Montage Resources 10-Q 9 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 06, 2019
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Trading Symbol	MR
Entity Registrant Name	Montage Resources Corporation
Entity Central Index Key	0001600470
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	true
Entity Ex Transition Period	true
Entity Common Stock, Shares Outstanding		35,617,374

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 7,592	$ 5,959
Accounts receivable	120,802	119,332
Assets held for sale	2,294
Other current assets	6,347	8,639
Total current assets	137,035	133,930
Oil and natural gas properties, successful efforts method:
Unproved properties	557,583	482,475
Proved oil and gas properties, net	1,101,772	807,583
Other property and equipment, net	13,146	6,300
Total property and equipment, net	1,672,501	1,296,358
OTHER NONCURRENT ASSETS
Other assets	8,182	3,481
Operating lease right-of-use asset	44,222
Assets held for sale	8,514
TOTAL ASSETS	1,870,454	1,433,769
CURRENT LIABILITIES
Accounts payable	141,410	116,735
Accrued capital expenditures	25,116	12,979
Accrued liabilities	61,960	56,909
Accrued interest payable	10,876	21,661
Liabilities associated with assets held for sale	8,212
Operating lease liability	19,787
Total current liabilities	267,361	208,284
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs	498,469	497,778
Revolving credit facility	97,500	32,500
Asset retirement obligations	24,148	7,110
Other liabilities	1,021	611
Operating lease liability	25,592
Liabilities associated with assets held for sale	6,639
Total liabilities	920,730	746,283
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, 35,682,480 and 20,169,063 shares issued and outstanding, respectively	382	3,043
Additional paid in capital	2,349,527	2,065,119
Treasury stock, shares at cost; 2,478,798 and 1,747,624 shares, respectively	(8,768)	(3,357)
Accumulated deficit	(1,391,417)	(1,377,319)
Total stockholders' equity	949,724	687,486
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 1,870,454	$ 1,433,769

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
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	35,682,480	20,169,063
Common stock, shares outstanding	35,682,480	20,169,063
Treasury stock, shares	2,478,798	1,747,624

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
REVENUES
Revenues	$ 141,497	$ 110,192
OPERATING EXPENSES
Lease operating	7,525	9,390
Production and ad valorem taxes	2,848	2,445
Brokered natural gas and marketing expense	9,459	48
Depreciation, depletion, amortization and accretion	29,897	31,311
Exploration	16,789	15,278
General and administrative	28,930	9,757
(Gain) loss on sale of assets	2	(267)
Other expense	24
Total operating expenses	136,642	95,651
OPERATING INCOME	4,855	14,541
OTHER INCOME (EXPENSE)
Loss on derivative instruments	(4,931)	(4,215)
Interest expense, net	(13,840)	(12,952)
Total other income (expense), net	(18,771)	(17,167)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(13,916)	(2,626)
LOSS FROM CONTINUING OPERATIONS	(13,916)	(2,626)
Loss from discontinued operations, net of income tax	(182)
NET LOSS	$ (14,098)	$ (2,626)
NET LOSS PER COMMON SHARE
Basic	$ (0.55)	$ (0.13)
Diluted	$ (0.55)	$ (0.13)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	25,564	19,563
Diluted	25,564	19,563
Oil and Gas [Member]
REVENUES
Revenues	$ 131,828	$ 110,184
Brokered Natural Gas and Marketing Revenue [Member]
REVENUES
Revenues	9,530	8
Other Revenue [Member]
REVENUES
Revenues	139
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
OPERATING EXPENSES
Transportation, gathering and compression	$ 41,168	$ 27,689

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - 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		17,516,024
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		2,521,573
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		(80,477)
Net 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		20,118,074
Beginning Balances at Dec. 31, 2018	687,486	$ 3,043	2,065,119	(3,357)	(1,377,319)
Beginning Balance, shares at Dec. 31, 2018		20,169,063
Stock-based compensation	6,001		6,001
Equity issuance costs	(30)		(30)
Shares of common stock issued in asset acquisition, net of equity issuance costs	275,759	$ 150	275,609
Shares of common stock issued in asset acquisition, net of equity issuance costs, shares		15,013,520
Reverse split		$ (2,833)	2,833
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	(5,394)	$ 22	(5)	(5,411)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares		(499,897)
Net loss	(14,098)				(14,098)
Ending Balances at Mar. 31, 2019	$ 949,724	$ 382	$ 2,349,527	$ (8,768)	$ (1,391,417)
Ending Balance, shares at Mar. 31, 2019		35,682,480

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical)	3 Months Ended
	Mar. 31, 2019$ / shares	Dec. 31, 2018$ / shares	Mar. 31, 2018$ / shares	Dec. 31, 2017$ / shares
Statement Of Stockholders Equity [Abstract]
Common stock, par value	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Reverse split ratio	0.067

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (14,098)	$ (2,626)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depreciation, depletion, amortization and accretion	29,950	31,311
Exploration expense	9,600	6,790
Stock-based compensation	6,001	1,981
Net cash for plugging wells	(48)
Loss on derivative instruments	4,931	4,215
Net cash receipts (payments) on settled derivatives	(3,186)	141
(Gain) loss on sale of assets	2	(267)
Amortization of deferred financing costs	629	554
Amortization of debt discount	333	332
Changes in operating assets and liabilities:
Accounts receivable	25,812	(35,499)
Other assets	(188)	(459)
Accounts payable and accrued liabilities	(68,643)	(3,179)
Net cash provided by (used in) operating activities	(8,905)	3,294
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties	(58,530)	(66,441)
Capital expenditures for other property and equipment	(184)	(155)
Proceeds from sale of assets	1	4,099
Cash proceeds from merger	12,894
Change in deposits and other long term assets	(3)
Net cash used in investing activities	(45,822)	(62,497)
CASH FLOWS FROM FINANCING ACTIVITIES
Debt issuance costs	(3,102)	(48)
Repayments of long-term debt	(98)	(92)
Proceeds (repayments) from revolving credit facility	65,000	65,000
Equity issuance costs	(30)	(145)
Employee tax withholding for settlement of equity compensation awards	(5,410)	(935)
Net cash provided by financing activities	56,360	63,780
Net increase in cash and cash equivalents	1,633	4,577
Cash and cash equivalents at beginning of period	5,959	17,224
Cash and cash equivalents at end of period	7,592	21,801
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	24,198	23,638
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	16,691	85
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	45,287	8,864
Asset acquisition through stock issuance		$ 90,020
BRMR Merger consideration	$ 275,759

Organization and Nature of Oper

Organization and Nature of Operations	3 Months Ended
	Mar. 31, 2019
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Nature of Operations	Note 1—Organization and Nature of Operations Montage 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, Indian Castle/Flat Creek Shales and Marcellus Shale prospective areas.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2019
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, 2018, 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 15, 2019. Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2019 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 • estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion, amortization and accretion 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
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, 2019 or December 31, 2018. The Company accrues revenue due to timing differences between the delivery of natural gas, 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 $83.2 million and $94.1 million of accrued revenues, net of certain expenses, at March 31, 2019 and December 31, 2018, 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, amortization and accretion expense (see “Depreciation, Depletion, Amortization and Accretion 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, 2019 December 31, 2018 Oil and natural gas properties: Unproved $ 557,583 $ 482,475 Proved 2,511,575 2,188,233 Gross oil and natural gas properties 3,069,158 2,670,708 Less accumulated depreciation, depletion and amortization (1,409,803 ) (1,380,650 ) Oil and natural gas properties, net 1,659,355 1,290,058 Other property and equipment 21,662 14,460 Less accumulated depreciation (8,516 ) (8,160 ) Other property and equipment, net 13,146 6,300 Property and equipment, net $ 1,672,501 $ 1,296,358 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 $0.7 million and $0.5 million for the three months ended March 31, 2019 and 2018, 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 receive 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 deliver the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials and certain downstream costs incurred by third parties. 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 at central stabilization facilities and well pads and collects a contractually agreed upon index price, net of pricing differentials. The Company transfers control of the product from the central stabilization facilities and well pads 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, 2019 and 2018: Three Months Ended March 31, 2019 2018 Revenues (in thousands) Natural gas sales $ 81,825 $ 58,483 NGL sales 21,248 19,743 Oil sales 28,755 31,958 Brokered natural gas and marketing revenue 9,530 8 Other revenue 139 — Total revenues $ 141,497 $ 110,192 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 are 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 $83.2 million and $94.1 million at March 31, 2019 and December 31, 2018, 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 (if any), by product or service as of March 31, 2019 and December 31, 2018 (in thousands): March 31, 2019 December 31, 2018 Receivables by product or service: Sale of oil and natural gas and related products and services $ 83,188 $ 94,107 Joint interest owners 35,559 24,830 Derivatives 1,878 372 Other 177 23 Total $ 120,802 $ 119,332 Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the States of Ohio, Pennsylvania and West Virginia. 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 ($3.3) million and a net asset position of $5.7 million at March 31, 2019 and December 31, 2018, 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, 2019 and December 31, 2018, the Company did not have past-due receivables from or payables to any of such counterparties. (f) Depreciation, Depletion, Amortization, and Accretion 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 $29.5 million and $30.9 million for the three months ended March 31, 2019 and 2018, respectively and is included in Depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations. 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 $0.4 million and $0.5 million for the three months ended March 31, 2019 and 2018, respectively. This amount is included in Depreciation, depletion, amortization and accretion 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, 2019 or the three months ended March 31, 2018. 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 $9.6 million and $6.7 million for the three months ended March 31, 2019 and 2018, respectively. 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 ( i.e. The Company applies Topic 740’s intra-period income tax allocation rules using the with and without approach, to allocate income tax expense (benefit) among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital as required. (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. 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, 2019 (in thousands): Three Months Ended March 31, 2019 Asset retirement obligations, beginning of period $ 7,110 Accretion 347 Additional liabilities incurred 49 Obligation for wells acquired 20,188 Liabilities settled via plugging (26 ) Less: current ARO portion (accrued liabilities) (3,520 ) Asset retirement obligations, end of period $ 24,148 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) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. (m) 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. (n) 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. (o) Recent Accounting Pronouncements Recently Adopted 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. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements”. The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements”, which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption. The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third party sponsored lease accounting information system to facilitate the accounting and financial reporting requirements, and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment. See “Note 7 – Leases” for the disclosures required by the standards.

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2019
Business Combinations [Abstract]
Acquisitions	Note 4—Acquisitions Eclipse Resources-PA, LP 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 2.5 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. During the year ended December 31, 2018, the Company assigned its option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC (“Cardinal”), a wholly owned subsidiary of Cardinal Midstream II, LLC which owns midstream infrastructure with associated gathering rights on acreage in the Indian Castle and Flat Creek Shales, to a third party. The third party exercised its option to purchase all of the outstanding equity interests of Cardinal in July 2018. Merger with Blue Ridge Mountain Resources On February 28, 2019, the Company completed its previously announced business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”). As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 15-to-1 (See Note 13— Earnings (Loss) Per Share ) The following table summarizes the preliminary purchase price allocation and the values of assets acquired and liabilities assumed (in thousands): Purchase Price February 28, 2019 Fair value of Montage common stock issued $ 263,487 Fair value of BRMR share-based and other compensation 12,272 Total Fair Value of Consideration $ 275,759 Cash and cash equivalents 12,894 Accounts receivable 25,884 Assets held for sale - current 2,296 Other current assets 1,702 Unproved properties 84,742 Proved oil and gas properties 218,866 Other property and equipment 7,059 Other assets 2,461 Operating lease right-of-use asset 7,900 Assets held for sale - long-term 8,505 Total assets acquired $ 372,309 Accounts payable (16,571 ) Accrued capital expenditures (5,807 ) Accrued liabilities (31,619 ) Operating lease liability - current (1,977 ) Liabilities associated with assets held for sale - current (7,683 ) Asset retirement obligations (20,188 ) Operating lease liability - noncurrent (5,923 ) Liabilities associated with assets held for sale - long-term (6,782 ) Total liabilities assumed $ (96,550 ) Net identifiable assets $ 275,759 The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighed average cost of capital rate. The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin. These inputs required significant judgements and estimates by management at the time of the valuation and are the most sensitive to possible future changes. The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2018. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results. For the Three Months Ended March 31, (in thousands, except per share data) (unaudited) 2019 2018 Pro forma total revenues $ 184,155 $ 133,900 Pro forma net loss from continuing operations $ (26,760 ) $ (4,731 ) Pro forma loss per share (basic and diluted) $ (0.78 ) $ (0.28 )

Sale of Oil and Natural Gas Pro

Sale of Oil and Natural Gas Property Interests	3 Months Ended
	Mar. 31, 2019
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 of approximately 400 acres to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties. During the three months ended March 31, 2018, the Company received approximately $0.3 million from an additional completed asset sale of approximately 50 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $0.3 million.

Assets Held for Sale and Discon

Assets Held for Sale and Discontinued Operations	3 Months Ended
	Mar. 31, 2019
Discontinued Operations And Disposal Groups [Abstract]
Assets Held for Sale and Discontinued Operations	Note 6—Assets Held for Sale and Discontinued Operations Assets Held for Sale As a result of the BRMR Merger, the Company acquired certain assets that met the criteria for assets held for sale at the acquisition date, comprised of the net assets of Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of BRMR located primarily in Kentucky and Tennessee. The following summarizes assets and liabilities held for sale at March 31, 2019: (in thousands) March 31, 2019 Accounts receivable $ 1,797 Other current assets 497 Total current assets held for sale $ 2,294 Proved oil and gas properties, net $ 8,270 Other noncurrent assets 244 Total noncurrent assets held for sale $ 8,514 Accounts payable $ 2,583 Accrued liabilities 5,312 Other current liabilities 317 Total current liabilities associated with assets held for sale $ 8,212 Asset retirement obligations $ 6,029 Other liabilities 610 Total noncurrent liabilities associated with assets held for sale $ 6,639 Discontinued Operations The Company determined that the planned divestiture of MHP met the assets held for sale criteria and the criteria for classification as discontinued operations as of March 31, 2019. The Company included the results of operations for MHP for the period from March 1, 2019 through March 31, 2019 presented in discontinued operations as follows: For the Three Months Ended March 31, (in thousands) 2019 Revenues $ 949 Depreciation, depletion, amortization and accretion (52 ) Other operating expenses (1,079 ) Loss from discontinued operations, net of tax (182 ) Gain on disposal of discontinued operations, net of tax — Loss from discontinued operations, net of tax $ (182 ) Total operating and investing cash flows of discontinued operations for the period from March 1, 2019 through March 31, 2019 were as follows: For the Three Months Ended March 31, (in thousands) 2019 Net cash provided by operating activities $ 1,046 Net cash provided by investing activities $ 1

Leases

Leases	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Leases	Note 7—Leases The Company leases drilling rigs, compressors, vehicles, office space, and other equipment under non-cancelable operating leases expiring through 2036. Certain lease agreements may include options to renew the lease, terminate the lease early, or may purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including the options to extend or terminate the lease when such an option is reasonably certain to be exercised. As discussed in Note 3— Summary of Significant Accounting Policies , the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 “Leases (Topic 842)” on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification and (iii) initial direct costs. In addition, the Company elected the following practical expedients for all asset classes: (i) to not reassess certain land easements; (ii) to not apply the recognition requirements under the standard to short-term leases; and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and recognition of variable nonlease payments as variable lease expense. On January 1, 2019, the Company recorded a total of $10.4 million in right-of-use assets and corresponding new lease liabilities on its Condensed Consolidated Balance Sheets representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date. The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts and terms recognized under the prior lease accounting guidance. Leases with an initial term of twelve months or less, taking into account extensions if reasonably certain to be exercised, are considered short-term leases and are not recorded on the balance sheet. The Company incurred $2.3 million in operating lease cost during the three months ended March 31, 2019. The operating lease right-of-use assets were reported in other noncurrent assets and the current and noncurrent portions of the operating lease liabilities were reported in other current liabilities and other liabilities, respectively, on the Condensed Consolidated Balance Sheets. As of March 31, 2019, the operating right-of-use assets were $44.2 million and operating lease liabilities were $45.4 million, of which $19.8 million was classified as current. As of March 31, 2019, the weighted average remaining lease term was 3.5 years and the weighted average discount rate was 5.6%. Supplemental cash flow information related to the Company’s operating leases is included in the table below (in thousands): For the Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 870 Investing cash flows from operating leases $ 1,452 ROU assets added in exchange for lease obligations (upon adoption) $ 10,434 ROU assets and lease obligations acquired in BRMR Merger $ 7,900 ROU assets added in exchange for lease obligations (since adoption) $ 27,169 The Company’s lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands): Operating Leases Remainder of 2019 $ 16,362 2020 15,132 2021 6,574 2022 4,630 2023 2,467 Thereafter 4,438 Total lease payments $ 49,603 Less imputed interest (4,224 ) Total lease liability $ 45,379

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments	Note 8—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, 2019 , the C ompany’s derivative instruments were with Bank of Montreal, J Aron, Morgan Stanley, Capital One N.A., BP Energy Company, KeyBank N.A, NextEra Energy, Inc., Shell Oil Company and EDF Energy. The Company has not experienced any issues of non-performance by d erivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of March 31, 2019 , for future production periods: Natural Gas Derivatives: Description Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Swaps: 90,000 April 2019 – December 2019 $ 2.84 15,000 April 2019 – September 2019 $ 2.79 Natural Gas Collars: Floor purchase price (put) 55,000 April 2019 – June 2019 $ 2.51 Ceiling sold price (call) 55,000 April 2019 – June 2019 $ 2.81 Floor purchase price (put) 75,000 July 2019 – September 2019 $ 2.50 Ceiling sold price (call) 75,000 July 2019 – September 2019 $ 2.87 Floor purchase price (put) 65,000 October 2019 – December 2019 $ 2.65 Ceiling sold price (call) 65,000 October 2019 – December 2019 $ 2.96 Floor purchase price (put) 30,000 January 2020 – March 2020 $ 2.72 Ceiling sold price (call) 30,000 January 2020 – March 2020 $ 3.15 Floor purchase price (put) 15,000 April 2020 – June 2020 $ 2.50 Ceiling sold price (call) 15,000 April 2020 – June 2020 $ 2.80 Natural Gas Three-way Collars: Floor purchase price (put) 77,500 April 2019 – December 2019 $ 2.72 Ceiling sold price (call) 77,500 April 2019 – December 2019 $ 3.04 Floor sold price (put) 77,500 April 2019 – December 2019 $ 2.30 Floor purchase price (put) 40,000 April 2019 – June 2019 $ 2.65 Ceiling sold price (call) 40,000 April 2019 – June 2019 $ 2.84 Floor sold price (put) 40,000 April 2019 – June 2019 $ 2.30 Floor purchase price (put) 70,000 January 2020 – June 2020 $ 2.70 Ceiling sold price (call) 70,000 January 2020 – June 2020 $ 2.98 Floor sold price (put) 70,000 January 2020 – June 2020 $ 2.25 Floor purchase price (put) 30,000 October 2019 – June 2020 $ 2.90 Ceiling sold price (call) 30,000 October 2019 – June 2020 $ 3.15 Floor sold price (put) 30,000 October 2019 – June 2020 $ 2.50 Natural Gas Call/Put Options: Call sold 40,000 April 2019 – December 2019 $ 3.44 Basis Swaps: Appalachia - Dominion 12,500 April 2019 – October 2019 $ (0.52 ) Appalachia - Dominion 12,500 April 2020 – October 2020 $ (0.52 ) Appalachia - Dominion 20,000 January 2020 – December 2020 $ (0.59 ) Appalachia - Dominion 17,500 April 2019 – December 2019 $ (0.50 ) Appalachia - Dominion 20,000 April 2019 – March 2020 $ (0.39 ) Oil Derivatives: Description Volume (Bbls/d) Production Period Weighted Average Price Oil Swaps: 1,500 July 2019 – December 2019 $ 59.18 1,000 January 2020 – December 2020 $ 58.60 Oil Collars: Floor purchase price (put) 1,500 July 2019 – December 2019 $ 51.67 Ceiling sold price (call) 1,500 July 2019 – December 2019 $ 65.92 Floor purchase price (put) 500 January 2020 – December 2020 $ 50.00 Ceiling sold price (call) 500 January 2020 – December 2020 $ 64.00 Oil Three-way Collars: Floor purchase price (put) 2,000 April 2019 – December 2019 $ 50.00 Ceiling sold price (call) 2,000 April 2019 – December 2019 $ 60.56 Floor sold price (put) 2,000 April 2019 – December 2019 $ 40.00 Floor purchase price (put) 2,000 January 2020 – June 2020 $ 62.50 Ceiling sold price (call) 2,000 January 2020 – June 2020 $ 74.00 Floor sold price (put) 2,000 January 2020 – June 2020 $ 55.00 NGL Derivatives: Description Volume (Bbls/d) Production Period Weighted Average Price ($/Bbl) Propane Swaps: 350 April 2019 – December 2019 $ 39.90 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, 2019 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 2,416 $ (2,154 ) $ 262 Other current assets Commodity derivatives - noncurrent 1,510 (176 ) 1,334 Other assets Total assets $ 3,926 $ (2,330 ) $ 1,596 Liabilities Commodity derivatives - current $ (6,234 ) $ 2,154 $ (4,080 ) Accrued liabilities Commodity derivatives - noncurrent (972 ) 176 (796 ) Other liabilities Total liabilities $ (7,206 ) $ 2,330 $ (4,876 ) As of December 31, 2018 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 4,960 $ (845 ) $ 4,115 Other current assets Commodity derivatives - noncurrent 1,910 — 1,910 Other assets Total assets $ 6,870 $ (845 ) $ 6,025 Liabilities Commodity derivatives - current $ (845 ) $ 845 $ — Accrued liabilities Commodity derivatives - noncurrent (326 ) — (326 ) Other liabilities Total liabilities $ (1,171 ) $ 845 $ (326 ) (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, 2019 2018 Commodity derivatives Gain (loss) on derivative instruments $ (4,931 ) $ (4,215 )

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 9—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 Total As of March 31, 2019: (in thousands) Commodity derivative instruments $ — $ (3,280 ) $ — $ (3,280 ) Total $ — $ (3,280 ) $ — $ (3,280 ) As of December 31, 2018: (in thousands) Commodity derivative instruments $ — $ 5,699 $ — $ 5,699 Total $ — $ 5,699 $ — $ 5,699 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 capita lized 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 dis count 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 10— Debt

Debt

Debt	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Debt	Note 10—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, 2019 and 2018, the Company amortized $1.0 million and $0.9 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, 2019. Based on Level 2 market data inputs, the fair value of the senior unsecured notes at March 31, 2019 was $486.6 million. Revolving Credit Facility During the first quarter of 2014, the 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). The credit agreement governing the revolving credit facility (as amended and restated, the “Credit Agreement”) was amended and restated on January 12, 2015. The primary change effected by such amendment was to add Montage Resources Corporation as a party to the revolving credit facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions thereof. Relative to Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Montage 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 remain generally consistent with Eclipse I’s previous credit agreement. On February 24, 2016, the Company amended the Credit Agreement 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. On February 28, 2019, the Company amended and restated the Credit Agreement to increase its revolving credit facility from $500 million to $1 billion. Further, the amended and restated Credit Agreement, among other things, increases the borrowing base from $225 million to $375 million (subject to scheduled and interim redeterminations based on the Company’s oil and natural gas reserves and other adjustments described therein) and extends the maturity date thereof to February 2024 (subject to earlier maturity in certain circumstances specified therein). The amended and restated Credit Agreement also adjusted the ratio of Consolidated Total Funded Net Debt to EBITDAX (as such terms are defined in the Credit Agreement) to provide that the Company will not, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2019), permit its ratio of Consolidated Total Funded Net Debt to EBITDAX for the four previous fiscal quarters to be greater than 4.00 to 1.00. At March 31, 2019, the borrowing base was $375 million and the Company had $97.5 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $13.5 million and the outstanding borrowings of $97.5 million, the Company had available borrowing capacity under the revolving credit facility of $264.0 million at March 31, 2019. Subsequent to March 31, 2019, the Company borrowed an incremental $25 million under its revolving credit facility and issued an additional $15.7 million in outstanding letters of credit. Further, on May 6, 2019, the Company entered into an amendment to the Credit Agreement that increased the borrowing base from $375 million to $400 million. As of May 9, 2019 the available borrowing capacity under the revolving credit facility was $248.3 million. The revolving credit facility is secured by mortgages on 85% of the value of the Company’s proved reserves 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, 2019. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.375%-0.500% of the unused facility based on utilization.

Benefit Plans

Benefit Plans	3 Months Ended
	Mar. 31, 2019
Compensation And Retirement Disclosure [Abstract]
Benefit Plans	Note 11—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, 2019 and 2018, respectively.

Stock-Based Compensation

Stock-Based Compensation	3 Months Ended
	Mar. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock-Based Compensation	Note 12—Stock-Based Compensation The Company is authorized to grant up to 1,666,667 shares of common stock under its 2014 Long-Term Incentive Plan (as amended, the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 430,656 shares were available for future grants under the Plan as of March 31, 2019. Our stock-based compensation expense was as follows for the three months ended March 31, 2019 and 2018 (in thousands): Three Months Ended March 31, 2019 2018 Restricted stock units $ 3,147 $ 1,164 Performance units 2,759 728 Restricted stock issued to directors 95 89 Total expense $ 6,001 $ 1,981 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, 2019, there was $0.8 million of total unrecognized compensation cost related to outstanding restricted stock units. The weighted average period for the shares to vest is approximately 2 years. A summary of employee restricted stock unit awards activity during the three months ended March 31, 2019 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2018 233,960 $ 29.27 $ 3,685 Granted 70,409 17.55 Vested (198,279 ) 29.28 Forfeited (485 ) 31.78 Total awarded and unvested, March 31, 2019 105,605 $ 21.42 $ 1,588 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, 2019, there was $2.0 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the shares to vest is approximately 1 year. A summary of performance stock unit awards activity during the three months ended March 31, 2019 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2018 346,589 $ 27.68 $ 716 Granted — — Vested (265,311 ) 27.54 Forfeited (16,001 ) 24.47 Total awarded and unvested, March 31, 2019 65,277 $ 29.02 $ 1,201 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: Three Months Ended March 31, 2018 Volatility 89.70 % Risk-free interest rate 2.37 % Restricted Stock On May 17, 2017, the Company issued an aggregate of 10,212 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 17, 2018. For the three months ended March 31, 2018, the Company recognized expense of approximately $0.1 million related to these awards. On May 16, 2018, the Company issued an aggregate of 15,476 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 16, 2019. For the three months ended March 31, 2019, the Company recognized expense of approximately $0.1 million related to these awards. As of March 31, 2019, there was approximately less than $0.1 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s directors.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	3 Months Ended
	Mar. 31, 2019
Earnings Per Share [Abstract]
Earnings (Loss) Per Share	Note 13—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. Reverse Stock Split Effective immediately prior to the Effective Time (See Note 4— Acquisitions ), the Company effected a 15-to-1 reverse stock split of its common stock. . The table below retroactively reflects, in accordance with ASC 505 “Equity”, the reverse stock split that occurred on February 28, 2019 for the three months ended March 31, 2018. 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, 2019 and 2018: Three Months Ended March 31, (in thousands, except per share data) 2019 2018 Loss Shares Per Share Loss Shares Per Share Basic: Net loss, shares, basic $ (14,098 ) 25,564 $ (0.55 ) $ (2,626 ) 19,563 $ (0.13 ) Weighted-average number of shares of common stock-diluted: Restricted stock and performance unit awards — — — — Diluted: Net loss, shares, diluted $ (14,098 ) 25,564 $ (0.55 ) $ (2,626 ) 19,563 $ (0.13 )

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Note 14—Related Party Transactions During the three months ended March 31, 2019 and 2018, the Company incurred approximately less than $0.1 and $0.2 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which were owned by the Company’s former Chairman, President and Chief Executive Officer. The fees were paid in accordance with a standard service contract that did not obligate the Company to any minimum terms. The Company no longer utilizes any flight charter services under this arrangement. Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap Investments L.P. (“EnCap”). EnCap has representatives on the Board, and affiliates of EnCap collectively beneficially own approximately 40% of the outstanding shares of the Company’s common stock. (See Note 4— Acquisitions

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2019
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 15—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) Other Commitments As a result of the BRMR Merger, the Company assumed commitments related to certain gas gathering and processing agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR as shown below (in thousands): Firm transportation (i) Gas processing, gathering, and compression services (ii) Total Year Ending December 31: 2019 $ 14,562 $ 12,873 $ 27,435 2020 19,416 17,133 $ 36,549 2021 19,416 17,087 $ 36,503 2022 19,416 17,087 $ 36,503 2023 18,047 16,561 $ 34,608 Thereafter 92,395 139,545 $ 231,940 Total $ 183,252 $ 220,286 $ 403,538 (i) Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest. (ii) Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements its proportionate share of costs based on the Company’s working interest

Income Tax

Income Tax	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Income Tax	Note 16—Income Tax For the year ending December 31, 2019, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company expects to incur book income but a tax loss in fiscal year 2019, 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%. In forecasting the 2019 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book income such that no net deferred tax asset is recorded in 2019. Management reached this conclusion considering several factors such as: (i) the lack of carryback potential resulting in a tax refund, and (ii) in light of current commodity pricing uncertainty, there is insuf ficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s balance sheet. The Company is forecasting positive pre-tax book income for the year ending December 31, 2019. Management expects that income tax expense attributable to current year operations will be offset by a release of the valuation allowance on hand at the beginning of the year. As a result, no net income tax expense or benefit is allocable to either income from continuing operations or to discontinued operations. As a result of the BRMR Merger, the Company may undergo an ownership change as described in Code section 382. This may limit the future annual availability of the use of the Company’s NOLs that accrued prior to the ownership change date as well as future tax depreciation, depletion and amortization amounts. The Company is still evaluating the impacts that Code section 382 will have on its tax attributes.

Subsidiary Guarantors

Subsidiary Guarantors	3 Months Ended
	Mar. 31, 2019
Text Block [Abstract]
Subsidiary Guarantors	Note 17—Subsidiary Guarantors Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, joint and severally, guarantee the Company’s 8.875% senior unsecured notes. Each such subsidiary of the Company in existence immediately prior to the BRMR Merger guaranteed the Company’s 8.875% senior unsecured notes. As a result of the BRMR Merger, and within the timeframe required by the indenture governing the Company’s 8.875% senior unsecured notes, the Company caused BRMR and each of its subsidiaries that guaranteed the Company’s revolving credit facility to guarantee the Company’s 8.875% senior unsecured notes (See Note 10— Debt 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.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	Note 18—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 the redetermination on the credit facility, new letters of credit and the midstream agreements disclosed in the accompanying notes to the condensed consolidated financial statements (See Note 10— Debt Commitments and Contingencies

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2019
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, 2019 or December 31, 2018. The Company accrues revenue due to timing differences between the delivery of natural gas, 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 $83.2 million and $94.1 million of accrued revenues, net of certain expenses, at March 31, 2019 and December 31, 2018, 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, amortization and accretion expense (see “Depreciation, Depletion, Amortization and Accretion 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, 2019 December 31, 2018 Oil and natural gas properties: Unproved $ 557,583 $ 482,475 Proved 2,511,575 2,188,233 Gross oil and natural gas properties 3,069,158 2,670,708 Less accumulated depreciation, depletion and amortization (1,409,803 ) (1,380,650 ) Oil and natural gas properties, net 1,659,355 1,290,058 Other property and equipment 21,662 14,460 Less accumulated depreciation (8,516 ) (8,160 ) Other property and equipment, net 13,146 6,300 Property and equipment, net $ 1,672,501 $ 1,296,358 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 $0.7 million and $0.5 million for the three months ended March 31, 2019 and 2018, 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 receive 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 deliver the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials and certain downstream costs incurred by third parties. 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 at central stabilization facilities and well pads and collects a contractually agreed upon index price, net of pricing differentials. The Company transfers control of the product from the central stabilization facilities and well pads 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, 2019 and 2018: Three Months Ended March 31, 2019 2018 Revenues (in thousands) Natural gas sales $ 81,825 $ 58,483 NGL sales 21,248 19,743 Oil sales 28,755 31,958 Brokered natural gas and marketing revenue 9,530 8 Other revenue 139 — Total revenues $ 141,497 $ 110,192 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 are 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 $83.2 million and $94.1 million at March 31, 2019 and December 31, 2018, 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 (if any), by product or service as of March 31, 2019 and December 31, 2018 (in thousands): March 31, 2019 December 31, 2018 Receivables by product or service: Sale of oil and natural gas and related products and services $ 83,188 $ 94,107 Joint interest owners 35,559 24,830 Derivatives 1,878 372 Other 177 23 Total $ 120,802 $ 119,332 Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the States of Ohio, Pennsylvania and West Virginia. 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 ($3.3) million and a net asset position of $5.7 million at March 31, 2019 and December 31, 2018, 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, 2019 and December 31, 2018, the Company did not have past-due receivables from or payables to any of such counterparties.
Depreciation, Depletion, Amortization, and Accretion	(f) Depreciation, Depletion, Amortization, and Accretion 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 $29.5 million and $30.9 million for the three months ended March 31, 2019 and 2018, respectively and is included in Depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations. 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 $0.4 million and $0.5 million for the three months ended March 31, 2019 and 2018, respectively. This amount is included in Depreciation, depletion, amortization and accretion 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, 2019 or the three months ended March 31, 2018. 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 $9.6 million and $6.7 million for the three months ended March 31, 2019 and 2018, respectively. 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 ( i.e. The Company applies Topic 740’s intra-period income tax allocation rules using the with and without approach, to allocate income tax expense (benefit) among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital as required.
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. 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, 2019 (in thousands): Three Months Ended March 31, 2019 Asset retirement obligations, beginning of period $ 7,110 Accretion 347 Additional liabilities incurred 49 Obligation for wells acquired 20,188 Liabilities settled via plugging (26 ) Less: current ARO portion (accrued liabilities) (3,520 ) Asset retirement obligations, end of period $ 24,148 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.
Off-Balance Sheet Arrangements	(l) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements.
Segment Reporting	(m) 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	(n) 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	(o) Recent Accounting Pronouncements Recently Adopted 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. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements”. The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements”, which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption. The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third party sponsored lease accounting information system to facilitate the accounting and financial reporting requirements, and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment. See “Note 7 – Leases” for the disclosures required by the standards.
Leases	As discussed in Note 3— Summary of Significant Accounting Policies , the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 “Leases (Topic 842)” on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification and (iii) initial direct costs. In addition, the Company elected the following practical expedients for all asset classes: (i) to not reassess certain land easements; (ii) to not apply the recognition requirements under the standard to short-term leases; and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and recognition of variable nonlease payments as variable lease expense.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
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, 2019 December 31, 2018 Oil and natural gas properties: Unproved $ 557,583 $ 482,475 Proved 2,511,575 2,188,233 Gross oil and natural gas properties 3,069,158 2,670,708 Less accumulated depreciation, depletion and amortization (1,409,803 ) (1,380,650 ) Oil and natural gas properties, net 1,659,355 1,290,058 Other property and equipment 21,662 14,460 Less accumulated depreciation (8,516 ) (8,160 ) Other property and equipment, net 13,146 6,300 Property and equipment, net $ 1,672,501 $ 1,296,358
Summary of Revenue Disaggregated by Type	The following table illustrates the revenue disaggregated by type for the three months ended March 31, 2019 and 2018: Three Months Ended March 31, 2019 2018 Revenues (in thousands) Natural gas sales $ 81,825 $ 58,483 NGL sales 21,248 19,743 Oil sales 28,755 31,958 Brokered natural gas and marketing revenue 9,530 8 Other revenue 139 — Total revenues $ 141,497 $ 110,192
Concentration Risk	The following table summarizes the Company’s concentration of receivables, net of allowances (if any), by product or service as of March 31, 2019 and December 31, 2018 (in thousands): March 31, 2019 December 31, 2018 Receivables by product or service: Sale of oil and natural gas and related products and services $ 83,188 $ 94,107 Joint interest owners 35,559 24,830 Derivatives 1,878 372 Other 177 23 Total $ 120,802 $ 119,332
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, 2019 (in thousands): Three Months Ended March 31, 2019 Asset retirement obligations, beginning of period $ 7,110 Accretion 347 Additional liabilities incurred 49 Obligation for wells acquired 20,188 Liabilities settled via plugging (26 ) Less: current ARO portion (accrued liabilities) (3,520 ) Asset retirement obligations, end of period $ 24,148

Acquisitions (Tables)

Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2019
Business Combinations [Abstract]
Summary of Preliminary Purchase Price Allocation and Values of Assets Acquired and Liabilities Assumed	The following table summarizes the preliminary purchase price allocation and the values of assets acquired and liabilities assumed (in thousands): Purchase Price February 28, 2019 Fair value of Montage common stock issued $ 263,487 Fair value of BRMR share-based and other compensation 12,272 Total Fair Value of Consideration $ 275,759 Cash and cash equivalents 12,894 Accounts receivable 25,884 Assets held for sale - current 2,296 Other current assets 1,702 Unproved properties 84,742 Proved oil and gas properties 218,866 Other property and equipment 7,059 Other assets 2,461 Operating lease right-of-use asset 7,900 Assets held for sale - long-term 8,505 Total assets acquired $ 372,309 Accounts payable (16,571 ) Accrued capital expenditures (5,807 ) Accrued liabilities (31,619 ) Operating lease liability - current (1,977 ) Liabilities associated with assets held for sale - current (7,683 ) Asset retirement obligations (20,188 ) Operating lease liability - noncurrent (5,923 ) Liabilities associated with assets held for sale - long-term (6,782 ) Total liabilities assumed $ (96,550 ) Net identifiable assets $ 275,759
Unaudited Pro Forma Financial Information	The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2018. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results. For the Three Months Ended March 31, (in thousands, except per share data) (unaudited) 2019 2018 Pro forma total revenues $ 184,155 $ 133,900 Pro forma net loss from continuing operations $ (26,760 ) $ (4,731 ) Pro forma loss per share (basic and diluted) $ (0.78 ) $ (0.28 )

Assets Held for Sale and Disc_2

Assets Held for Sale and Discontinued Operations (Tables)	3 Months Ended
	Mar. 31, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Summary of Assets Held for Sale and Discontinued Operations	The Company included the results of operations for MHP for the period from March 1, 2019 through March 31, 2019 presented in discontinued operations as follows: For the Three Months Ended March 31, (in thousands) 2019 Revenues $ 949 Depreciation, depletion, amortization and accretion (52 ) Other operating expenses (1,079 ) Loss from discontinued operations, net of tax (182 ) Gain on disposal of discontinued operations, net of tax — Loss from discontinued operations, net of tax $ (182 ) Total operating and investing cash flows of discontinued operations for the period from March 1, 2019 through March 31, 2019 were as follows: For the Three Months Ended March 31, (in thousands) 2019 Net cash provided by operating activities $ 1,046 Net cash provided by investing activities $ 1
Assets Held for Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Summary of Assets Held for Sale and Discontinued Operations	The following summarizes assets and liabilities held for sale at March 31, 2019: (in thousands) March 31, 2019 Accounts receivable $ 1,797 Other current assets 497 Total current assets held for sale $ 2,294 Proved oil and gas properties, net $ 8,270 Other noncurrent assets 244 Total noncurrent assets held for sale $ 8,514 Accounts payable $ 2,583 Accrued liabilities 5,312 Other current liabilities 317 Total current liabilities associated with assets held for sale $ 8,212 Asset retirement obligations $ 6,029 Other liabilities 610 Total noncurrent liabilities associated with assets held for sale $ 6,639

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Supplemental Cash Flow Information Related to Operating Leases	Supplemental cash flow information related to the Company’s operating leases is included in the table below (in thousands): For the Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 870 Investing cash flows from operating leases $ 1,452 ROU assets added in exchange for lease obligations (upon adoption) $ 10,434 ROU assets and lease obligations acquired in BRMR Merger $ 7,900 ROU assets added in exchange for lease obligations (since adoption) $ 27,169
Schedule of Lease Liabilities	The Company’s lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands): Operating Leases Remainder of 2019 $ 16,362 2020 15,132 2021 6,574 2022 4,630 2023 2,467 Thereafter 4,438 Total lease payments $ 49,603 Less imputed interest (4,224 ) Total lease liability $ 45,379

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2019
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, 2019 , for future production periods: Natural Gas Derivatives: Description Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Swaps: 90,000 April 2019 – December 2019 $ 2.84 15,000 April 2019 – September 2019 $ 2.79 Natural Gas Collars: Floor purchase price (put) 55,000 April 2019 – June 2019 $ 2.51 Ceiling sold price (call) 55,000 April 2019 – June 2019 $ 2.81 Floor purchase price (put) 75,000 July 2019 – September 2019 $ 2.50 Ceiling sold price (call) 75,000 July 2019 – September 2019 $ 2.87 Floor purchase price (put) 65,000 October 2019 – December 2019 $ 2.65 Ceiling sold price (call) 65,000 October 2019 – December 2019 $ 2.96 Floor purchase price (put) 30,000 January 2020 – March 2020 $ 2.72 Ceiling sold price (call) 30,000 January 2020 – March 2020 $ 3.15 Floor purchase price (put) 15,000 April 2020 – June 2020 $ 2.50 Ceiling sold price (call) 15,000 April 2020 – June 2020 $ 2.80 Natural Gas Three-way Collars: Floor purchase price (put) 77,500 April 2019 – December 2019 $ 2.72 Ceiling sold price (call) 77,500 April 2019 – December 2019 $ 3.04 Floor sold price (put) 77,500 April 2019 – December 2019 $ 2.30 Floor purchase price (put) 40,000 April 2019 – June 2019 $ 2.65 Ceiling sold price (call) 40,000 April 2019 – June 2019 $ 2.84 Floor sold price (put) 40,000 April 2019 – June 2019 $ 2.30 Floor purchase price (put) 70,000 January 2020 – June 2020 $ 2.70 Ceiling sold price (call) 70,000 January 2020 – June 2020 $ 2.98 Floor sold price (put) 70,000 January 2020 – June 2020 $ 2.25 Floor purchase price (put) 30,000 October 2019 – June 2020 $ 2.90 Ceiling sold price (call) 30,000 October 2019 – June 2020 $ 3.15 Floor sold price (put) 30,000 October 2019 – June 2020 $ 2.50 Natural Gas Call/Put Options: Call sold 40,000 April 2019 – December 2019 $ 3.44 Basis Swaps: Appalachia - Dominion 12,500 April 2019 – October 2019 $ (0.52 ) Appalachia - Dominion 12,500 April 2020 – October 2020 $ (0.52 ) Appalachia - Dominion 20,000 January 2020 – December 2020 $ (0.59 ) Appalachia - Dominion 17,500 April 2019 – December 2019 $ (0.50 ) Appalachia - Dominion 20,000 April 2019 – March 2020 $ (0.39 ) Oil Derivatives: Description Volume (Bbls/d) Production Period Weighted Average Price Oil Swaps: 1,500 July 2019 – December 2019 $ 59.18 1,000 January 2020 – December 2020 $ 58.60 Oil Collars: Floor purchase price (put) 1,500 July 2019 – December 2019 $ 51.67 Ceiling sold price (call) 1,500 July 2019 – December 2019 $ 65.92 Floor purchase price (put) 500 January 2020 – December 2020 $ 50.00 Ceiling sold price (call) 500 January 2020 – December 2020 $ 64.00 Oil Three-way Collars: Floor purchase price (put) 2,000 April 2019 – December 2019 $ 50.00 Ceiling sold price (call) 2,000 April 2019 – December 2019 $ 60.56 Floor sold price (put) 2,000 April 2019 – December 2019 $ 40.00 Floor purchase price (put) 2,000 January 2020 – June 2020 $ 62.50 Ceiling sold price (call) 2,000 January 2020 – June 2020 $ 74.00 Floor sold price (put) 2,000 January 2020 – June 2020 $ 55.00 NGL Derivatives: Description Volume (Bbls/d) Production Period Weighted Average Price ($/Bbl) Propane Swaps: 350 April 2019 – December 2019 $ 39.90
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, 2019 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 2,416 $ (2,154 ) $ 262 Other current assets Commodity derivatives - noncurrent 1,510 (176 ) 1,334 Other assets Total assets $ 3,926 $ (2,330 ) $ 1,596 Liabilities Commodity derivatives - current $ (6,234 ) $ 2,154 $ (4,080 ) Accrued liabilities Commodity derivatives - noncurrent (972 ) 176 (796 ) Other liabilities Total liabilities $ (7,206 ) $ 2,330 $ (4,876 ) As of December 31, 2018 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 4,960 $ (845 ) $ 4,115 Other current assets Commodity derivatives - noncurrent 1,910 — 1,910 Other assets Total assets $ 6,870 $ (845 ) $ 6,025 Liabilities Commodity derivatives - current $ (845 ) $ 845 $ — Accrued liabilities Commodity derivatives - noncurrent (326 ) — (326 ) Other liabilities Total liabilities $ (1,171 ) $ 845 $ (326 ) (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, 2019 2018 Commodity derivatives Gain (loss) on derivative instruments $ (4,931 ) $ (4,215 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value 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. Level 1 Level 2 Level 3 Total As of March 31, 2019: (in thousands) Commodity derivative instruments $ — $ (3,280 ) $ — $ (3,280 ) Total $ — $ (3,280 ) $ — $ (3,280 ) As of December 31, 2018: (in thousands) Commodity derivative instruments $ — $ 5,699 $ — $ 5,699 Total $ — $ 5,699 $ — $ 5,699

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2019
Schedule of Stock Based Compensation Expense	Our stock-based compensation expense was as follows for the three months ended March 31, 2019 and 2018 (in thousands): Three Months Ended March 31, 2019 2018 Restricted stock units $ 3,147 $ 1,164 Performance units 2,759 728 Restricted stock issued to directors 95 89 Total expense $ 6,001 $ 1,981
Summary of Employee Restricted Stock Unit Awards Activity	A summary of employee restricted stock unit awards activity during the three months ended March 31, 2019 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2018 233,960 $ 29.27 $ 3,685 Granted 70,409 17.55 Vested (198,279 ) 29.28 Forfeited (485 ) 31.78 Total awarded and unvested, March 31, 2019 105,605 $ 21.42 $ 1,588
Summary of Performance Stock Unit Awards Activity	A summary of performance stock unit awards activity during the three months ended March 31, 2019 is as follows Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2018 346,589 $ 27.68 $ 716 Granted — — Vested (265,311 ) 27.54 Forfeited (16,001 ) 24.47 Total awarded and unvested, March 31, 2019 65,277 $ 29.02 $ 1,201
Performance Units [Member]
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: Three Months Ended March 31, 2018 Volatility 89.70 % Risk-free interest rate 2.37 %

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	3 Months Ended
	Mar. 31, 2019
Earnings Per Share [Abstract]
Calculation of Basic and Diluted Weighted-Average Number of Shares of Common Stock and EPS	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, 2019 and 2018: Three Months Ended March 31, (in thousands, except per share data) 2019 2018 Loss Shares Per Share Loss Shares Per Share Basic: Net loss, shares, basic $ (14,098 ) 25,564 $ (0.55 ) $ (2,626 ) 19,563 $ (0.13 ) Weighted-average number of shares of common stock-diluted: Restricted stock and performance unit awards — — — — Diluted: Net loss, shares, diluted $ (14,098 ) 25,564 $ (0.55 ) $ (2,626 ) 19,563 $ (0.13 )

Commitments and Contingencies (

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2019
BRMR and Everest Merger Sub Inc. [Member]
Schedule of Other Commitments Assumed in Relation to Certain Gas Gathering and Processing Agreements	As a result of the BRMR Merger, the Company assumed commitments related to certain gas gathering and processing agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR as shown below (in thousands): Firm transportation (i) Gas processing, gathering, and compression services (ii) Total Year Ending December 31: 2019 $ 14,562 $ 12,873 $ 27,435 2020 19,416 17,133 $ 36,549 2021 19,416 17,087 $ 36,503 2022 19,416 17,087 $ 36,503 2023 18,047 16,561 $ 34,608 Thereafter 92,395 139,545 $ 231,940 Total $ 183,252 $ 220,286 $ 403,538 (i) Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest. (ii) Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements its proportionate share of costs based on the Company’s working interest

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2019USD ($)Segment	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 120,802,000		$ 119,332,000
Capitalized interest expense	$ 700,000	$ 500,000
Number of operating segment | Segment	1
Oil and Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciation, depletion and amortization	$ 29,500,000	30,900,000
Other property and equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciation	$ 400,000	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] | Marcellus Shale [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	9,600,000	$ 6,700,000
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Summary Of Significant Accounting Policies [Line Items]
Fair value of commodity derivative contracts	(3,300,000)		5,700,000
Revenue From Contract With Customer [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	83,200,000		94,100,000
Unbilled Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 83,200,000		$ 94,100,000

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Oil and natural gas properties:
Unproved properties	$ 557,583	$ 482,475
Proved properties	2,511,575	2,188,233
Gross oil and natural gas properties	3,069,158	2,670,708
Less accumulated depreciation, depletion and amortization	(1,409,803)	(1,380,650)
Total oil and natural gas properties, net	1,659,355	1,290,058
Other property and equipment	21,662	14,460
Less accumulated depreciation	(8,516)	(8,160)
Other property and equipment, net	13,146	6,300
Total property and equipment, net	$ 1,672,501	$ 1,296,358

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Summary of Revenue Disaggregated by Type (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation Of Revenue [Line Items]
Total revenues	$ 141,497	$ 110,192
Natural Gas Sales [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	81,825	58,483
NGL Sales [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	21,248	19,743
Oil Sales [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	28,755	31,958
Brokered Natural Gas and Marketing Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	9,530	$ 8
Other Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	$ 139

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Summary for Concentration of Receivables, Net of Allowances, By Product or Service (Detail) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	$ 120,802	$ 119,332
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	83,188	94,107
Product Concentration Risk [Member] | Joint Interest Owners [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	35,559	24,830
Product Concentration Risk [Member] | Derivatives [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	1,878	372
Product Concentration Risk [Member] | Other [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	$ 177	$ 23

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Asset Retirement Obligation [Abstract]
Asset retirement obligations, beginning of period	$ 7,110
Accretion	347
Additional liabilities incurred	49
Obligation for wells acquired	20,188
Liabilities settled via plugging	(26)
Less: current ARO portion (accrued liabilities)	(3,520)
Asset retirement obligations, end of period	$ 24,148

Acquisitions - Additional Infor

Acquisitions - Additional Information (Detail) $ / shares in Units, $ in Thousands	Feb. 28, 2019USD ($)$ / sharesshares	Jan. 18, 2018USD ($)aWellshares	Mar. 31, 2019$ / shares	Dec. 31, 2018$ / shares	Mar. 31, 2018$ / shares	Dec. 31, 2017$ / shares
Business Acquisition [Line Items]
Common stock, par value | $ / shares			$ 0.01	$ 0.01	$ 0.01	$ 0.01
Reverse stock split			0.067
Flat Castle Acquisition [Member]
Business Acquisition [Line Items]
Area of land purchased | a		44,500
Purchase price		$ 90,000
Purchase price paid through shares of common stock | shares		2,500,000
Transaction costs capitalized related to acquisition		$ 1,000
Flat Castle Acquisition [Member] | Proved Oil And Gas Properties [Member]
Business Acquisition [Line Items]
Number of producing wells acquired | Well		1
Purchase price		$ 4,000
Flat Castle Acquisition [Member] | Unproved Oil and Natural Gas Properties [Member]
Business Acquisition [Line Items]
Purchase price		$ 86,000
Cardinal Midstream II, LLC [Member]
Business Acquisition [Line Items]
Third party options exercised month and year				2018-07
BRMR and Everest Merger Sub Inc. [Member]
Business Acquisition [Line Items]
Purchase price	$ 275,759
Common stock, par value | $ / shares	$ 0.01
BRMR and Everest Merger Sub Inc. [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Purchase price paid through shares of common stock | shares	0.29506
Reverse stock split, description			15-to-1
Reverse stock split	0.067

Acquisitions - Summary of Preli

Acquisitions - Summary of Preliminary Purchase Price Allocation and Values of Assets Acquired and Liabilities Assumed (Detail) - BRMR and Everest Merger Sub Inc. [Member] $ in Thousands	Feb. 28, 2019USD ($)
Business Acquisition [Line Items]
Fair value of Montage common stock issued	$ 263,487
Fair value of BRMR share-based and other compensation	12,272
Total Fair Value of Consideration	275,759
Cash and cash equivalents	12,894
Accounts receivable	25,884
Assets held for sale - current	2,296
Other current assets	1,702
Unproved properties	84,742
Proved oil and gas properties	218,866
Other property and equipment	7,059
Other assets	2,461
Operating lease right-of-use asset	7,900
Assets held for sale - long-term	8,505
Total assets acquired	372,309
Accounts payable	(16,571)
Accrued capital expenditures	(5,807)
Accrued liabilities	(31,619)
Operating lease liability - current	(1,977)
Liabilities associated with assets held for sale - current	(7,683)
Asset retirement obligations	(20,188)
Operating lease liability - noncurrent	(5,923)
Liabilities associated with assets held for sale - long-term	(6,782)
Total liabilities assumed	(96,550)
Net identifiable assets	$ 275,759

Acquisitions - Unaudited Pro Fo

Acquisitions - Unaudited Pro Forma Financial Information (Detail) - BRMR and Everest Merger Sub Inc. [Member] - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Business Acquisition [Line Items]
Pro forma total revenues	$ 184,155	$ 133,900
Pro forma net loss from continuing operations	$ (26,760)	$ (4,731)
Pro forma loss per share (basic and diluted)	$ (0.78)	$ (0.28)

Sale of Oil and Natural Gas P_2

Sale of Oil and Natural Gas Property Interests - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018USD ($)a
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 oil and gas property	$ 0
Proceeds from sale of oil and gas property	$ 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 oil and gas property	$ 300,000
Proceeds from sale of oil and gas property	$ 300,000
Area of land | a	50

Assets Held for Sale and Disc_3

Assets Held for Sale and Discontinued Operations - Summary of Assets and Liabilities Held for Sale (Details) $ in Thousands	Mar. 31, 2019USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total current assets held for sale	$ 2,294
Total noncurrent assets held for sale	8,514
Total current liabilities associated with assets held for sale	8,212
Total noncurrent liabilities associated with assets held for sale	6,639
Assets Held for Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	1,797
Other current assets	497
Total current assets held for sale	2,294
Proved oil and gas properties, net	8,270
Other noncurrent assets	244
Total noncurrent assets held for sale	8,514
Accounts payable	2,583
Accrued liabilities	5,312
Other current liabilities	317
Total current liabilities associated with assets held for sale	8,212
Asset retirement obligations	6,029
Other liabilities	610
Total noncurrent liabilities associated with assets held for sale	$ 6,639

Assets Held for Sale and Disc_4

Assets Held for Sale and Discontinued Operations - Summary of Results of Operations for Discontinued Operations (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Discontinued Operations And Disposal Groups [Abstract]
Revenues	$ 949
Depreciation, depletion, amortization and accretion	(52)
Other operating expenses	(1,079)
Loss from discontinued operations, net of tax	(182)
Loss from discontinued operations, net of tax	$ (182)

Assets Held for Sale and Disc_5

Assets Held for Sale and Discontinued Operations - Summary of Operating and Investing Cash Flow of Discontinued Operations (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Discontinued Operations And Disposal Groups [Abstract]
Net cash provided by operating activities	$ 1,046
Net cash provided by investing activities	$ 1

Leases - Additional Information

Leases - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Jan. 01, 2019
Leases [Abstract]
Operating lease right-of-use asset	$ 44,222	$ 10,400
Operating lease liability	45,379	$ 10,400
Operating lease cost	2,300
Operating lease liability current	$ 19,787
Weighted average remaining lease term	3 years 6 months
Weighted average discount cate	5.60%

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	Jan. 01, 2019	Mar. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$ 870
Investing cash flows from operating leases		1,452
ROU assets added in exchange for lease obligations (upon / since adoption)	$ 10,434	27,169
BRMR and Everest Merger Sub Inc. [Member]
Cash paid for amounts included in the measurement of lease liabilities:
ROU assets and lease obligations acquired in BRMR Merger		$ 7,900

Leases - Schedule of Lease Liab

Leases - Schedule of Lease Liabilities (Detail) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019
Operating Leases
Remainder of 2019	$ 16,362
2020	15,132
2021	6,574
2022	4,630
2023	2,467
Thereafter	4,438
Total lease payments	49,603
Less imputed interest	(4,224)
Total lease liability	$ 45,379	$ 10,400

Derivative Instruments - Summar

Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail)	3 Months Ended
	Mar. 31, 2019MMBTU$ / MMBTU$ / bblbbl
Natural Gas Swaps Production Period April 2019 - December 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	90,000
Weighted Average Price | $ / MMBTU	2.84
Natural Gas Swaps Production Period April 2019 - September 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	15,000
Weighted Average Price | $ / MMBTU	2.79
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) | $ / 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) | $ / MMBTU	(0.52)
Basis Swaps Production Period January 2020 – December 2020 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price ($/MMBtu) | $ / MMBTU	(0.59)
Basis Swaps Production Period April 2019 – December 2019 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	17,500
Weighted Average Price ($/MMBtu) | $ / MMBTU	(0.50)
Basis Swaps Production Period April 2019 – March 2020 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price ($/MMBtu) | $ / MMBTU	(0.39)
Natural Gas Collars Production Period April 2019 – June 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	55,000
Weighted Average Price, Floor | $ / MMBTU	2.51
Natural Gas Collars Production Period April 2019 – June 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	55,000
Weighted Average Price, Ceiling | $ / MMBTU	2.81
Natural Gas Collars Production Period July 2019 – September 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	75,000
Weighted Average Price, Floor | $ / MMBTU	2.50
Natural Gas Collars Production Period July 2019 – September 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	75,000
Weighted Average Price, Ceiling | $ / MMBTU	2.87
Natural Gas Three-way Collars Production Period April 2019 – December 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	77,500
Weighted Average Price, Floor | $ / MMBTU	2.72
Natural Gas Three-way Collars Production Period April 2019 – December 2019 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	77,500
Weighted Average Price, Floor | $ / MMBTU	2.30
Natural Gas Three-way Collars Production Period April 2019 – December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	77,500
Weighted Average Price, Ceiling | $ / MMBTU	3.04
Natural Gas Collars Production Period October 2019 – December 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	65,000
Weighted Average Price, Floor | $ / MMBTU	2.65
Natural Gas Collars Production Period October 2019 – December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	65,000
Weighted Average Price, Ceiling | $ / MMBTU	2.96
Natural Gas Collars Production Period January 2020 – March 2020 [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	2.72
Natural Gas Collars Production Period January 2020 – March 2020 [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	3.15
Natural Gas Three-way Collars Production Period April 2019 – June 2019 [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	2.65
Natural Gas Three-way Collars Production Period April 2019 – June 2019 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price, Floor | $ / MMBTU	2.30
Natural Gas Three-way Collars Production Period April 2019 – June 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	40,000
Weighted Average Price, Ceiling | $ / MMBTU	2.84
Natural Gas Collars Production Period April 2020 – June 2020 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	15,000
Weighted Average Price, Floor | $ / MMBTU	2.50
Natural Gas Collars Production Period April 2020 – June 2020 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	15,000
Weighted Average Price, Ceiling | $ / MMBTU	2.80
Natural Gas Three-way Collars Production Period January 2020 – June 2020 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	70,000
Weighted Average Price, Floor | $ / MMBTU	2.70
Natural Gas Three-way Collars Production Period January 2020 – June 2020 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	70,000
Weighted Average Price, Floor | $ / MMBTU	2.25
Natural Gas Three-way Collars Production Period January 2020 – June 2020 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	70,000
Weighted Average Price, Ceiling | $ / MMBTU	2.98
Natural Gas Three-way Collars Production Period October 2019 – June 2020 [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	2.90
Natural Gas Three-way Collars Production Period October 2019 – June 2020 [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 October 2019 – June 2020 [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	3.15
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	40,000
Weighted Average Price | $ / MMBTU	3.44
Oil Swaps Production Period July 2019 – December 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	59.18
Volume (Bbls/d) | bbl	1,500
Oil Swaps Production Period January 2020 – December 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	58.60
Volume (Bbls/d) | bbl	1,000
Oil Collars Production Period July 2019 - December 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	51.67
Volume (Bbls/d) | bbl	1,500
Oil Collars Production Period July 2019 - December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	65.92
Volume (Bbls/d) | bbl	1,500
Oil Collars Production Period January 2020 - December 2020 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	50
Volume (Bbls/d) | bbl	500
Oil Collars Production Period January 2020 - December 2020 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	64
Volume (Bbls/d) | bbl	500
Oil Three-way Collars Production Period April 2019 – December 2019 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	50
Volume (Bbls/d) | bbl	2,000
Oil Three-way Collars Production Period April 2019 – December 2019 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	40
Volume (Bbls/d) | bbl	2,000
Oil Three-way Collars Production Period April 2019 – December 2019 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	60.56
Volume (Bbls/d) | bbl	2,000
Oil Three-way Collars Production Period January 2020 – June 2020 [Member] | Put Option [Member] | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	62.50
Volume (Bbls/d) | bbl	2,000
Oil Three-way Collars Production Period January 2020 – June 2020 [Member] | Put Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	55
Volume (Bbls/d) | bbl	2,000
Oil Three-way Collars Production Period January 2020 – June 2020 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	74
Volume (Bbls/d) | bbl	2,000
Propane Swaps Production Period April 2019 – December 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	39.90
Volume (Bbls/d) | bbl	350

Derivative Instruments - Fair V

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, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Gross Amount		$ 3,926	$ 6,870
Netting Adjustments	[1]	(2,330)	(845)
Net Amount Presented in Balance Sheets		1,596	6,025
Gross Amount		(7,206)	(1,171)
Netting Adjustments	[1]	2,330	845
Net Amount Presented in Balance Sheets		(4,876)	(326)
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		2,416	4,960
Netting Adjustments	[1]	(2,154)	(845)
Net Amount Presented in Balance Sheets		262	4,115
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		1,510	1,910
Netting Adjustments	[1]	(176)
Net Amount Presented in Balance Sheets		1,334	1,910
Current Liabilities [Member] | Accrued Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(6,234)	(845)
Netting Adjustments	[1]	2,154	845
Net Amount Presented in Balance Sheets		(4,080)
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(972)	(326)
Netting Adjustments	[1]	176
Net Amount Presented in Balance Sheets		$ (796)	$ (326)
[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.

Derivative Instruments - Summ_2

Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ (4,931)	$ (4,215)
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Gain (Loss) on Derivative Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ (4,931)	$ (4,215)

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Detail) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	$ (3,280)	$ 5,699
Commodity Derivative Instruments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	(3,280)	5,699
Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	(3,280)	5,699
Level 2 [Member] | Commodity Derivative Instruments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	$ (3,280)	$ 5,699

Debt - Additional Information (

Debt - Additional Information (Detail) - USD ($)

Feb. 28, 2019

Feb. 24, 2017

Feb. 24, 2016

Jul. 06, 2015

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Mar. 31, 2014

May 09, 2019

May 06, 2019

Apr. 01, 2019

Feb. 27, 2019

Aug. 01, 2017

Feb. 23, 2017

Debt Instrument [Line Items]

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 letters of credit

$ 13,500,000

BRMR and Everest Merger Sub Inc. [Member] | Minimum [Member]

Debt Instrument [Line Items]

Ratio of total funded net debt to EBITDAX

400.00%

400.00%

400.00%

400.00%

Subsequent Event [Member]

Debt Instrument [Line Items]

Outstanding letters of credit

$ 15,700,000

Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Revolving credit facility

$ 1,000,000,000

$ 500,000,000

$ 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

$ 375,000,000

$ 225,000,000

$ 125,000,000

Revolving credit facility, extended maturity month and year

2024-02

2020-02

Outstanding borrowings

97,500,000

Available capacity on the Revolving Credit Facility

$ 264,000,000

Percentage of company's proved reserves and guarantees secured by mortgages

85.00%

Revolving Credit Facility [Member] | Minimum [Member]

Debt Instrument [Line Items]

Commitment fees on unused portion of revolving credit facility

0.375%

Revolving Credit Facility [Member] | Maximum [Member]

Debt Instrument [Line Items]

Commitment fees on unused portion of revolving credit facility

0.50%

Revolving Credit Facility [Member] | BRMR and Everest Merger Sub Inc. [Member]

Debt Instrument [Line Items]

Borrowing base

$ 375,000,000

Revolving Credit Facility [Member] | Subsequent Event [Member]

Debt Instrument [Line Items]

Borrowing base

$ 400,000,000

$ 25,000,000

Available capacity on the Revolving Credit Facility

$ 248,300,000

8.875% Senior Unsecured Notes Due 2023 [Member]

Debt Instrument [Line Items]

Issuance date

Jul. 6, 2015

Debt instrument, outstanding principal balance amount

$ 550,000,000

Debt instrument interest rate

8.875%

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

$ 1,000,000

$ 900,000

8.875% Senior Unsecured Notes Due 2023 [Member] | Level 2 [Member]

Debt Instrument [Line Items]

Fair value of senior unsecured notes

$ 486,600,000

Senior PIK Notes [Member]

Debt Instrument [Line Items]

Debt instrument repurchase amount

$ 510,700,000

Benefit Plans - Additional Info

Benefit Plans - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Defined Contribution Plan Disclosure [Line Items]
Matching contribution by the company to the plan	100.00%
Percentage of employees' eligible compensation	6.00%
Plan name	401(k) plan
General and Administrative [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, compensation expense	$ 0.2	$ 0.2

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) $ in Millions	May 16, 2018Directorshares	May 17, 2017Directorshares	Mar. 31, 2019USD ($)shares	Mar. 31, 2018USD ($)
May 2017 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock expense				$ 0.1
May 2018 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock expense			$ 0.1
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 2017 [Member] | Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares of common stock issued | shares		10,212
Number of non employee directors | Director		3
Restricted Stock [Member] | May 2018 [Member] | Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares of common stock issued | shares	15,476
Number of non employee directors | Director	3
Restricted Stock [Member] | May 2018 [Member] | Board of Directors [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost			$ 0.1
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			$ 0.8
Weighted average period for shares to vest			2 years
Performance 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			$ 2
Weighted average period for shares to vest			1 year
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			1,666,667
Number of shares are available for future grants | shares			430,656

Stock-Based Compensation - Sche

Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	$ 6,001	$ 1,981
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	3,147	1,164
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	2,759	728
Restricted Stock Issued to Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	$ 95	$ 89

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Restricted Stock and Employee Restricted Stock Unit Awards Activity (Detail) - Restricted Stock Units [Member] - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, Beginning Balance	233,960
Number of shares, Granted	70,409
Number of shares, Vested	(198,279)
Number of shares, Forfeited	(485)
Number of shares, Ending Balance	105,605
Weighted average grant date fair value, Beginning Balance	$ 29.27
Weighted average grant date fair value, Granted	17.55
Weighted average grant date fair value, Vested	29.28
Weighted average grant date fair value, Forfeited	31.78
Weighted average grant date fair value, Ending Balance	$ 21.42
Aggregate intrinsic value	$ 1,588	$ 3,685

Stock-Based Compensation - Su_2

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, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, Beginning Balance	346,589
Number of shares, Granted	0
Number of shares, Vested	(265,311)
Number of shares, Forfeited	(16,001)
Number of shares, Ending Balance	65,277
Weighted average grant date fair value, Beginning Balance	$ 27.68
Weighted average grant date fair value, Vested	27.54
Weighted average grant date fair value, Forfeited	24.47
Weighted average grant date fair value, Ending Balance	$ 29.02
Aggregate intrinsic value	$ 1,201	$ 716

Stock-Based Compensation - Assu

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

Earnings (Loss) Per Share - Add

Earnings (Loss) Per Share - Additional Information (Detail)	Feb. 28, 2019	Mar. 31, 2019
Business Acquisition [Line Items]
Reverse stock split		0.067
BRMR and Everest Merger Sub Inc. [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Reverse stock split, description		15-to-1
Reverse stock split	0.067

Earnings (Loss) Per Share - Cal

Earnings (Loss) Per Share - Calculation of Basic and Diluted Weighted-Average Number of Shares of Common Stock and EPS (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Basic:
Net loss, basic	$ (14,098)	$ (2,626)
Net loss, shares, basic	25,564	19,563
Net loss, per share, basic	$ (0.55)	$ (0.13)
Diluted:
Net loss, diluted	$ (14,098)	$ (2,626)
Net loss, shares, diluted	25,564	19,563
Net loss, per share, diluted	$ (0.55)	$ (0.13)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Former Chairman, President and Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Flight charter services fees		$ 0.2
Maximum [Member] | Former Chairman, President and Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Flight charter services fees	$ 0.1
EnCap and Affiliates [Member] | Montage Resources Corporation [Member]
Related Party Transaction [Line Items]
Percentage of ownership interest	40.00%

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Other Commitments Assumed in Relation to Certain Gas Gathering and Processing Agreements (Detail) - BRMR and Everest Merger Sub Inc. [Member] $ in Thousands	Mar. 31, 2019USD ($)
Other Commitments [Line Items]
2019	$ 27,435
2020	36,549
2021	36,503
2022	36,503
2023	34,608
Thereafter	231,940
Total	403,538
Firm Transportation [Member]
Other Commitments [Line Items]
2019	14,562	[1]
2020	19,416	[1]
2021	19,416	[1]
2022	19,416	[1]
2023	18,047	[1]
Thereafter	92,395	[1]
Total	183,252	[1]
Gas Processing, Gathering, and Compression Services [Member]
Other Commitments [Line Items]
2019	12,873	[2]
2020	17,133	[2]
2021	17,087	[2]
2022	17,087	[2]
2023	16,561	[2]
Thereafter	139,545	[2]
Total	$ 220,286	[2]
[1]	Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest.
[2]	Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements its proportionate share of costs based on the Company’s working interest

Income Tax - Additional Informa

Income Tax - Additional Information (Detail) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2017
Income Tax [Line Items]
U.S. statutory tax rate	21.00%		35.00%
Scenario, Forecast [Member]
Income Tax [Line Items]
Percentage of annual effective income tax rate		0.00%
Current federal income tax anticipated to be paid		$ 0
Net deferred tax asset		0
Net income tax expense or benefit		$ 0

Subsidiary Guarantors - Additio

Subsidiary Guarantors - Additional Information (Detail)	Mar. 31, 2019	Jul. 06, 2015
8.875% Senior Unsecured Notes Due 2023 [Member]
Guarantee Obligations [Line Items]
Debt instrument interest rate	8.875%	8.875%