 million and the Company had $65 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $33.6 million and the outstanding borrowings of $65 million, the Company had available borrowing capacity under the revolving credit facility of $126.4 million at March 31, 2018.  Subsequent to March 31, 2018, the Company repaid $20 million on the revolving credit facility, which reduced the outstanding borrowings to $45 million and resulted in available borrowing capacity of $146.4 million.  In April 2018, the Company completed its most recent borrowing base redetermination, which resulted in no change to the borrowing base of $225 million.  The Company’s next scheduled borrowing base redetermination is expected to be completed by October 2018.

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 March 31, 2018. 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

3 Months Ended

Mar. 31, 2018

Compensation And Retirement Disclosure [Abstract]

Benefit Plans

Note 9—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 $0.2 million for the three months ended March 31, 2018 and 2017, respectively.

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Stock-Based Compensation

3 Months Ended

Mar. 31, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock-Based Compensation

Note 10—Stock-Based Compensation

The Company is authorized to grant up to 25,000,000 shares of common stock under its Amended and Restated 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 7,199,257 shares were available for future grants under the Plan as of March 31, 2018.

Our stock-based compensation expense was as follows for the three months ended March 31, 2018 and 2017 (in thousands):

	Three Months Ended March 31,
	2018		2017
Restricted stock units	$	1,164	$	1,247
Performance units		728		734
Restricted stock issued to directors		89		100
Total expense	$	1,981	$	2,081

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 March 31, 2018, there was $7.0 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 three months ended March 31, 2018 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2017		4,057,354		$	2.48	$	9,738
Granted		1,498,524			1.70
Vested		(1,378,403	)		3.17
Forfeited		(6,512	)		2.15
Total awarded and unvested, March 31, 2018		4,170,963		$	1.97	$	6,006

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return, 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 March 31, 2018, there was $6.4 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 three months ended March 31, 2018 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2017		3,966,377		$	1.82	$	11,257
Granted		1,498,524			1.92
Vested		—			—
Forfeited		(9,768	)		1.94
Total awarded and unvested, March 31, 2018		5,455,133		$	1.84	$	2,856

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 stock price.  Prior to 2018, the volatility estimate was tied to the Company’s public peer group.  The following table presents the assumptions used to determine the fair value for performance stock units granted during the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018			2017
Volatility		89.70	%		50.41	%
Risk-free interest rate		2.37	%		1.34	%

Restricted Stock Issued to Directors

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 months ended March 31, 2017, the Company recognized expense of approximately $0.1 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 months ended March 31, 2018, the Company recognized expense of approximately $0.1 million related to these awards.  As of March 31, 2018, there was approximately less than $0.1 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s directors.

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Earnings (Loss) Per Share

3 Months Ended

Mar. 31, 2018

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 months ended March 31, 2018 and 2017, respectively:

	Three Months Ended March 31,
(in thousands, except per share data)	2018								2017
	Income (Loss)			Shares		Per Share			Income (Loss)		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(2,626	)		293,450	$	(0.01	)	$	26,847		261,105	$	0.10
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		3,110
Diluted:
Net income (loss), shares, diluted	$	(2,626	)		293,450	$	(0.01	)	$	26,847		264,215	$	0.10

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Related Party Transactions

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

Note 12—Related Party Transactions

During the three months ended March 31, 2018, the Company incurred approximately $0.2 million 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 related to such services during the three months ended March 31, 2017.  The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms.

Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap.  EnCap has representatives on the Board, and affiliates of EnCap collectively beneficially own a majority of the outstanding shares of our common stock. (See Note 4—Acquisition).

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2018

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 $0.2 million for the three months ended March 31, 2018 and 2017, respectively.

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Income Tax

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Income Tax

Note 14—Income Tax

For the year ending December 31, 2018, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company expects to incur both a book and tax loss in fiscal year 2018, and thus, no current federal income taxes are anticipated to be paid.  The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to the Company’s year-to-date loss.  On December 22, 2017, the Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, resulted in the reduction in the U.S. statutory rate from 35% to 21%.For the three months ended March 31, 2018, the Company’s overall effective tax rate on operations was different than the federal statutory rate of 21% due primarily to valuation allowances and other permanent differences.

The Company’s interest expense deduction has the potential to be limited as a result of the enactment of the Tax Cuts and Jobs Act; however, the impact is anticipated to be minimal as a result of its full valuation allowance.  Future interpretations relating to the passage of the Tax Cuts and Jobs Act which vary from our current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on our future taxable position.  The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

In forecasting the 2018 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2018. Management reached this conclusion considering several factors such as: (i) the Company’s short tax history, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s balance sheet. At this time, the estimated valuation allowance to be recorded in 2018 is $5.3 million.

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Subsidiary Guarantors

3 Months Ended

Mar. 31, 2018

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 8—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

3 Months Ended

Mar. 31, 2018

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 8—Debt).

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2018

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 March 31, 2018 or December 31, 2017.

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 $51.3 million and $52.9 million of accrued revenues, net of certain expenses, at March 31, 2018 and December 31, 2017, 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 the 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 the 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):

	March 31, 2018			December 31, 2017
Oil and natural gas properties:
Unproved	$	537,958		$	459,549
Proved		1,973,468			1,896,081
Gross oil and natural gas properties		2,511,426			2,355,630
Less accumulated depreciation, depletion and amortization		(1,278,869	)		(1,248,200	)
Oil and natural gas properties, net		1,232,557			1,107,430
Other property and equipment		13,837			13,508
Less accumulated depreciation		(7,052	)		(6,566	)
Other property and equipment, net		6,785			6,942
Property and equipment, net	$	1,239,342		$	1,114,372

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 $0.5 million and $0.4 million for the three months ended March 31, 2018 and 2017, 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

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas.  The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company delivers the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials.  The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to further process and transport NGLs are recorded as transportation, gathering and compression expense.

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks near central stabilization facilities and collect a contractually agreed upon index price, net of pricing differentials. The Company transfers control of the product from the central stabilization facilities to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs.  The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

  The following table illustrates the revenue disaggregated by type for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018		2017
Revenues (in thousands)
Natural gas sales	$	58,483	$	61,420
NGL sales		19,743		17,063
Oil sales		31,958		20,949
Brokered natural gas and marketing revenue		8		2,431
Total revenues	$	110,192	$	101,863

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations is part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.  Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.  Accounts receivable attributable to the Company’s revenue contracts with customers was $51.3 million and $52.9 million at March 31, 2018 and December 31, 2017, respectively.

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 March 31, 2018 and December 31, 2017 (in thousands):

	March 31, 2018		December 31, 2017
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	51,298	$	52,908
Joint interest owners		60,263		23,154
Derivatives		1,628		1,528
Other		19		19
Total	$	113,208	$	77,609

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 ($8.9) million and ($5.1) million at March 31, 2018 and December 31, 2017, 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 March 31, 2018 and December 31, 2017, 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 $30.7 million and $25.7 million for the three months ended March 31, 2018 and 2017, 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 March 31, 2018 and 2017. 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.  There were no impairments of proved properties for the three months ended March 31, 2018 or the three months ended March 31, 2017.

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is 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 $6.7 million and $4.1 million for the three months ended March 31, 2018 and 2017, respectively. The increase in impairment charges during the three months ended March 31, 2018 is the result of an increase in expected lease expirations due to the reduction in the Company’s planned future drilling activity due to the current commodity price environment. 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 three months ended March 31, 2018 and 2017.

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 three months ended March 31, 2018 (in thousands):

	Three Months Ended March 31, 2018
Asset retirement obligations, beginning of period	$	6,029
Additional liabilities incurred		85
Accretion		155
Asset retirement obligations, end of period	$	6,269

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.  The Company adopted this standard effective January 1, 2018 using the modified retrospective method.  The Company did not recognize a significant impact on its financial position or results of operations.  Upon adoption of this new standard, the Company did not record a cumulative effect adjustment nor did the Company alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify the impact of future revenue contracts entered into by the Company.  Additional disclosures have been included to provide further detail regarding the Company’s revenue recognition policies.  

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 plans to adopt this standard effective January 1, 2019 using the modified retrospective transition method and is evaluating the standard’s applicability to its various contractual arrangements.  Although the Company believes that the adoption of the standard will result in increases to its assets and liabilities on its consolidated balance sheet as well as changes to the presentation of certain operating expenses on its consolidated statement of operations, the Company has not yet determined the extent of the adjustments that will be required upon implementation of the standard.  The Company continues to monitor relevant industry guidance regarding the implementation of the standard.

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 adopted this standard effective January 1, 2018 and did not recognize a significant impact on its financial position, results of operations, or statement of cash flows.

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 adopted this standard effective January 1, 2018 and considered the new guidance in its assessment of the accounting treatment for the Flat Castle Acquisition. (See Note 4—Acquisition).

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2018

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):

	March 31, 2018			December 31, 2017
Oil and natural gas properties:
Unproved	$	537,958		$	459,549
Proved		1,973,468			1,896,081
Gross oil and natural gas properties		2,511,426			2,355,630
Less accumulated depreciation, depletion and amortization		(1,278,869	)		(1,248,200	)
Oil and natural gas properties, net		1,232,557			1,107,430
Other property and equipment		13,837			13,508
Less accumulated depreciation		(7,052	)		(6,566	)
Other property and equipment, net		6,785			6,942
Property and equipment, net	$	1,239,342		$	1,114,372

Summary of Revenue Disaggregated by Type

The following table illustrates the revenue disaggregated by type for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018		2017
Revenues (in thousands)
Natural gas sales	$	58,483	$	61,420
NGL sales		19,743		17,063
Oil sales		31,958		20,949
Brokered natural gas and marketing revenue		8		2,431
Total revenues	$	110,192	$	101,863

Changes in Company's Asset Retirement Obligation Liability

The following table sets forth the changes in the Company’s ARO liability for the three months ended March 31, 2018 (in thousands):

	Three Months Ended March 31, 2018
Asset retirement obligations, beginning of period	$	6,029
Additional liabilities incurred		85
Accretion		155
Asset retirement obligations, end of period	$	6,269

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 March 31, 2018 and December 31, 2017 (in thousands):

	March 31, 2018		December 31, 2017
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	51,298	$	52,908
Joint interest owners		60,263		23,154
Derivatives		1,628		1,528
Other		19		19
Total	$	113,208	$	77,609

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2018

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 March 31, 2018, for future production periods:

Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		30,000	April 2018 – March 2019	$	2.90
		20,000	April 2018 – December 2018	$	2.80
		20,000	July 2018 – September 2018	$	2.81
		40,000	October 2018 – December 2019	$	2.80
		50,000	January 2019 – December 2019	$	2.87
Natural Gas Three-way Collars:
Floor purchase price (put)		30,000	April 2018 – March 2019	$	3.00
Ceiling sold price (call)		30,000	April 2018 – March 2019	$	3.40
Floor sold price (put)		30,000	April 2018 – March 2019	$	2.50
Floor purchase price (put)		40,000	April 2018 – December 2018	$	3.11
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.80
Ceiling sold price (call)		100,000	April 2018 – December 2018	$	3.36
Floor sold price (put)		100,000	April 2018 – December 2018	$	2.50
Floor purchase price (put)		20,000	October 2018 – December 2019	$	2.75
Ceiling sold price (call)		20,000	October 2018 – December 2019	$	3.10
Floor sold price (put)		20,000	October 2018 – December 2019	$	2.30
Floor purchase price (put)		57,500	January 2019 – December 2019	$	2.72
Ceiling sold price (call)		57,500	January 2019 – December 2019	$	3.02
Floor sold price (put)		57,500	January 2019 – December 2019	$	2.30
Natural Gas Call/Put Options:
Call sold		40,000	April 2018 – December 2018	$	3.75
Call sold		30,000	January 2019 – March 2019	$	3.50
Call sold		30,000	April 2019 – December 2019	$	3.00
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
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 Swaps:
		1,000	July 2018 – March 2019	$	61.00
Oil Three-way Collars:
Floor purchase price (put)		4,000	April 2018 – December 2018	$	45.00
Ceiling sold price (call)		4,000	April 2018 – December 2018	$	53.47
Floor sold price (put)		4,000	April 2018 – December 2018	$	35.00
Floor purchase price (put)		2,000	January 2019 – December 2019	$	50.00
Ceiling sold price (call)		2,000	January 2019 – December 2019	$	60.56
Floor sold price (put)		2,000	January 2019 – December 2019	$	40.00

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 March 31, 2018	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	11,768		$	(6,258	)	$	5,510		Other current assets
Commodity derivatives - noncurrent		3,931			(14	)		3,917		Other assets
Total assets	$	15,699		$	(6,272	)	$	9,427
Liabilities
Commodity derivatives - current	$	(23,012	)	$	6,258		$	(16,754	)	Accrued liabilities
Commodity derivatives - noncurrent		(1,603	)		14			(1,589	)	Other liabilities
Total liabilities	$	(24,615	)	$	6,272		$	(18,343	)

As of December 31, 2017	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	15,971		$	(6,380	)	$	9,591		Other current assets
Commodity derivatives - noncurrent		469			(176	)		293		Other assets
Total assets	$	16,440		$	(6,556	)	$	9,884
Liabilities
Commodity derivatives - current	$	(21,256	)	$	6,380		$	(14,876	)	Accrued liabilities
Commodity derivatives - noncurrent		(252	)		176			(76	)	Other liabilities
Total liabilities	$	(21,508	)	$	6,556		$	(14,952	)

(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 March 31,
		2018			2017
Commodity derivatives	Gain (loss) on derivative instruments	$	(4,215	)	$	25,097

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2018

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 March 31, 2018: (in thousands)
Commodity derivative instruments	$	—	$	(8,916	)	$	—	$	(8,916	)
Total	$	—	$	(8,916	)	$	—	$	(8,916	)
As of December 31, 2017: (in thousands)
Commodity derivative instruments	$	—	$	(5,068	)	$	—	$	(5,068	)
Total	$	—	$	(5,068	)	$	—	$	(5,068	)

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Stock-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2018

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 months ended March 31, 2018 and 2017 (in thousands):

	Three Months Ended March 31,
	2018		2017
Restricted stock units	$	1,164	$	1,247
Performance units		728		734
Restricted stock issued to directors		89		100
Total expense	$	1,981	$	2,081

Summary of Restricted Stock Unit Awards Activity

A summary of restricted stock unit awards activity during the three months ended March 31, 2018 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2017		4,057,354		$	2.48	$	9,738
Granted		1,498,524			1.70
Vested		(1,378,403	)		3.17
Forfeited		(6,512	)		2.15
Total awarded and unvested, March 31, 2018		4,170,963		$	1.97	$	6,006

Summary of Performance Stock Unit Awards Activity

A summary of performance stock unit awards activity during the three months ended March 31, 2018 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2017		3,966,377		$	1.82	$	11,257
Granted		1,498,524			1.92
Vested		—			—
Forfeited		(9,768	)		1.94
Total awarded and unvested, March 31, 2018		5,455,133		$	1.84	$	2,856

Assumptions Used to Determine Fair Value of Performance Stock Units Granted

The following table presents the assumptions used to determine the fair value for performance stock units granted during the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
	2018			2017
Volatility		89.70	%		50.41	%
Risk-free interest rate		2.37	%		1.34	%

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Earnings (Loss) Per Share (Tables)

3 Months Ended

Mar. 31, 2018

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 months ended March 31, 2018 and 2017, respectively:

	Three Months Ended March 31,
(in thousands, except per share data)	2018								2017
	Income (Loss)			Shares		Per Share			Income (Loss)		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(2,626	)		293,450	$	(0.01	)	$	26,847		261,105	$	0.10
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		3,110
Diluted:
Net income (loss), shares, diluted	$	(2,626	)		293,450	$	(0.01	)	$	26,847		264,215	$	0.10

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Summary of Significant Accounting Policies - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018 USD ($) Segment	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 113,208,000		$ 77,609,000
Capitalized interest expense	$ 500,000	$ 400,000
Revenue recognition payment receivable period	1 month
Revenue, practical expedient, nondisclosure of transaction price allocation to remaining performance obligation description	true
Accounts receivable attributable to revenue contracts with customers	$ 51,300,000		52,900,000
Depreciation, depletion and amortization	$ 31,156,000	$ 26,189,000
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	$ 30,700,000	$ 25,700,000
Other property and equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciation	$ 500,000	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]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties	$ 0	0
Unproved Oil And Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties	6,700,000	$ 4,100,000
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Summary Of Significant Accounting Policies [Line Items]
Fair value of commodity derivative contracts	(8,900,000)		(5,100,000)
Unbilled Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 51,300,000		$ 52,900,000

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Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Oil and natural gas properties:
Unproved properties	$ 537,958	$ 459,549
Proved properties	1,973,468	1,896,081
Gross oil and natural gas properties	2,511,426	2,355,630
Less accumulated depreciation, depletion and amortization	(1,278,869)	(1,248,200)
Total oil and natural gas properties, net	1,232,557	1,107,430
Other property and equipment	13,837	13,508
Less accumulated depreciation	(7,052)	(6,566)
Other property and equipment, net	6,785	6,942
Total property and equipment, net	$ 1,239,342	$ 1,114,372

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Summary of Significant Accounting Policies - Summary of Revenue Disaggregated by Type (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Oil And Gas Revenue [Line Items]
Total revenues	$ 110,192	$ 101,863
Natural Gas Sales [Member]
Oil And Gas Revenue [Line Items]
Total revenues	58,483	61,420
NGL Sales [Member]
Oil And Gas Revenue [Line Items]
Total revenues	19,743	17,063
Oil Sales [Member]
Oil And Gas Revenue [Line Items]
Total revenues	31,958	20,949
Brokered Natural Gas and Marketing Revenue [Member]
Oil And Gas Revenue [Line Items]
Total revenues	$ 8	$ 2,431

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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	Mar. 31, 2018	Dec. 31, 2017
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	$ 113,208	$ 77,609
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	51,298	52,908
Product Concentration Risk [Member] | Joint Interest Owners [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	60,263	23,154
Product Concentration Risk [Member] | Derivatives [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	1,628	1,528
Product Concentration Risk [Member] | Other [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	$ 19	$ 19

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Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Asset Retirement Obligation [Abstract]
Asset retirement obligations, beginning of period	$ 6,029
Additional liabilities incurred	85
Accretion	155	$ 124
Asset retirement obligations, end of period	$ 6,269

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Acquisition - Additional Information (Detail) - Flat Castle Acquisition [Member] shares in Millions, $ in Millions	Jan. 18, 2018 USD ($) a Well shares
Business Acquisition [Line Items]
Area of land purchased | a	44,500
Purchase price	$ 90
Purchase price paid through shares of common stock | shares	37.8
Transaction costs capitalized related to acquisition	$ 1
Proved Oil And Gas Properties [Member]
Business Acquisition [Line Items]
Number of producing wells acquired | Well	1
Purchase price	$ 4
Unproved Oil and Natural Gas Properties [Member]
Business Acquisition [Line Items]
Purchase price	$ 86

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Sale of Oil and Natural Gas Property Interests - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018 USD ($) a	Mar. 31, 2017 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale of assets	$ 267,000	$ 5,000
Asset Sale 400 Acres [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	$ 3,800,000
Area of land | a	400
Asset Sale 50 Acres [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale of assets	$ 300,000
Proceeds from sale of asset	$ 300,000
Area of land | a	50

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Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail)	3 Months Ended
	Mar. 31, 2018 MMBTU $ / MMBTU bbl
Natural Gas Swaps Production Period April 2018 – March 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price ($/MMBtu)	2.90
Natural Gas Swaps Production Period April 2018 – December 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price ($/MMBtu)	2.80
Natural Gas Swaps Production Period July 2018 – September 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price ($/MMBtu)	2.81
Natural Gas Swaps Production Period October 2018 – December 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price ($/MMBtu)	2.80
Natural Gas Swaps Production Period January 2019 – December 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price ($/MMBtu)	2.87
Basis Swaps Production Period April 2019 – October 2019 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	12,500
Weighted Average Price ($/MMBtu)	(0.52)
Basis Swaps Production Period April 2020 – October 2020 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	12,500
Weighted Average Price ($/MMBtu)	(0.52)
Natural Gas Three-way Collars Production Period April 2018 – March 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price, Floor ($/MMBtu)	3.00
Natural Gas Three-way Collars Production Period April 2018 – March 2019 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price, Floor ($/MMBtu)	2.50
Natural Gas Three-way Collars Production Period April 2018 – March 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price, Ceiling ($/MMBtu)	3.40
Natural Gas Three-way Collars Production Period April 2018 – December 2018 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price, Floor ($/MMBtu)	3.11
Natural Gas Three-way Collars Production Period April 2018 – December 2018 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	60,000
Weighted Average Price, Floor ($/MMBtu)	2.80
Natural Gas Three-way Collars Production Period April 2018 – December 2018 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	100,000
Weighted Average Price, Floor ($/MMBtu)	2.50
Natural Gas Three-way Collars Production Period April 2018 – December 2018 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	100,000
Weighted Average Price, Ceiling ($/MMBtu)	3.36
Natural Gas Three-way Collars Production Period October 2018 – December 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price, Floor ($/MMBtu)	2.75
Natural Gas Three-way Collars Production Period October 2018 – December 2019 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price, Floor ($/MMBtu)	2.30
Natural Gas Three-way Collars Production Period October 2018 – December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price, Ceiling ($/MMBtu)	3.10
Natural Gas Three-way Collars Production Period January 2019 – December 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	57,500
Weighted Average Price, Floor ($/MMBtu)	2.72
Natural Gas Three-way Collars Production Period January 2019 – December 2019 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	57,500
Weighted Average Price, Floor ($/MMBtu)	2.30
Natural Gas Three-way Collars Production Period January 2019 – December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	57,500
Weighted Average Price, Ceiling ($/MMBtu)	3.02
Natural Gas Call/Put Options Production Period April 2018 – December 2018 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price ($/MMBtu)	3.75
Natural Gas Call/Put Options Production Period January 2019 – March 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price ($/MMBtu)	3.50
Natural Gas Call/Put Options Production Period April 2019 – December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price ($/MMBtu)	3.00
Natural Gas Call/Put Options Production Period January 2019 – December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	10,000
Weighted Average Price ($/MMBtu)	4.75
Oil Swaps Production Period July 2018 – March 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price ($/MMBtu)	61.00
Volume (Bbls/d) | bbl	1,000
Oil Three-way Collars Production Period April 2018 – December 2018 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor ($/MMBtu)	45.00
Volume (Bbls/d) | bbl	4,000
Oil Three-way Collars Production Period April 2018 – December 2018 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor ($/MMBtu)	35.00
Volume (Bbls/d) | bbl	4,000
Oil Three-way Collars Production Period April 2018 – December 2018 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling ($/MMBtu)	53.47
Volume (Bbls/d) | bbl	4,000
Oil Three-way Collars Production Period January 2019 – December 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor ($/MMBtu)	50.00
Volume (Bbls/d) | bbl	2,000
Oil Three-way Collars Production Period January 2019 – December 2019 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor ($/MMBtu)	40.00
Volume (Bbls/d) | bbl	2,000
Oil Three-way Collars Production Period January 2019 – December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling ($/MMBtu)	60.56
Volume (Bbls/d) | bbl	2,000

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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		Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Gross Amount		$ 15,699	$ 16,440
Netting Adjustments	[1]	(6,272)	(6,556)
Net Amount Presented in Balance Sheets		9,427	9,884
Gross Amount		(24,615)	(21,508)
Netting Adjustments	[1]	6,272	6,556
Net Amount Presented in Balance Sheets		(18,343)	(14,952)
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		11,768	15,971
Netting Adjustments	[1]	(6,258)	(6,380)
Net Amount Presented in Balance Sheets		5,510	9,591
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		3,931	469
Netting Adjustments	[1]	(14)	(176)
Net Amount Presented in Balance Sheets		3,917	293
Current Liabilities [Member] | Accrued Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(23,012)	(21,256)
Netting Adjustments	[1]	6,258	6,380
Net Amount Presented in Balance Sheets		(16,754)	(14,876)
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(1,603)	(252)
Netting Adjustments	[1]	14	176
Net Amount Presented in Balance Sheets		$ (1,589)	$ (76)

[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
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ (4,215)	$ 25,097
Commodity Contract [Member] | Gain (Loss) on Derivative Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ (4,215)	$ 25,097

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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	Mar. 31, 2018	Dec. 31, 2017
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Total fair value	$ (8,916)	$ (5,068)
Commodity Contract [Member]
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Total fair value	(8,916)	(5,068)
Level 2 [Member]
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Total fair value	(8,916)	(5,068)
Level 2 [Member] | Commodity Contract [Member]
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Total fair value	$ (8,916)	$ (5,068)

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Debt - Additional Information (Detail) - USD ($)					3 Months Ended
	May 04, 2018	Feb. 24, 2017	Feb. 24, 2016	Jul. 06, 2015	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2014	Apr. 30, 2018	Aug. 01, 2017	Feb. 23, 2017
Debt Instrument [Line Items]
Debt instrument interest rate					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.
Outstanding borrowings					$ 65,000,000
Outstanding letters of credit					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		$ 175,000,000			225,000,000				$ 225,000,000	$ 125,000,000
Revolving credit facility, extended maturity month and year		2020-02
Outstanding borrowings					65,000,000
Available capacity on the Revolving Credit Facility					$ 126,400,000
Commitment fees on unused portion of revolving credit facility					0.50%
Revolving Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Borrowing base								$ 225,000,000
Outstanding borrowings	$ 45,000,000
Revolving credit facility repaid	20,000,000
Available capacity on the Revolving Credit Facility	$ 146,400,000
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					$ 900,000	$ 800,000
Debt instrument, fair value					$ 482,000,000
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
	Mar. 31, 2018	Mar. 31, 2017
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	$ 0.2
Plan name	401(K) plan

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Stock-Based Compensation - Additional Information (Detail)			3 Months Ended
	May 17, 2017 Director shares	May 18, 2016 Director shares	Mar. 31, 2018 USD ($) shares	Mar. 31, 2017 USD ($)
May Two Thousand Sixteen [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock expense				$ 100,000
May Two Thousand Seventeen [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock expense			$ 100,000
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 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]
Restricted shares of common stock issued | shares	153,192
Number of non employee directors | Director	3
Restricted Stock [Member] | May Two Thousand Seventeen [Member] | Board of Directors [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost			$ 100,000
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			$ 7,000,000
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			$ 6,400,000
Weighted average period for shares to vest			2 years
2014 Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be issue | shares			25,000,000
Number of shares are available for future grants | shares			7,199,257

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Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	$ 1,981	$ 2,081
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	1,164	1,247
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	728	734
Restricted Stock Issued to Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	$ 89	$ 100

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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	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, Beginning Balance	4,057,354
Number of shares, Granted	1,498,524
Number of shares, Vested	(1,378,403)
Number of shares, Forfeited	(6,512)
Number of shares, Ending Balance	4,170,963
Weighted average grant date fair value, Beginning Balance	$ 2.48
Weighted average grant date fair value, Granted	1.70
Weighted average grant date fair value, Vested	3.17
Weighted average grant date fair value, Forfeited	2.15
Weighted average grant date fair value, Ending Balance	$ 1.97
Aggregate intrinsic value	$ 6,006	$ 9,738

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Stock-Based Compensation - Summary of Performance Stock Unit Awards Activity (Detail) - Performance Units [Member] - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, Beginning Balance	3,966,377
Number of shares, Granted	1,498,524
Number of shares, Vested	0
Number of shares, Forfeited	(9,768)
Number of shares, Ending Balance	5,455,133
Weighted average grant date fair value, Beginning Balance	$ 1.82
Weighted average grant date fair value, Granted	1.92
Weighted average grant date fair value, Vested	0
Weighted average grant date fair value, Forfeited	1.94
Weighted average grant date fair value, Ending Balance	$ 1.84
Aggregate intrinsic value	$ 2,856	$ 11,257

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Stock-Based Compensation - Assumptions Used to Determine Fair Value of Performance Stock Units Granted (Detail) - Performance Units [Member]	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	89.70%	50.41%
Risk-free interest rate	2.37%	1.34%

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Earnings (Loss) Per Share - Schedule of Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Basic:
Net income (loss), basic	$ (2,626)	$ 26,847
Net income (loss), shares, basic	293,450	261,105
Net income (loss), per share, basic	$ (0.01)	$ 0.10
Weighted-average number of shares of common stock-diluted:
Restricted stock and performance unit awards		3,110
Diluted:
Net income (loss), diluted	$ (2,626)	$ 26,847
Net income (loss), shares, diluted	293,450	264,215
Net income (loss), per share, diluted	$ (0.01)	$ 0.10

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Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Chairman President and Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Flight charter services fees	$ 0.2	$ 0.1

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Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
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	$ 0.2

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Income Tax - Additional Information (Detail) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Income Tax Examination [Line Items]
Income taxes paid	$ 0
U.S. statutory tax rate	21.00%		35.00%
Estimated valuation allowance	$ 5,300,000
Scenario, Forecast [Member]
Income Tax Examination [Line Items]
Percentage of annual effective income tax rate		0.00%
Net deferred tax assets		$ 0

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Subsidiary Guarantors - Additional Information (Detail)	Mar. 31, 2018
Guarantees [Abstract]
Debt instrument interest rate	8.875%