Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Mar. 13, 2019 | Jun. 30, 2018 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2018 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | MR | ||
Entity Registrant Name | Montage Resources Corporation | ||
Entity Central Index Key | 0001600470 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | true | ||
Entity Ex Transition Period | true | ||
Entity Shell Company | false | ||
Entity Common Stock, Shares Outstanding | 35,193,719 | ||
Entity Public Float | $ 140 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 5,959 | $ 17,224 |
Accounts receivable | 119,332 | 77,609 |
Assets held for sale | 206 | |
Other current assets | 8,639 | 12,023 |
Total current assets | 133,930 | 107,062 |
Oil and natural gas properties, successful efforts method: | ||
Unproved properties | 482,475 | 459,549 |
Proved oil and gas properties, net | 807,583 | 647,881 |
Other property and equipment, net | 6,300 | 6,942 |
Total property and equipment, net | 1,296,358 | 1,114,372 |
OTHER NONCURRENT ASSETS | ||
Other assets | 3,481 | 2,093 |
TOTAL ASSETS | 1,433,769 | 1,223,527 |
CURRENT LIABILITIES | ||
Accounts payable | 116,735 | 76,174 |
Accrued capital expenditures | 12,979 | 10,658 |
Accrued liabilities | 56,909 | 41,662 |
Accrued interest payable | 21,661 | 21,100 |
Total current liabilities | 208,284 | 149,594 |
NONCURRENT LIABILITIES | ||
Debt, net of unamortized discount and debt issuance costs | 497,778 | 495,021 |
Credit facility | 32,500 | |
Asset retirement obligations | 7,110 | 6,029 |
Other liabilities | 611 | 529 |
Total liabilities | 746,283 | 651,173 |
COMMITMENTS AND CONTINGENCIES | ||
STOCKHOLDERS' EQUITY | ||
Preferred stock, 50,000,000 authorized, no shares issued and outstanding | ||
Common stock, $0.01 par value, 1,000,000,000 authorized, 20,169,063 and 17,516,024 shares issued and outstanding, respectively | 3,043 | 2,637 |
Additional paid in capital | 2,065,119 | 1,967,958 |
Treasury stock, shares at cost; 1,747,624 and 992,315 shares, respectively | (3,357) | (2,096) |
Accumulated deficit | (1,377,319) | (1,396,145) |
Total stockholders' equity | 687,486 | 572,354 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ 1,433,769 | $ 1,223,527 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement Of Financial Position [Abstract] | ||
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 1,000,000,000 | 1,000,000,000 |
Common stock, shares issued | 20,169,063 | 17,516,024 |
Common stock, shares outstanding | 20,169,063 | 17,516,024 |
Treasury stock, shares | 1,747,624 | 992,315 |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
REVENUES | |||
Revenues | $ 515,145 | $ 383,659 | $ 235,034 |
OPERATING EXPENSES | |||
Lease operating | 28,289 | 20,525 | 9,023 |
Production and ad valorem taxes | 10,141 | 8,490 | 7,927 |
Brokered natural gas and marketing expense | 16,886 | 3,191 | 12,268 |
Depreciation, depletion and amortization | 134,277 | 118,818 | 92,948 |
Exploration | 49,563 | 50,208 | 52,775 |
General and administrative | 44,389 | 44,553 | 39,431 |
Rig termination and standby | 1 | 3,846 | |
Impairment of proved oil and gas properties | 17,665 | ||
Accretion of asset retirement obligations | 663 | 544 | 391 |
(Gain) loss on sale of assets | (1,815) | (179) | 6,936 |
Total operating expenses | 421,159 | 370,990 | 352,436 |
OPERATING INCOME (LOSS) | 93,986 | 12,669 | (117,402) |
OTHER INCOME (EXPENSE) | |||
Gain (loss) on derivative instruments | (21,169) | 45,365 | (52,338) |
Interest expense, net | (53,990) | (49,490) | (50,789) |
Gain (loss) on early extinguishment of debt | 14,489 | ||
Other income (expense) | (1) | (19) | (149) |
Total other income (expense), net | (75,160) | (4,144) | (88,787) |
INCOME (LOSS) BEFORE INCOME TAXES | 18,826 | 8,525 | (206,189) |
INCOME TAX BENEFIT (EXPENSE) | (546) | ||
NET INCOME (LOSS) | $ 18,826 | $ 8,525 | $ (206,735) |
NET INCOME (LOSS) PER COMMON SHARE (See Note 11) | |||
Basic | $ 0.94 | $ 0.49 | $ (12.84) |
Diluted | $ 0.94 | $ 0.48 | $ (12.84) |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (See Note 11) | |||
Basic | 19,999 | 17,479 | 16,096 |
Diluted | 20,087 | 17,679 | 16,096 |
Oil and Gas [Member] | |||
REVENUES | |||
Revenues | $ 498,593 | $ 380,178 | $ 223,015 |
Brokered Natural Gas and Marketing Revenue [Member] | |||
REVENUES | |||
Revenues | 16,552 | 3,481 | 12,019 |
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | |||
OPERATING EXPENSES | |||
Transportation, gathering and compression | $ 138,766 | $ 124,839 | $ 109,226 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Total | Public Offering [Member] | Common Stock [Member] | Common Stock [Member]Public Offering [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member]Public Offering [Member] | Treasury Stock [Member] | Accumulated Deficit [Member] |
Beginning Balances at Dec. 31, 2015 | $ 633,374 | $ 2,227 | $ 1,829,082 | $ (1,197,935) | ||||
Beginning Balance, shares at Dec. 31, 2015 | 14,844,951 | |||||||
Stock-based compensation | 6,216 | 6,216 | ||||||
Shares of common stock issued, value | $ 123,813 | $ 375 | $ 123,438 | |||||
Shares of common stock issued, shares | 2,500,000 | |||||||
Issuance of restricted stock | $ 2 | (2) | ||||||
Issuance of restricted stock, shares | 9,963 | |||||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings | (61) | $ 3 | (3) | $ (61) | ||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares | 17,878 | |||||||
Net income (loss) | (206,735) | (206,735) | ||||||
Ending Balances at Dec. 31, 2016 | 556,607 | $ 2,607 | 1,958,731 | (61) | (1,404,670) | |||
Ending Balance, shares at Dec. 31, 2016 | 17,372,793 | |||||||
Stock-based compensation | 9,301 | 9,301 | ||||||
Equity issuance costs | (44) | (44) | ||||||
Issuance of restricted stock | $ 2 | (2) | ||||||
Issuance of restricted stock, shares | 10,213 | |||||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings | (2,035) | $ 28 | (28) | (2,035) | ||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares | 133,018 | |||||||
Net income (loss) | 8,525 | 8,525 | ||||||
Ending Balances at Dec. 31, 2017 | 572,354 | $ 2,637 | 1,967,958 | (2,096) | (1,396,145) | |||
Ending Balance, shares at Dec. 31, 2017 | 17,516,024 | |||||||
Stock-based compensation | 7,891 | 7,891 | ||||||
Equity issuance costs | (344) | (344) | ||||||
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 restricted stock | $ 2 | (2) | ||||||
Issuance of restricted stock, shares | 15,476 | |||||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings | (1,261) | $ 26 | (26) | (1,261) | ||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares | 115,990 | |||||||
Net income (loss) | 18,826 | 18,826 | ||||||
Ending Balances at Dec. 31, 2018 | $ 687,486 | $ 3,043 | $ 2,065,119 | $ (3,357) | $ (1,377,319) | |||
Ending Balance, shares at Dec. 31, 2018 | 20,169,063 |
Consolidated Statements of St_2
Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Statement Of Stockholders Equity [Abstract] | |||
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income (loss) | $ 18,826 | $ 8,525 | $ (206,735) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities | |||
Depreciation, depletion and amortization | 134,277 | 118,818 | 92,948 |
Exploration expense | 28,324 | 31,417 | 30,853 |
Stock-based compensation | 7,891 | 9,301 | 6,216 |
Impairment of proved oil and gas properties | 17,665 | ||
Accretion of asset retirement obligations | 663 | 544 | 391 |
(Gain) loss on derivative instruments | 21,169 | (45,365) | 52,338 |
Net cash receipts (payments) on settled derivatives | (26,985) | (2,224) | 38,696 |
(Gain) loss on sale of assets | (1,815) | (179) | 6,936 |
(Gain) loss on early extinguishment of debt | (14,489) | ||
Deferred income taxes | 540 | ||
Amortization of deferred financing costs | 2,256 | 2,098 | 1,962 |
Amortization of debt discount | 1,327 | 1,324 | 1,362 |
Changes in operating assets and liabilities: | |||
Accounts receivable | (42,879) | (31,780) | (21,277) |
Other assets | (2,192) | 1,863 | (1,795) |
Accounts payable and accrued liabilities | 84,231 | 18,404 | 794 |
Net cash provided by operating activities | 225,093 | 112,746 | 6,405 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Capital expenditures for oil and gas properties | (275,601) | (291,779) | (167,355) |
Capital expenditures for other property and equipment | (1,007) | (2,007) | (1,164) |
Proceeds from sale of assets | 10,358 | 1,317 | 79,201 |
Net cash used in investing activities | (266,250) | (292,469) | (89,318) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Debt issuance costs | (497) | (1,750) | 30 |
Repayments of long-term debt | (506) | (453) | (24,045) |
Proceeds from issuance of common stock | 124,361 | ||
Proceeds from credit facility | 32,500 | ||
Equity issuance costs | (344) | (44) | (548) |
Employee tax withholding for settlement of equity compensation awards | (1,261) | (2,035) | (61) |
Net cash provided by (used in) financing activities | 29,892 | (4,282) | 99,737 |
Net increase (decrease) in cash and cash equivalents | (11,265) | (184,005) | 16,824 |
Cash and cash equivalents at beginning of period | 17,224 | 201,229 | 184,405 |
Cash and cash equivalents at end of period | 5,959 | 17,224 | 201,229 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | |||
Cash paid for interest | 51,101 | 47,362 | 48,483 |
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES | |||
Asset retirement obligations incurred, including changes in estimate | 418 | 679 | 1,014 |
Additions of other property through debt financing | 173 | 183 | |
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures | (15,269) | 22,264 | $ 8,583 |
Assets held for sale | $ (262) | ||
Asset acquisition through stock issuance | $ 90,020 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2018 | |
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. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 2—Summary of Significant Accounting Policies (a) Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2018 and 2017, and the results of its operations, comprehensive income (loss) and its cash flows for the years ended December 31, 2018, 2017, and 2016. (b) 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. (c) 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 party. The Company did not deem any of its accounts receivables to be uncollectable as of December 31, 2018 or December 31, 2017. 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, which are, in turn, based upon applicable product prices. The Company had $94.1 million and $52.9 million of accrued revenues, net of expenses at December 31, 2018 and December 31, 2017, respectively, which were included in accounts receivable within the Company’s consolidated balance sheets. (d) Property and Equipment Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “ Depreciation, Depletion and Amortization 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 consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s 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 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): December 31, 2018 December 31, 2017 Oil and natural gas properties: Unproved $ 482,475 $ 459,549 Proved 2,188,233 1,896,081 Gross oil and natural gas properties 2,670,708 2,355,630 Less accumulated depreciation, depletion and amortization (1,380,650 ) (1,248,200 ) Oil and natural gas properties, net 1,290,058 1,107,430 Other property and equipment 14,460 13,508 Less accumulated depreciation (8,160 ) (6,566 ) Other property and equipment, net 6,300 6,942 Property and equipment, net $ 1,296,358 $ 1,114,372 Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. The Company capitalized interest expense totaling $1.7 million, $2.3 million and $1.1 million for the years ended December 31, 2018, 2017, and 2016, respectively. Other Property and Equipment Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. (e) Accounts Payable and Accrued Liabilities A summary of accounts payable is as follows (in thousands): December 31, 2018 December 31, 2017 Trade payables $ 27,481 $ 44,516 Royalty payables 70,019 17,483 Production & ad valorem taxes 1,811 967 Derivative payable 4,736 941 Other payables 12,688 12,267 Total accounts payable $ 116,735 $ 76,174 A summary of accrued liabilities is as follows (in thousands): December 31, 2018 December 31, 2017 Ad valorem and production taxes $ 6,193 $ 4,299 Employee compensation 6,595 8,667 Royalties 39,969 9,660 Short term derivatives — 14,875 Other 4,152 4,161 Total accrued liabilities $ 56,909 $ 41,662 (f) 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. 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 periods indicated: For the Year Ended December 31, 2018 2017 2016 Revenues (in thousands) Natural gas sales $ 274,239 $ 241,379 $ 134,618 NGL sales 86,152 64,109 38,204 Oil sales 138,202 74,690 50,193 Brokered natural gas and marketing revenue 16,552 3,481 12,019 Total revenues $ 515,145 $ 383,659 $ 235,034 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 $94.1 million and $52.9 million at December 31, 2018 and December 31, 2017, respectively. (g) Major Customers The Company sells production volumes to various purchasers. For the years ended December 31, 2018, 2017, and 2016, there were one, two and four customers, respectively, that accounted for 10% or more of the total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the Year Ended December 31, 2018 2017 2016 Purchaser Antero Resources — — 14% Concord Energy — — 12% Emera Energy Services — 17% — EnLink Midstream — — 17% Marathon Petroleum 25% 10% — Sequent Energy Management — — 20% Total 25% 27% 63% Management believes that the loss of any one customer would not have a material adverse effect on the Company’s ability to sell natural gas, NGLs and oil production because it believes that there are potential alternative purchasers although it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers. (h) Concentration of Credit Risk The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2018 and December 31, 2017 (in thousands): December 31, 2018 December 31, 2017 Receivables by product or service: Sale of oil and natural gas and related products and services $ 94,107 $ 52,908 Joint interest owners 24,830 23,154 Derivatives 372 1,528 Other 23 19 Total $ 119,332 $ 77,609 Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy 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 commodity unsettled derivative contracts was a net asset position of $5.7 million and a net liability position of ($5.1) million at December 31, 2018 and 2017, respectively. Other than, as provided by the 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 they required to provide credit support to the Company. As of December 31, 2018, the Company did not have past-due receivables from or payables to any of the counterparties. (i) Depreciation, Depletion and Amortization Oil and Natural Gas Properties Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties for the years ended December 31, 2018, 2017, and 2016 totaled approximately $132.5 million, $116.8 million and $91.0 million, respectively. Other Property and Equipment Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the years ended December 31, 2018, 2017, and 2016 totaled approximately $1.8 million, $2.0 million and $1.9 million, respectively. This amount is included in DD&A expense in the consolidated statements of operations. (j) 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 of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the year ended December 31, 2016 relating to proved properties in the Marcellus Shale. The aforementioned impairment charges represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $27.6 million, $28.3 million, and $29.8 million for the years ended December 31, 2018, 2017, and 2016, respectively. These costs are included in exploration expense in the consolidated statements of operations. (k) Income Taxes The Company accounts for income taxes, as required, under the liability method. 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 “ Income Taxes ” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date. (l) 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 date 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. (m) 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 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 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 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. (n) Asset Retirement Obligation The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 410, “Asset , 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 periods indicated (in thousands): For the Year Ended December 31, 2018 2017 2016 Asset retirement obligations, beginning of period $ 6,029 $ 4,806 $ 3,401 Additional liabilities incurred 418 679 1,014 Accretion 663 544 391 Asset retirement obligations, end of period $ 7,110 $ 6,029 $ 4,806 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. (o) Lease Obligations The Company leases office space under an operating lease that expires in 2024. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception. (p) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. (q) 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. (r) 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. (s) Recent Accounting Pronouncements Recently Adopted In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted this standard effective January 1, 2018 using the modified retrospective method. The Company did not recognize a significant impact on its financial position or results of operations. Upon adoption of this new standard, the Company did not record a cumulative effect adjustment nor did the Company alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify the impact of future revenue contracts entered into by the Company. Additional disclosures have been included to provide further detail regarding the Company’s revenue recognition policies. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company adopted this standard effective January 1, 2018 and did not recognize a significant impact on its financial position, results of operations, or statement of cash flows. In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” Currently under the standard, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company adopted this standard effective January 1, 2018 and considered the new guidance in its assessment of the accounting treatment for the Flat Castle Acquisition. (See Note 3— Acquisition Accounting Pronouncements Not Yet Adopted In February 2016, the FASB issued Update 2016-02, “Leases (Topic 842)”, which increases transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 maintains a distinction between finance leases and operating leases, which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease to remain similar to the previous accounting treatment. A lessee is permitted to make an accounting policy election by class of underlying asset to exclude from balance sheet recognition any lease assets and lease liabilities with a term of 12 months or less, and instead to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the ROU asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position. For public business entities, the amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach with the option to adopt certain practical expedients. In July 2018, the FASB issued Update 2018-11 which provides entities with the option to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company will adopt Topic 842 guidance as of January 1, 2019 usin |
Acquisition
Acquisition | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Acquisition | Note 3—Acquisition 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 Flat Castle area to a third party. The third party exercised its option 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 11— Earnings (Loss) Per Share ) Due to the BRMR Merger closing subsequent to the year ended December 31, 2018, the initial accounting for the acquisition will be accounted for in the period it closed and the Company is in the process of determining the fair values of the net assets acquired. |
Sale of Oil and Natural Gas Pro
Sale of Oil and Natural Gas Property Interests | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations And Disposal Groups [Abstract] | |
Sale of Oil and Natural Gas Property Interests | Note 4—Sale of Oil and Natural Gas Property Interests Asset Sales During the year ended December 31, 2016, the Company completed the sale of its Conventional oil and gas properties and related equipment for approximately $4.7 million. As of December 31, 2015, the Company was actively negotiating the sale of these assets and the costs related to these properties of approximately $21.8 million and corresponding asset retirement obligations of approximately $19.1 million were classified as held for sale in the consolidated balance sheets as of December 31, 2015. As a result of this sale, the Company recognized a gain of approximately $1.1 million. During the year ended December 31, 2016, the Company sold additional pipeline assets, which resulted in proceeds of approximately $0.4 million and a loss of less than $0.1 million. During the year ended December 31, 2016, the Company received $3.9 million from the sale of mineral interests related primarily to unproved properties to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and gas properties. During the year ended December 31, 2016, the Company received $4.8 million from the sale of unproved leases to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and gas properties. During the year ended December 31, 2016, the Company received approximately $63.8 million from a completed asset sale with a third party totaling approximately 9,900 acres. As a result of this sale, the Company recognized a loss of approximately $7.6 million. During the year ended December 31, 2017, the Company received approximately $0.5 million from a completed asset sale with a third party totaling approximately 100 acres. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties. During the year ended December 31, 2017, the Company received approximately $0.8 million from a completed asset sale with a third party totaling approximately 150 acres. As a result of this sale, the Company recognized a gain of approximately $0.2 million. During the year ended December 31, 2018, the Company received approximately $6.0 million from a completed asset sale of approximately 1,000 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $1.5 million. During the year ended December 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 year ended December 31, 2018, the Company received approximately $0.3 million from a 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. During the year ended December 31, 2018, the Company sold the $0.2 million of pipeline assets. As a result of this sale, the Company recognized a loss of less than approximately $0.1 million. These pipeline assets were classified as held for sale on the consolidated balance sheets as of December 31, 2015. Acreage Trades During the year ended December 31, 2016, the Company received approximately $1.6 million from completed acreage trades with various working interest owners totaling approximately 249.5 acres. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and gas properties. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Note 5—Derivative Instruments Commodity derivatives The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes. The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of December 31, 2018, the Company’s derivative instruments were with Bank of Montreal, KeyBank, N.A, Morgan Stanley, Capital One N.A., BP Energy Company and Goldman Sachs. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of December 31, 2018, for future production periods: Natural Gas Derivatives Description Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Swaps: 30,000 January 2019 – March 2019 $ 2.90 90,000 January 2019 – December 2019 $ 2.84 Natural Gas Collars: Ceiling sold price (call) 30,000 October 2019 – December 2019 $ 2.95 Floor sold price (put) 30,000 October 2019 – December 2019 $ 2.65 Natural Gas Three-way Collars: Floor purchase price (put) 30,000 January 2019 – March 2019 $ 3.00 Ceiling sold price (call) 30,000 January 2019 – March 2019 $ 3.40 Floor sold price (put) 30,000 January 2019 – March 2019 $ 2.50 Floor purchase price (put) 77,500 January 2019 – December 2019 $ 2.72 Ceiling sold price (call) 77,500 January 2019 – December 2019 $ 3.04 Floor sold price (put) 77,500 January 2019 – December 2019 $ 2.30 Floor purchase price (put) 50,000 January 2020 – June 2020 $ 2.70 Ceiling sold price (call) 50,000 January 2020 – June 2020 $ 2.95 Floor sold price (put) 50,000 January 2020 – June 2020 $ 2.25 Natural Gas Call/Put Options: Call sold 30,000 January 2019 – March 2019 $ 3.50 Call sold 30,000 April 2019 – December 2019 $ 3.00 Call sold 10,000 January 2019 – December 2019 $ 4.75 Basis Swaps: Appalachia - Dominion 12,500 April 2019 – October 2019 $ (0.52 ) Appalachia - Dominion 12,500 April 2020 – October 2020 $ (0.52 ) Appalachia - Dominion 20,000 January 2020 – December 2020 $ (0.59 ) Oil Derivatives Description Volume (Bbls/d) Production Period Weighted Price Oil Swaps: 1,000 January 2019 – March 2019 $ 61.00 Oil Three-way Collars: Floor purchase price (put) 2,000 January 2019 – December 2019 $ 50.00 Ceiling sold price (call) 2,000 January 2019 – December 2019 $ 60.56 Floor sold price (put) 2,000 January 2019 – December 2019 $ 40.00 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 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 consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes. 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 ) As of December 31, 2017 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 15,971 $ (6,380 ) $ 9,591 Other current assets Commodity derivatives - noncurrent 469 (176 ) 293 Other assets Total assets $ 16,440 $ (6,556 ) $ 9,884 Liabilities Commodity derivatives - current $ (21,256 ) $ 6,380 $ (14,876 ) Accrued liabilities Commodity derivatives - noncurrent (252 ) 176 (76 ) Other liabilities Total liabilities $ (21,508 ) $ 6,556 $ (14,952 ) (a) The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the consolidated statements of operations for the periods presented (in thousands): For the Year Ended December 31, Location of Gain (Loss) 2018 2017 2016 Commodity derivatives Gain (loss) on derivative instruments $ (21,169 ) $ 45,365 $ (52,338 ) |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 6—Fair Value Measurements Fair Value Measurement on a Recurring Basis The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the 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 forward curves. These values are compared to the values given by counterparties for reasonableness. Since natural gas swaps 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 December 31, 2018: (in thousands) Commodity derivative instruments $ — $ 5,699 $ — $ 5,699 Total $ — $ 5,699 $ — $ 5,699 As of December 31, 2017: (in thousands) Commodity derivative instruments $ — $ (5,068 ) $ — $ (5,068 ) Total $ — $ (5,068 ) $ — $ (5,068 ) Nonfinancial Assets and Liabilities Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 2(n)). The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 2(l)). The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 7— Debt |
Debt
Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Note 7—Debt 8.875% Senior Unsecured Notes Due 2023 On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% Senior Unsecured Notes due 2023 at an issue price of 97.903% of 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 of the United States in compliance with Rule 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 offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding 12.0% Senior PIK notes. The Company used the remaining proceeds to fund its capital expenditure plan and for general corporate purposes. During the years ended December 31, 2018, 2017, and 2016, the Company amortized $3.6 million, $3.4 million and $3.3 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 December 31, 2018. During the year ended December 31, 2016, the Company repurchased $39.5 million of the outstanding senior unsecured notes in open market purchases for $23.4 million. The principal of the outstanding senior unsecured notes that were repurchased less cash proceeds and unamortized debt discount and deferred financing costs were charged to gain on early extinguishment of debt, totaling $14.5 million for the year ended December 31, 2016. The Company repurchased all such senior unsecured notes with cash on hand. Based on Level 2 market data inputs, the fair value of the senior unsecured notes at December 31, 2018 was approximately $437.9 million. Revolving Credit Facility During the first quarter of 2014, the Company entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that 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 revolving credit facility was amended and restated on January 12, 2015. The primary change effected by the 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 the 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 its revolving credit facility to, among other things, adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense, and to permit the sale of certain conventional properties. The amendment to the revolving credit facility 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 the amendment, execute and deliver additional mortgages on the oil and gas properties that include at least 90% of the proved reserves. On February 24, 2017, the Company entered into an additional amendment that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020. In addition, the amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Net Debt to EBITDAX. On August 1, 2017, the Company entered into an additional amendment that increased the borrowing base from $175 million to $225 million. At December 31, 2018, the borrowing base was $225 million and the Company had $32.5 million in outstanding borrowings. After giving effect to outstanding letters of credit issued by the Company totaling $27.0 million, the Company had available borrowing capacity under the revolving credit facility of $165.5 million. On February 28, 2019, the Company amended and restated the credit agreement governing its revolving credit facility to, among other things, increase the borrowing base from $225 million to $375 million and extend the maturity date thereof to approximately five years after the closing of the BRMR Merger. 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 amended and restated 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. Subsequent to December 31, 2018, the Company reduced its outstanding letters of credit to approximately $13.5 million. Further, the Company borrowed an incremental $85 million under its revolving credit facility, which reduced the available borrowing capacity to $244 million. The revolving credit facility is secured by mortgages on 85% of the value of the Company’s properties and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and leverage 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 December 31, 2018. 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 | 12 Months Ended |
Dec. 31, 2018 | |
Compensation And Retirement Disclosure [Abstract] | |
Benefit Plans | Note 8—Benefit Plans Defined Contribution Plan The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense of $0.9 million, $0.7 million and $0.7 million related to matching contributions, classified under general and administrative in the consolidated statements of operations, for the years ended December 31, 2018, 2017, and 2016, respectively. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Stock-Based Compensation | Note 9—Stock-Based Compensation The Company is authorized to grant up to 25,000,000 shares of common stock under its 2014 Long-Term Incentive Plan (as amended, the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 7,145,866 shares are available for future grant under the Plan as of December 31, 2018. The foregoing share numbers provided as of December 31, 2018 do not reflect any adjustment with respect to the 15-to-1 reverse stock split that occurred on February 28, 2019. Our stock based compensation expense is as follows for the years ended December 31, 2018, 2017, and 2016 (in thousands): Year Ended December 31, 2018 2017 2016 Restricted stock units $ 4,014 $ 5,301 $ 4,006 Performance units 3,497 3,622 1,922 Restricted stock issued to directors 380 378 556 Incentive units — — (268 ) Total expense $ 7,891 $ 9,301 $ 6,216 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 December 31, 2018, there was $4.0 million of total unrecognized compensation cost related to restricted stock units. The weighted average period for the shares to vest is approximately 1 year. A summary of employee restricted stock unit awards activity during the year ended December 31, 2018 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2017 270,490 $ 37.20 $ 9,738 Granted 99,901 25.50 Vested (132,406 ) 42.42 Forfeited (4,025 ) 31.30 Total awarded and unvested, December 31, 2018 233,960 $ 29.27 $ 3,685 Performance Units Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of December 31, 2018, there was $3.5 million of total unrecognized compensation cost related to performance units. The weighted average period for the shares to vest is approximately 1 years. A summary of performance stock unit awards activity during the year ended December 31, 2018 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2017 264,425 $ 27.30 $ 11,257 Granted 99,901 28.80 Vested (11,536 ) 27.51 Forfeited (6,201 ) 27.61 Total awarded and unvested, December 31, 2018 346,589 $ 27.68 $ 716 The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s public peer group. The following table presents the assumptions used to determine the fair value for performance stock units granted during the years ended December 31, 2018, 2017, and 2016: Year Ended December 31, 2018 2017 2016 Volatility 89.70 % 50.41 % 49.84 % Risk-free interest rate 2.37 % 1.34 % 0.96 % The fair value of the performance stock units vested during the year ended December 31, 2017 was approximately $0.8 million. Restricted Stock Issued to Directors On May 11, 2015, the Company issued an aggregate of 8,833 restricted shares of common stock to its seven non-employee members of its Board of Directors, which became fully vested on May 11, 2016. For the year ended December 31, 2016, the Company recognized expense of approximately $0.3 million related to these awards. On May 18, 2016, the Company issued an aggregate of 9,963 restricted shares of common stock to its three non-employee members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which became fully vested on May 18, 2017. For the years ended December 31, 2017 and 2016, the Company recognized expense of approximately $0.2 million and $0.3 million, respectively, related to these awards. 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 years ended December 31, 2017 and 2018, the Company recognized expense of approximately $0.2 million and $0.1 million, respectively, 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 year ended December 31, 2018, the Company recognized expense of approximately $0.3 million related to these awards. As of December 31, 2018, there was approximately $ 0.1 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s Directors. |
Equity
Equity | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
Equity | Note 10—Equity Public Offering of Common Stock On June 28, 2016, the Company commenced an underwritten public offering of 2,500,000 shares of common stock, which was priced at $52.50 per share. The Company closed the offering on July 5, 2016 and received net proceeds of approximately $123.8 million (after deducting underwriting discounts and commissions and estimated expenses), which the Company used to fund its capital expenditure plan and for general corporate purposes. |
Earnings (Loss) Per Share
Earnings (Loss) Per Share | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Earnings (Loss) Per Share | Note 11—Earnings (Loss) Per Share Earnings (Loss) Per Share Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive. Reverse Stock Split Effective immediately prior to the Effective Time (See Note 3— Acquisition ), the Company effected a 15-to-1 reverse stock split of its common stock. . The below table retroactively reflects, in accordance with ASC 505 “Equity”, the stock split that occurred after the year ended December 31, 2018 for the years ended December 31, 2018, 2017, and 2016, respectively: Year Ended December 31, (in thousands, except per share data) 2018 2017 2016 Income (Loss) Shares Per Share Income (Loss) Shares Per Share Income (Loss) Shares Per Share Basic: Net income (loss), shares, basic $ 18,826 19,999 $ 0.94 $ 8,525 17,479 $ 0.49 $ (206,735 ) 16,096 $ (12.84 ) Weighted-average number of shares of common stock-diluted: Restricted stock and performance unit awards — 88 — 200 — — Diluted: Net income (loss), shares, diluted $ 18,826 20,087 $ 0.94 $ 8,525 17,679 $ 0.48 $ (206,735 ) 16,096 $ (12.84 ) |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 12—Related Party Transactions During the years ended December 31, 2018, 2017, and 2016, the Company incurred approximately $0.6 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 a majority of the outstanding shares of the Company’s common stock. (See Note 3— Acquisition ). |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 13—Commitments and Contingencies (a) Legal Matters From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings. (b) Environmental Matters The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected. (c) Leases The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties. The Company leases office space under an operating lease that expires in 2024. Rent expense related to lease agreements for the years ended December 31, 2018, 2017, and 2016 was $0.6 million, $0.6 million and $0.9 million, respectively. The following is a schedule by year, of the future minimum lease payments required under the lease agreements as of December 31, 2018 (in thousands). 2019 1,360 2020 1,060 2021 929 2022 755 2023 755 Thereafter 1,619 Total minimum lease payments $ 6,478 (d) Other Commitments (in thousands) Drilling rig commitments (i) Firm transportation (ii) Gas processing, gathering, and compression services (iii) Total Year Ending December 31: 2019 $ 1,287 $ 80,083 $ 26,271 $ 107,641 2020 — 80,303 22,886 103,189 2021 — 80,083 18,147 98,230 2022 — 80,083 20,440 100,523 2023 — 80,083 18,515 98,598 Thereafter — 700,549 61,923 762,472 Total $ 1,287 $ 1,101,184 $ 168,182 $ 1,270,653 (i) Drilling rig commitments - The Company had contracts for the service of two rigs, which have both expired and the Company has entered into well-to-well contracts. 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, as applicable. (ii) 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. (iii) 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 | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Note 14—Income Tax For the year ended December 31, 2018, the Company’s annual effective tax rate is approximately 0.0%. Despite reporting pre-tax book income of $18.8 million, the Company incurred a tax loss in the current year (due principally to intangible drilling cost amortization) and thus, no current federal income taxes will be due. This tax loss results in a net operating loss carryforward at December 31, 2018 in the amount of $667 million. Management assessed the realizability of the Company’s deferred tax assets based on the more likely than not standard. Management considered several factors such as: (i) the Company’s short (five-year) tax history, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net federal tax attribute carryforwards are realizable. As such, the Company has provided a valuation allowance of $208 million as of December 31, 2018. For the Year Ended December 31, 2018 2017 2016 Current Federal $ — $ — $ — State — — 6 Total current — — 6 Deferred Federal — — — State — — 540 Total deferred — — 540 Total income tax expense (benefit) $ — $ — $ 546 The Company’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items (in thousands): For the Year Ended December 31, 2018 2017 2016 Income (loss) before income taxes $ 18,826 $ 8,525 $ (206,189 ) Statutory rate 21 % 35 % 35 % Income tax benefit computed at statutory rate 3,953 2,984 (72,166 ) Reconciling items: State income taxes — — 546 Other, net 54 50 854 Share-based compensation 1,201 (576 ) — Executive compensation limitation 268 496 — Change in valuation allowance (5,476 ) (145,449 ) 71,312 Change in Federal tax rate — 142,495 — Income tax expense (benefit) $ — $ — $ 546 Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Company’s deferred taxes are detailed in the table below (in thousands): For the Year Ended December 31, 2018 2017 2016 Deferred tax asset: Oil and gas properties and equipment $ 62,616 $ 93,854 $ 193,095 Federal tax loss carryforwards 140,059 114,652 145,628 Derivative instruments and other — 1,064 16,829 State effect of deferreds — — — Other, net 7,398 4,639 4,259 Deferred tax asset 210,073 214,209 359,811 Valuation allowance (208,324 ) (213,800 ) (359,098 ) Net deferred tax assets $ 1,749 $ 409 $ 713 Deferred tax liability: Derivative instruments and other $ 1,197 $ — $ — Other, net 552 409 713 Net deferred tax liability $ 1,749 $ 409 $ 713 Reflected in the accompanying consolidated balance sheet as: Net deferred tax asset $ — $ — $ — Net deferred tax liability $ — $ — $ — The Company has U.S. federal tax loss carryforwards (“NOL”) of approximately $667 million as of December 31, 2018. The NOL carryforwards will begin to expire in 2034. The tax years ended December 31, 2015 through 2018 will remain open to examination under the applicable statute of limitations in the U.S. and other jurisdictions in which the Company and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not commence until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. As of December 31, 2018, 2017, and 2016 the Company has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods. As a result of the BRMR Merger (See Note 3— Acquisition |
Subsidiary Guarantors
Subsidiary Guarantors | 12 Months Ended |
Dec. 31, 2018 | |
Text Block [Abstract] | |
Subsidiary Guarantors | Note 15—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 expects to cause BRMR and each of its subsidiaries that guarantees the Company’s revolving credit facility to guarantee the Company’s 8.875% Senior Unsecured Notes (See Note 7— 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. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 16—Subsequent Events Management has evaluated subsequent events and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures, except for analysis on Topic 842 related to the BRMR Merger (See Note 2— Summary of Significant Accounting Policies Acquisition Debt Earnings (Loss) Per Share |
Quarterly Financial Information
Quarterly Financial Information (unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Information (unaudited) | Note 17—Quarterly Financial Information (unaudited) Summarized quarterly financial data for the years ended December 31, 2018 and 2017 are presented in the following table to retroactively reflect the 15-to-1 reverse stock split at the close the BRMR Merger. In the following table, the sum of basic and diluted “Income (loss) per common share” for the four quarters may differ from the annual amounts due to the required method of computing weighted average number of shares in the respective periods. Additionally, due to the effect of rounding, the sum of the individual quarterly loss per share amounts may not equal the calculated year loss per share amount (in thousands, except per share data). First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2018 Total operating revenues $ 110,192 $ 103,622 $ 130,123 $ 171,208 Total operating expenses 95,651 92,989 108,929 123,590 Operating income (loss) 14,541 10,633 21,194 47,618 Net income (loss) (2,626 ) (19,036 ) 3,998 36,490 Income (loss) per common share: Basic $ (0.13 ) $ (0.95 ) $ 0.20 $ 1.81 Diluted $ (0.13 ) $ (0.95 ) $ 0.20 $ 1.80 First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2017 Total operating revenues $ 101,863 $ 86,191 $ 91,549 $ 104,056 Total operating expenses 87,632 80,589 94,338 108,431 Operating loss 14,231 5,602 (2,789 ) (4,375 ) Net income (loss) 26,847 11,494 (16,694 ) (13,122 ) Income (loss) per common share: Basic $ 1.54 $ 0.66 $ (0.95 ) $ (0.75 ) Diluted $ 1.52 $ 0.65 $ (0.95 ) $ (0.74 ) |
Supplemental Oil and Natural Ga
Supplemental Oil and Natural Gas Information (unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Text Block [Abstract] | |
Supplemental Oil and Natural Gas Information (unaudited) | Note 18—Supplemental Oil and Natural Gas Information (unaudited) (a) Capitalized Costs A summary of the Company’s capitalized costs are contained in the table below (in thousands): December 31, 2018 2017 Oil and natural gas properties: Unproved properties $ 482,475 $ 459,549 Proved properties 2,188,233 1,896,081 Total oil and natural gas properties 2,670,708 2,355,630 Less accumulated depreciation, depletion and amortization (1,380,650 ) (1,248,200 ) Net oil and natural gas properties $ 1,290,058 $ 1,107,430 (b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands): December 31, 2018 2017 2016 Acquisition costs: Unproved properties $ 107,862 $ 57,498 $ 24,764 Proved properties 4,072 — — Development cost 239,467 257,119 150,778 Exploration cost 20,957 18,791 20,127 Total acquisition, development and exploration costs $ 372,358 $ 333,408 $ 195,669 (c) Reserve Quantity Information The following information represents estimates of the Company’s proved reserves as of December 31, 2018 and December 31, 2017, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2018, 2017, and 2016 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs and a Henry Hub spot natural gas price per MMBtu for natural gas. Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Appalachian Basin of Ohio and Pennsylvania. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more. The Company’s proved oil and natural gas reserves are all located in the United States, within the States of Ohio and Pennsylvania. All of the estimates of the proved reserves at December 31, 2018 and December 31, 2017 and 2016, were prepared by SIS and NSAI, our independent petroleum engineers, respectively. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB. Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2018, 2017, and 2016 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Natural Gas (Bcf) Natural Gas Liquids (MBbl) Oil (MBbl) TOTAL (Bcfe) End of year, December 31, 2015 274.1 7,758.7 4,693.1 348.8 Revisions (0.1 ) 1,273.7 1,196.8 14.8 Extensions and discoveries 175.4 2,156.0 1,300.2 196.1 Acquisitions 3.8 24.8 15.1 4.1 Divestitures (5.9 ) (91.5 ) (703.7 ) (10.7 ) Production (60.9 ) (2,446.2 ) (1,343.8 ) (83.7 ) End of year, December 31, 2016 386.4 8,675.5 5,157.7 469.4 Revisions 515.1 20,327.3 9,746.8 695.6 Extensions and discoveries 274.4 15,598.8 6,192.9 405.1 Acquisitions 1.6 42.6 5.8 1.9 Production (87.4 ) (2,713.6 ) (1,622.4 ) (113.4 ) End of year, December 31, 2017 1,090.1 41,930.6 19,480.8 1,458.6 Revisions 5.6 (8,307.5 ) 231.2 (42.8 ) Extensions and discoveries 515.8 4,059.4 2,995.7 558.1 Acquisitions 9.9 551 522 16.3 Divestitures (0.2 ) — — (0.2 ) Production (90.0 ) (3,503.0 ) (2,377.8 ) (125.3 ) End of year, December 31, 2018 1,531.2 34,730.9 20,852.1 1,864.7 Proved developed reserves: December 31, 2015 209.5 7,245.7 4,239.2 278.4 December 31, 2016 226.1 7,520.0 4,439.5 297.8 December 31, 2017 334.6 13,782.9 6,449.6 456.0 December 31, 2018 501.0 20,213.8 8,058.7 670.7 Proved undeveloped reserves: December 31, 2015 64.5 513.0 453.9 70.3 December 31, 2016 160.4 1,155.5 718.1 171.6 December 31, 2017 755.5 28,147.7 13,031.2 1,002.6 December 31, 2018 1,030.2 14,517.2 12,793.4 1,194.1 2016 Changes in Reserves • Extensions of 196.1 Bcfe primarily from the development of the Company’s Utica asset. • Positive revisions of 14.8 Bcfe as a result of a negative revision of 50.8 Bcfe due to reductions in SEC pricing and a negative revision of 17.9 Bcfe due to changes in differentials. This was offset by a positive revision of 83.5 Bcfe primarily driven by proved developed producing wells in aggregate outperforming the previous estimate. • 4.1 • 10.7 2017 Changes in Reserves • Extensions of 405.1 Bcfe primarily from 361.0 Bcfe of development of the Company’s operated Utica asset. The Company also added 0.3 Bcfe from one non-operated Utica well through development. In addition, the Company proved 43.8 Bcfe from 3 Ohio Marcellus wells due to development in the Ohio Marcellus asset. • Positive revisions of 695.6 Bcfe as a result of a positive revision of 607.2 Bcfe due to improvements in SEC pricing, a positive revision of 61.4 Bcfe due to changes in pricing differentials, and a positive revision of 69.6 Bcfe primarily driven by proved developed producing wells in aggregate outperforming the previous estimate. This was offset by a negative revision of 42.6 Bcfe due a decision to not develop certain proved, undeveloped reserves within five years. 2018 Changes in Reserves • Extensions of 558.1 Bcfe from the development of 148.3 Bcfe of unproved wells to proved developed, 398.2 Bcfe from the development of the Company’s operated Utica asset and 11.6 Bcfe from the Company’s operated Marcellus asset. • 16.3 • 0.2 • Negative revisions of 42.8 Bcfe as a result of a positive revision of 15.0 Bcfe due to improvements in SEC pricing, a positive revision of 6.8 Bcfe due to changes in pricing differentials and a positive revision of 67.5 Bcfe primarily driven by proved developed producing wells outperforming the previous estimate. This was offset by a negative revision of 98.0 Bcfe due to changes in well spacing and 34.1 Bcfe due to changes in the five year development plan. F-34 (d) Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2018 and 2017 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2018, 2017, and 2016 (in thousands): December 31, 2018 2017 2016 Future cash inflows (total revenues) $ 6,730,000 $ 4,750,238 $ 1,143,142 Future production costs (2,964,098 ) (2,332,310 ) (725,724 ) Future development costs (capital costs) (855,932 ) (879,399 ) (116,988 ) Future income tax expense (136,472 ) — — Future net cash flows 2,773,498 1,538,529 300,430 10% annual discount for estimated timing of cash flows (1,444,188 ) (808,843 ) (94,449 ) Standardized measure of Discounted Future Net Cash Flow $ 1,329,310 $ 729,686 $ 205,981 It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. (e) Changes in the Standardized Measure of Discounted Future Net Cash Flows A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands): December 31, 2018 2017 2016 Standardized Measure, beginning of the year $ 729,686 $ 205,981 $ 212,865 Net change in prices and production costs 369,578 653,347 (33,507 ) Net change in future development costs 87,466 (385,042 ) 1,552 Sales, less production costs (321,802 ) (226,324 ) (99,768 ) Extensions 363,708 135,734 79,941 Acquisitions 7,468 2,365 1,045 Divestitures (20 ) — (5,231 ) Revisions of previous quantity estimates 19,910 322,917 15,754 Previously estimated development costs incurred 65,035 34,102 4,886 Net changes in taxes (37,345 ) — — Accretion of discount 72,969 20,598 21,287 Changes in timing and other (27,343 ) (33,992 ) 7,157 Standardized Measure, end of year $ 1,329,310 $ 729,686 $ 205,981 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Basis of Presentation | (a) Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2018 and 2017, and the results of its operations, comprehensive income (loss) and its cash flows for the years ended December 31, 2018, 2017, and 2016. |
Cash and Cash Equivalents | (b) 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 | (c) 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 party. The Company did not deem any of its accounts receivables to be uncollectable as of December 31, 2018 or December 31, 2017. 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, which are, in turn, based upon applicable product prices. The Company had $94.1 million and $52.9 million of accrued revenues, net of expenses at December 31, 2018 and December 31, 2017, respectively, which were included in accounts receivable within the Company’s consolidated balance sheets. |
Property and Equipment | (d) Property and Equipment Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “ Depreciation, Depletion and Amortization 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 consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s 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 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): December 31, 2018 December 31, 2017 Oil and natural gas properties: Unproved $ 482,475 $ 459,549 Proved 2,188,233 1,896,081 Gross oil and natural gas properties 2,670,708 2,355,630 Less accumulated depreciation, depletion and amortization (1,380,650 ) (1,248,200 ) Oil and natural gas properties, net 1,290,058 1,107,430 Other property and equipment 14,460 13,508 Less accumulated depreciation (8,160 ) (6,566 ) Other property and equipment, net 6,300 6,942 Property and equipment, net $ 1,296,358 $ 1,114,372 Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. The Company capitalized interest expense totaling $1.7 million, $2.3 million and $1.1 million for the years ended December 31, 2018, 2017, and 2016, respectively. Other Property and Equipment Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. |
Accounts Payable and Accrued Liabilities | (e) Accounts Payable and Accrued Liabilities A summary of accounts payable is as follows (in thousands): December 31, 2018 December 31, 2017 Trade payables $ 27,481 $ 44,516 Royalty payables 70,019 17,483 Production & ad valorem taxes 1,811 967 Derivative payable 4,736 941 Other payables 12,688 12,267 Total accounts payable $ 116,735 $ 76,174 A summary of accrued liabilities is as follows (in thousands): December 31, 2018 December 31, 2017 Ad valorem and production taxes $ 6,193 $ 4,299 Employee compensation 6,595 8,667 Royalties 39,969 9,660 Short term derivatives — 14,875 Other 4,152 4,161 Total accrued liabilities $ 56,909 $ 41,662 |
Revenue Recognition | (f) 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. 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 periods indicated: For the Year Ended December 31, 2018 2017 2016 Revenues (in thousands) Natural gas sales $ 274,239 $ 241,379 $ 134,618 NGL sales 86,152 64,109 38,204 Oil sales 138,202 74,690 50,193 Brokered natural gas and marketing revenue 16,552 3,481 12,019 Total revenues $ 515,145 $ 383,659 $ 235,034 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 $94.1 million and $52.9 million at December 31, 2018 and December 31, 2017, respectively. |
Major Customers | (g) Major Customers The Company sells production volumes to various purchasers. For the years ended December 31, 2018, 2017, and 2016, there were one, two and four customers, respectively, that accounted for 10% or more of the total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the Year Ended December 31, 2018 2017 2016 Purchaser Antero Resources — — 14% Concord Energy — — 12% Emera Energy Services — 17% — EnLink Midstream — — 17% Marathon Petroleum 25% 10% — Sequent Energy Management — — 20% Total 25% 27% 63% Management believes that the loss of any one customer would not have a material adverse effect on the Company’s ability to sell natural gas, NGLs and oil production because it believes that there are potential alternative purchasers although it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers. |
Concentration of Credit Risk | (h) Concentration of Credit Risk The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2018 and December 31, 2017 (in thousands): December 31, 2018 December 31, 2017 Receivables by product or service: Sale of oil and natural gas and related products and services $ 94,107 $ 52,908 Joint interest owners 24,830 23,154 Derivatives 372 1,528 Other 23 19 Total $ 119,332 $ 77,609 Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy 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 commodity unsettled derivative contracts was a net asset position of $5.7 million and a net liability position of ($5.1) million at December 31, 2018 and 2017, respectively. Other than, as provided by the 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 they required to provide credit support to the Company. As of December 31, 2018, the Company did not have past-due receivables from or payables to any of the counterparties. |
Depreciation, Depletion and Amortization | (i) Depreciation, Depletion and Amortization Oil and Natural Gas Properties Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties for the years ended December 31, 2018, 2017, and 2016 totaled approximately $132.5 million, $116.8 million and $91.0 million, respectively. Other Property and Equipment Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the years ended December 31, 2018, 2017, and 2016 totaled approximately $1.8 million, $2.0 million and $1.9 million, respectively. This amount is included in DD&A expense in the consolidated statements of operations. |
Impairment of Long-Lived Assets | (j) 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 of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the year ended December 31, 2016 relating to proved properties in the Marcellus Shale. The aforementioned impairment charges represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $27.6 million, $28.3 million, and $29.8 million for the years ended December 31, 2018, 2017, and 2016, respectively. These costs are included in exploration expense in the consolidated statements of operations. |
Income Taxes | (k) Income Taxes The Company accounts for income taxes, as required, under the liability method. 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 “ Income Taxes ” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date. |
Fair Value of Financial Instruments | (l) 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 date 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 | (m) 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 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 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 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 | (n) Asset Retirement Obligation The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 410, “Asset , 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 periods indicated (in thousands): For the Year Ended December 31, 2018 2017 2016 Asset retirement obligations, beginning of period $ 6,029 $ 4,806 $ 3,401 Additional liabilities incurred 418 679 1,014 Accretion 663 544 391 Asset retirement obligations, end of period $ 7,110 $ 6,029 $ 4,806 The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement. |
Lease Obligations | (o) Lease Obligations The Company leases office space under an operating lease that expires in 2024. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception. |
Off-Balance Sheet Arrangements | (p) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. |
Segment Reporting | (q) 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 | (r) 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 | (s) Recent Accounting Pronouncements Recently Adopted In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted this standard effective January 1, 2018 using the modified retrospective method. The Company did not recognize a significant impact on its financial position or results of operations. Upon adoption of this new standard, the Company did not record a cumulative effect adjustment nor did the Company alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify the impact of future revenue contracts entered into by the Company. Additional disclosures have been included to provide further detail regarding the Company’s revenue recognition policies. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company adopted this standard effective January 1, 2018 and did not recognize a significant impact on its financial position, results of operations, or statement of cash flows. In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” Currently under the standard, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company adopted this standard effective January 1, 2018 and considered the new guidance in its assessment of the accounting treatment for the Flat Castle Acquisition. (See Note 3— Acquisition Accounting Pronouncements Not Yet Adopted In February 2016, the FASB issued Update 2016-02, “Leases (Topic 842)”, which increases transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 maintains a distinction between finance leases and operating leases, which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease to remain similar to the previous accounting treatment. A lessee is permitted to make an accounting policy election by class of underlying asset to exclude from balance sheet recognition any lease assets and lease liabilities with a term of 12 months or less, and instead to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the ROU asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position. For public business entities, the amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach with the option to adopt certain practical expedients. In July 2018, the FASB issued Update 2018-11 which provides entities with the option to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company will adopt Topic 842 guidance as of January 1, 2019 using the transition method that allows a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company has elected the transition relief package of practical expedients by applying previous accounting conclusions under ASC 840 to all of its leases that existed prior to the transition date. As a result, the Company will not reassess 1) whether existing or expired contracts contain leases 2) lease classification for any existing or expired leases and 3) whether lease origination costs qualified as initial direct costs. The Company will not elect the practical expedient to use hindsight in determining a lease term and impairment of ROU assets at the adoption date. Additionally, the Company will elect the short-term practical expedient for all of its asset classes by establishing an accounting policy to exclude leases with a term of 12 months or less. The Company will not separate lease components from non-lease components for its specified asset classes. Lastly, the Company will adopt the easement practical expedient which allows the Company to apply ASC 842 prospectively to land easements after the adoption date. Easements that existed or expired prior to the adoption date that were not previously assessed under ASC 840 will not be reassessed. The Company has implemented a third-party supported lease accounting system to account for the identified leases and is currently in the process of performing final testing of this system. The adoption of Topic 842 will have a material impact on the Company’s Consolidated Balance Sheet due to the initial recognition of ROU assets and lease liabilities. In 2019, the Company expects to recognize a ROU asset and corresponding lease liability between $10 million to $15 million on its Consolidated Balance Sheet. Due to the BRMR Merger closing subsequent to the year ended December 31, 2018, the initial analysis in relation to BRMR’s adoption of Topic 842 is in process and will be accounted for in the period it closed. |
Change in Estimates | (t) Change in Estimates During the year ended December 31, 2016, the Company reduced its estimate of amounts due from a non-operated partner related to the sale of natural gas and NGLs, net of associated costs, based on revised information received from the non-operated partner during the period. As a result, the Company decreased accounts receivable by approximately $4 million, increased revenue from oil and natural gas sales by approximately $1.5 million, and increased transportation, gathering and compression expense by approximately $5.8 million, which increased the net loss for the year ended December 31, 2016 by approximately $4 million, or $0.02 per common share. During the year ended December 31, 2016, the Company reduced its estimate for production and ad valorem tax expense based on recent historical experience and additional information received during the period. As a result, the Company decreased the accrual for production and ad valorem taxes to be paid by approximately $4 million, which decreased the net loss for the year ended December 31, 2016 by a corresponding amount, or $0.30 per common share. |
Correction of Immaterial Error | (u) Correction of Immaterial Error During the three months ended March 31, 2017, the Company determined that its estimated accrual for production and ad valorem tax expense was overstated for prior periods. The Company evaluated the materiality of this error on both a quantitative and qualitative basis under the guidance of ASC 250 “Accounting Changes and Errors Corrections,” and determined that it did not have a material impact to previously issued financial statements. Although the error was immaterial to prior periods, the prior period financial statements were revised, in accordance with SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements A reconciliation of the effects of the revision to amounts in the previously reported consolidated financial statements is as follows (in thousands, except per share amounts): As of December 31, 2016 As Reported Adjustment As Adjusted Balance Sheet Accounts receivable $ 43,638 $ 785 $ 44,423 Total current assets 249,630 785 250,415 Total assets 1,197,859 785 1,198,644 Accrued liabilities 64,150 (9,106 ) 55,044 Total current liabilities 140,625 (9,106 ) 131,519 Total liabilities 651,143 (9,106 ) 642,037 Accumulated deficit (1,414,561 ) 9,891 (1,404,670 ) Total stockholders' equity 546,716 9,891 556,607 Total liabilities and stockholders' equity 1,197,859 785 1,198,644 As of December 31, 2016 As Reported Adjustment As Adjusted Statement of Stockholders' Equity Accumulated deficit $ (1,414,561 ) $ 9,891 $ (1,404,670 ) Total stockholders' equity 546,716 9,891 556,607 As of December 31, 2016 As Reported Adjustment As Adjusted Statement of Operations Production and ad valorem taxes $ 4,998 $ 2,929 $ 7,927 Total operating expenses 349,507 2,929 352,436 Operating loss (114,473 ) (2,929 ) (117,402 ) Loss before income taxes (203,260 ) (2,929 ) (206,189 ) Net loss (203,806 ) (2,929 ) (206,735 ) Basic and diluted loss per share $ (12.60 ) $ (0.24 ) $ (12.84 ) As of December 31, 2016 As Reported Adjustment As Adjusted Statement of Comprehensive Loss Net loss $ (203,806 ) $ (2,929 ) $ (206,735 ) Total Comprehensive loss (203,806 ) (2,929 ) (206,735 ) As of December 31, 2016 As Reported Adjustment As Adjusted Statement of Cash Flows Net loss $ (203,806 ) $ (2,929 ) $ (206,735 ) Accounts receivable (20,563 ) (714 ) (21,277 ) Accounts payable and accrued liabilities (2,849 ) 3,643 794 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Summary of Property and Equipment Including Oil and Natural Gas Properties | A summary of property and equipment including oil and natural gas properties is as follows (in thousands): December 31, 2018 December 31, 2017 Oil and natural gas properties: Unproved $ 482,475 $ 459,549 Proved 2,188,233 1,896,081 Gross oil and natural gas properties 2,670,708 2,355,630 Less accumulated depreciation, depletion and amortization (1,380,650 ) (1,248,200 ) Oil and natural gas properties, net 1,290,058 1,107,430 Other property and equipment 14,460 13,508 Less accumulated depreciation (8,160 ) (6,566 ) Other property and equipment, net 6,300 6,942 Property and equipment, net $ 1,296,358 $ 1,114,372 |
Schedule of Accounts Payable | A summary of accounts payable is as follows (in thousands): December 31, 2018 December 31, 2017 Trade payables $ 27,481 $ 44,516 Royalty payables 70,019 17,483 Production & ad valorem taxes 1,811 967 Derivative payable 4,736 941 Other payables 12,688 12,267 Total accounts payable $ 116,735 $ 76,174 |
Summary of Accrued Liabilities | A summary of accrued liabilities is as follows (in thousands): December 31, 2018 December 31, 2017 Ad valorem and production taxes $ 6,193 $ 4,299 Employee compensation 6,595 8,667 Royalties 39,969 9,660 Short term derivatives — 14,875 Other 4,152 4,161 Total accrued liabilities $ 56,909 $ 41,662 |
Summary of Revenue Disaggregated by Type | The following table illustrates the revenue disaggregated by type for the periods indicated: For the Year Ended December 31, 2018 2017 2016 Revenues (in thousands) Natural gas sales $ 274,239 $ 241,379 $ 134,618 NGL sales 86,152 64,109 38,204 Oil sales 138,202 74,690 50,193 Brokered natural gas and marketing revenue 16,552 3,481 12,019 Total revenues $ 515,145 $ 383,659 $ 235,034 |
Changes in Company's Asset Retirement Obligation Liability | The following table sets forth the changes in the Company’s ARO liability for the periods indicated (in thousands): For the Year Ended December 31, 2018 2017 2016 Asset retirement obligations, beginning of period $ 6,029 $ 4,806 $ 3,401 Additional liabilities incurred 418 679 1,014 Accretion 663 544 391 Asset retirement obligations, end of period $ 7,110 $ 6,029 $ 4,806 |
Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements | A reconciliation of the effects of the revision to amounts in the previously reported consolidated financial statements is as follows (in thousands, except per share amounts): As of December 31, 2016 As Reported Adjustment As Adjusted Balance Sheet Accounts receivable $ 43,638 $ 785 $ 44,423 Total current assets 249,630 785 250,415 Total assets 1,197,859 785 1,198,644 Accrued liabilities 64,150 (9,106 ) 55,044 Total current liabilities 140,625 (9,106 ) 131,519 Total liabilities 651,143 (9,106 ) 642,037 Accumulated deficit (1,414,561 ) 9,891 (1,404,670 ) Total stockholders' equity 546,716 9,891 556,607 Total liabilities and stockholders' equity 1,197,859 785 1,198,644 As of December 31, 2016 As Reported Adjustment As Adjusted Statement of Stockholders' Equity Accumulated deficit $ (1,414,561 ) $ 9,891 $ (1,404,670 ) Total stockholders' equity 546,716 9,891 556,607 As of December 31, 2016 As Reported Adjustment As Adjusted Statement of Operations Production and ad valorem taxes $ 4,998 $ 2,929 $ 7,927 Total operating expenses 349,507 2,929 352,436 Operating loss (114,473 ) (2,929 ) (117,402 ) Loss before income taxes (203,260 ) (2,929 ) (206,189 ) Net loss (203,806 ) (2,929 ) (206,735 ) Basic and diluted loss per share $ (12.60 ) $ (0.24 ) $ (12.84 ) As of December 31, 2016 As Reported Adjustment As Adjusted Statement of Comprehensive Loss Net loss $ (203,806 ) $ (2,929 ) $ (206,735 ) Total Comprehensive loss (203,806 ) (2,929 ) (206,735 ) As of December 31, 2016 As Reported Adjustment As Adjusted Statement of Cash Flows Net loss $ (203,806 ) $ (2,929 ) $ (206,735 ) Accounts receivable (20,563 ) (714 ) (21,277 ) Accounts payable and accrued liabilities (2,849 ) 3,643 794 |
Sales Revenue, Services, Net [Member] | Customer Concentration Risk [Member] | |
Concentration Risk | The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the Year Ended December 31, 2018 2017 2016 Purchaser Antero Resources — — 14% Concord Energy — — 12% Emera Energy Services — 17% — EnLink Midstream — — 17% Marathon Petroleum 25% 10% — Sequent Energy Management — — 20% Total 25% 27% 63% |
Accounts Receivable [Member] | Product Concentration Risk [Member] | |
Concentration Risk | The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2018 and December 31, 2017 (in thousands): December 31, 2018 December 31, 2017 Receivables by product or service: Sale of oil and natural gas and related products and services $ 94,107 $ 52,908 Joint interest owners 24,830 23,154 Derivatives 372 1,528 Other 23 19 Total $ 119,332 $ 77,609 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Derivative Instrument Positions for Future Production Periods | Below is a summary of the Company’s derivative instrument positions, as of December 31, 2018, for future production periods: Natural Gas Derivatives Description Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Swaps: 30,000 January 2019 – March 2019 $ 2.90 90,000 January 2019 – December 2019 $ 2.84 Natural Gas Collars: Ceiling sold price (call) 30,000 October 2019 – December 2019 $ 2.95 Floor sold price (put) 30,000 October 2019 – December 2019 $ 2.65 Natural Gas Three-way Collars: Floor purchase price (put) 30,000 January 2019 – March 2019 $ 3.00 Ceiling sold price (call) 30,000 January 2019 – March 2019 $ 3.40 Floor sold price (put) 30,000 January 2019 – March 2019 $ 2.50 Floor purchase price (put) 77,500 January 2019 – December 2019 $ 2.72 Ceiling sold price (call) 77,500 January 2019 – December 2019 $ 3.04 Floor sold price (put) 77,500 January 2019 – December 2019 $ 2.30 Floor purchase price (put) 50,000 January 2020 – June 2020 $ 2.70 Ceiling sold price (call) 50,000 January 2020 – June 2020 $ 2.95 Floor sold price (put) 50,000 January 2020 – June 2020 $ 2.25 Natural Gas Call/Put Options: Call sold 30,000 January 2019 – March 2019 $ 3.50 Call sold 30,000 April 2019 – December 2019 $ 3.00 Call sold 10,000 January 2019 – December 2019 $ 4.75 Basis Swaps: Appalachia - Dominion 12,500 April 2019 – October 2019 $ (0.52 ) Appalachia - Dominion 12,500 April 2020 – October 2020 $ (0.52 ) Appalachia - Dominion 20,000 January 2020 – December 2020 $ (0.59 ) Oil Derivatives Description Volume (Bbls/d) Production Period Weighted Price Oil Swaps: 1,000 January 2019 – March 2019 $ 61.00 Oil Three-way Collars: Floor purchase price (put) 2,000 January 2019 – December 2019 $ 50.00 Ceiling sold price (call) 2,000 January 2019 – December 2019 $ 60.56 Floor sold price (put) 2,000 January 2019 – December 2019 $ 40.00 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 |
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 consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes. 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 ) As of December 31, 2017 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 15,971 $ (6,380 ) $ 9,591 Other current assets Commodity derivatives - noncurrent 469 (176 ) 293 Other assets Total assets $ 16,440 $ (6,556 ) $ 9,884 Liabilities Commodity derivatives - current $ (21,256 ) $ 6,380 $ (14,876 ) Accrued liabilities Commodity derivatives - noncurrent (252 ) 176 (76 ) Other liabilities Total liabilities $ (21,508 ) $ 6,556 $ (14,952 ) (a) The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. |
Summary of Gains and Losses on Derivative Instruments | The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the consolidated statements of operations for the periods presented (in thousands): For the Year Ended December 31, Location of Gain (Loss) 2018 2017 2016 Commodity derivatives Gain (loss) on derivative instruments $ (21,169 ) $ 45,365 $ (52,338 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities that are Measured at Fair Value on a Recurring Basis | The fair value of the Company’s derivatives is based on third-party pricing models, which utilize inputs that are readily available in the public market, such as natural gas forward curves. These values are compared to the values given by counterparties for reasonableness. Since natural gas swaps 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 December 31, 2018: (in thousands) Commodity derivative instruments $ — $ 5,699 $ — $ 5,699 Total $ — $ 5,699 $ — $ 5,699 As of December 31, 2017: (in thousands) Commodity derivative instruments $ — $ (5,068 ) $ — $ (5,068 ) Total $ — $ (5,068 ) $ — $ (5,068 ) |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Schedule of Stock Based Compensation Expense | Our stock based compensation expense is as follows for the years ended December 31, 2018, 2017, and 2016 (in thousands): Year Ended December 31, 2018 2017 2016 Restricted stock units $ 4,014 $ 5,301 $ 4,006 Performance units 3,497 3,622 1,922 Restricted stock issued to directors 380 378 556 Incentive units — — (268 ) Total expense $ 7,891 $ 9,301 $ 6,216 |
Summary of Employee Restricted Stock Unit Awards Activity | A summary of employee restricted stock unit awards activity during the year ended December 31, 2018 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2017 270,490 $ 37.20 $ 9,738 Granted 99,901 25.50 Vested (132,406 ) 42.42 Forfeited (4,025 ) 31.30 Total awarded and unvested, December 31, 2018 233,960 $ 29.27 $ 3,685 |
Summary of Performance Stock Unit Awards Activity | A summary of performance stock unit awards activity during the year ended December 31, 2018 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2017 264,425 $ 27.30 $ 11,257 Granted 99,901 28.80 Vested (11,536 ) 27.51 Forfeited (6,201 ) 27.61 Total awarded and unvested, December 31, 2018 346,589 $ 27.68 $ 716 |
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 years ended December 31, 2018, 2017, and 2016: Year Ended December 31, 2018 2017 2016 Volatility 89.70 % 50.41 % 49.84 % Risk-free interest rate 2.37 % 1.34 % 0.96 % |
Earnings (Loss) Per Share (Tabl
Earnings (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share | The below table retroactively reflects, in accordance with ASC 505 “Equity”, the stock split that occurred after the year ended December 31, 2018 for the years ended December 31, 2018, 2017, and 2016, respectively Year Ended December 31, (in thousands, except per share data) 2018 2017 2016 Income (Loss) Shares Per Share Income (Loss) Shares Per Share Income (Loss) Shares Per Share Basic: Net income (loss), shares, basic $ 18,826 19,999 $ 0.94 $ 8,525 17,479 $ 0.49 $ (206,735 ) 16,096 $ (12.84 ) Weighted-average number of shares of common stock-diluted: Restricted stock and performance unit awards — 88 — 200 — — Diluted: Net income (loss), shares, diluted $ 18,826 20,087 $ 0.94 $ 8,525 17,679 $ 0.48 $ (206,735 ) 16,096 $ (12.84 ) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Future Minimum Lease Payments Required Under Lease Agreements | The following is a schedule by year, of the future minimum lease payments required under the lease agreements as of December 31, 2018 (in thousands). 2019 1,360 2020 1,060 2021 929 2022 755 2023 755 Thereafter 1,619 Total minimum lease payments $ 6,478 |
Other Commitments | (d) Other Commitments (in thousands) Drilling rig commitments (i) Firm transportation (ii) Gas processing, gathering, and compression services (iii) Total Year Ending December 31: 2019 $ 1,287 $ 80,083 $ 26,271 $ 107,641 2020 — 80,303 22,886 103,189 2021 — 80,083 18,147 98,230 2022 — 80,083 20,440 100,523 2023 — 80,083 18,515 98,598 Thereafter — 700,549 61,923 762,472 Total $ 1,287 $ 1,101,184 $ 168,182 $ 1,270,653 (i) Drilling rig commitments - The Company had contracts for the service of two rigs, which have both expired and the Company has entered into well-to-well contracts. 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, as applicable. (ii) 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. (iii) 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 (Tables)
Income Tax (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Segregation of Income Tax Provision Based on Location of Operations | For the Year Ended December 31, 2018 2017 2016 Current Federal $ — $ — $ — State — — 6 Total current — — 6 Deferred Federal — — — State — — 540 Total deferred — — 540 Total income tax expense (benefit) $ — $ — $ 546 |
Schedule of Effective Income Tax Rate Reconciliation | The Company’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items (in thousands): For the Year Ended December 31, 2018 2017 2016 Income (loss) before income taxes $ 18,826 $ 8,525 $ (206,189 ) Statutory rate 21 % 35 % 35 % Income tax benefit computed at statutory rate 3,953 2,984 (72,166 ) Reconciling items: State income taxes — — 546 Other, net 54 50 854 Share-based compensation 1,201 (576 ) — Executive compensation limitation 268 496 — Change in valuation allowance (5,476 ) (145,449 ) 71,312 Change in Federal tax rate — 142,495 — Income tax expense (benefit) $ — $ — $ 546 |
Components of Deferred Tax Assets and Liabilities | The components of the Company’s deferred taxes are detailed in the table below (in thousands): For the Year Ended December 31, 2018 2017 2016 Deferred tax asset: Oil and gas properties and equipment $ 62,616 $ 93,854 $ 193,095 Federal tax loss carryforwards 140,059 114,652 145,628 Derivative instruments and other — 1,064 16,829 State effect of deferreds — — — Other, net 7,398 4,639 4,259 Deferred tax asset 210,073 214,209 359,811 Valuation allowance (208,324 ) (213,800 ) (359,098 ) Net deferred tax assets $ 1,749 $ 409 $ 713 Deferred tax liability: Derivative instruments and other $ 1,197 $ — $ — Other, net 552 409 713 Net deferred tax liability $ 1,749 $ 409 $ 713 Reflected in the accompanying consolidated balance sheet as: Net deferred tax asset $ — $ — $ — Net deferred tax liability $ — $ — $ — |
Quarterly Financial Informati_2
Quarterly Financial Information (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Summarized quarterly financial data for the years ended December 31, 2018 and 2017 are presented in the following table to retroactively reflect the 15-to-1 reverse stock split at the close the BRMR Merger. In the following table, the sum of basic and diluted “Income (loss) per common share” for the four quarters may differ from the annual amounts due to the required method of computing weighted average number of shares in the respective periods. Additionally, due to the effect of rounding, the sum of the individual quarterly loss per share amounts may not equal the calculated year loss per share amount (in thousands, except per share data). First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2018 Total operating revenues $ 110,192 $ 103,622 $ 130,123 $ 171,208 Total operating expenses 95,651 92,989 108,929 123,590 Operating income (loss) 14,541 10,633 21,194 47,618 Net income (loss) (2,626 ) (19,036 ) 3,998 36,490 Income (loss) per common share: Basic $ (0.13 ) $ (0.95 ) $ 0.20 $ 1.81 Diluted $ (0.13 ) $ (0.95 ) $ 0.20 $ 1.80 First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2017 Total operating revenues $ 101,863 $ 86,191 $ 91,549 $ 104,056 Total operating expenses 87,632 80,589 94,338 108,431 Operating loss 14,231 5,602 (2,789 ) (4,375 ) Net income (loss) 26,847 11,494 (16,694 ) (13,122 ) Income (loss) per common share: Basic $ 1.54 $ 0.66 $ (0.95 ) $ (0.75 ) Diluted $ 1.52 $ 0.65 $ (0.95 ) $ (0.74 ) |
Supplemental Oil and Natural _2
Supplemental Oil and Natural Gas Information (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Text Block [Abstract] | |
Summary of Capitalized Costs | A summary of the Company’s capitalized costs are contained in the table below (in thousands): December 31, 2018 2017 Oil and natural gas properties: Unproved properties $ 482,475 $ 459,549 Proved properties 2,188,233 1,896,081 Total oil and natural gas properties 2,670,708 2,355,630 Less accumulated depreciation, depletion and amortization (1,380,650 ) (1,248,200 ) Net oil and natural gas properties $ 1,290,058 $ 1,107,430 |
Summary of Oil and Gas Property Acquisition and Development | A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands): December 31, 2018 2017 2016 Acquisition costs: Unproved properties $ 107,862 $ 57,498 $ 24,764 Proved properties 4,072 — — Development cost 239,467 257,119 150,778 Exploration cost 20,957 18,791 20,127 Total acquisition, development and exploration costs $ 372,358 $ 333,408 $ 195,669 |
Proved Developed and Proved Undeveloped Reserves | The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2018, 2017, and 2016 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Natural Gas (Bcf) Natural Gas Liquids (MBbl) Oil (MBbl) TOTAL (Bcfe) End of year, December 31, 2015 274.1 7,758.7 4,693.1 348.8 Revisions (0.1 ) 1,273.7 1,196.8 14.8 Extensions and discoveries 175.4 2,156.0 1,300.2 196.1 Acquisitions 3.8 24.8 15.1 4.1 Divestitures (5.9 ) (91.5 ) (703.7 ) (10.7 ) Production (60.9 ) (2,446.2 ) (1,343.8 ) (83.7 ) End of year, December 31, 2016 386.4 8,675.5 5,157.7 469.4 Revisions 515.1 20,327.3 9,746.8 695.6 Extensions and discoveries 274.4 15,598.8 6,192.9 405.1 Acquisitions 1.6 42.6 5.8 1.9 Production (87.4 ) (2,713.6 ) (1,622.4 ) (113.4 ) End of year, December 31, 2017 1,090.1 41,930.6 19,480.8 1,458.6 Revisions 5.6 (8,307.5 ) 231.2 (42.8 ) Extensions and discoveries 515.8 4,059.4 2,995.7 558.1 Acquisitions 9.9 551 522 16.3 Divestitures (0.2 ) — — (0.2 ) Production (90.0 ) (3,503.0 ) (2,377.8 ) (125.3 ) End of year, December 31, 2018 1,531.2 34,730.9 20,852.1 1,864.7 Proved developed reserves: December 31, 2015 209.5 7,245.7 4,239.2 278.4 December 31, 2016 226.1 7,520.0 4,439.5 297.8 December 31, 2017 334.6 13,782.9 6,449.6 456.0 December 31, 2018 501.0 20,213.8 8,058.7 670.7 Proved undeveloped reserves: December 31, 2015 64.5 513.0 453.9 70.3 December 31, 2016 160.4 1,155.5 718.1 171.6 December 31, 2017 755.5 28,147.7 13,031.2 1,002.6 December 31, 2018 1,030.2 14,517.2 12,793.4 1,194.1 |
Standard Measure of Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2018, 2017, and 2016 (in thousands): December 31, 2018 2017 2016 Future cash inflows (total revenues) $ 6,730,000 $ 4,750,238 $ 1,143,142 Future production costs (2,964,098 ) (2,332,310 ) (725,724 ) Future development costs (capital costs) (855,932 ) (879,399 ) (116,988 ) Future income tax expense (136,472 ) — — Future net cash flows 2,773,498 1,538,529 300,430 10% annual discount for estimated timing of cash flows (1,444,188 ) (808,843 ) (94,449 ) Standardized measure of Discounted Future Net Cash Flow $ 1,329,310 $ 729,686 $ 205,981 |
Summary of Changes in Standardized Measure of Discounted Net Cash Flows | A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands): December 31, 2018 2017 2016 Standardized Measure, beginning of the year $ 729,686 $ 205,981 $ 212,865 Net change in prices and production costs 369,578 653,347 (33,507 ) Net change in future development costs 87,466 (385,042 ) 1,552 Sales, less production costs (321,802 ) (226,324 ) (99,768 ) Extensions 363,708 135,734 79,941 Acquisitions 7,468 2,365 1,045 Divestitures (20 ) — (5,231 ) Revisions of previous quantity estimates 19,910 322,917 15,754 Previously estimated development costs incurred 65,035 34,102 4,886 Net changes in taxes (37,345 ) — — Accretion of discount 72,969 20,598 21,287 Changes in timing and other (27,343 ) (33,992 ) 7,157 Standardized Measure, end of year $ 1,329,310 $ 729,686 $ 205,981 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018USD ($)CustomerSegment | Dec. 31, 2017USD ($)Customer | Dec. 31, 2016USD ($)Customer$ / shares | |
Summary Of Significant Accounting Policies [Line Items] | |||
Accounts receivable | $ 119,332 | $ 77,609 | $ 44,423 |
Capitalized interest expense | 1,700 | 2,300 | 1,100 |
Depreciation, depletion and amortization | $ 134,277 | $ 118,818 | 92,948 |
Impairment of oil and gas properties | 17,665 | ||
Asset retirement obligations credit adjusted discount rates | 10.33% | 10.33% | |
Operating lease expiration year | 2024 | ||
Number of operating segment | Segment | 1 | ||
Decrease in accounts receivable | $ 42,879 | $ 31,780 | $ 21,277 |
Increase of net loss, per common share | $ / shares | $ (12.84) | ||
Decrease in accrual for production and ad valorem taxes to be paid | $ 4,000 | ||
Decrease of net loss, per common share | $ / shares | $ 0.30 | ||
Natural Gas and NGLs [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Decrease in accounts receivable | $ (4,000) | ||
Increase in revenue from oil and natural gas | 1,500 | ||
Increase in transportation, gathering and compression expense | 5,800 | ||
Increase in net loss | $ 4,000 | ||
Increase of net loss, per common share | $ / shares | $ 0.02 | ||
Topic 842 [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Operating lease ROU asset | 10,000 | ||
Operating lease liability | 15,000 | ||
Oil and Gas Properties [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Depreciation, depletion and amortization | 132,500 | 116,800 | $ 91,000 |
Other property and equipment [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Depreciation | $ 1,800 | 2,000 | 1,900 |
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 | 17,700 | ||
Unproved Oil And Gas Properties [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Impairment of oil and gas properties | $ 27,600 | 28,300 | $ 29,800 |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Fair value of commodity derivative contracts | $ 5,700 | $ (5,100) | |
Sales Revenue, Net [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Number of customers | Customer | 1 | 2 | 4 |
Revenue From Contract With Customer [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Accounts receivable | $ 94,100 | $ 52,900 | |
Unbilled Revenues [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Accounts receivable | $ 94,100 | $ 52,900 |
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 | Dec. 31, 2018 | Dec. 31, 2017 |
Oil and natural gas properties: | ||
Unproved properties | $ 482,475 | $ 459,549 |
Proved properties | 2,188,233 | 1,896,081 |
Gross oil and natural gas properties | 2,670,708 | 2,355,630 |
Less accumulated depreciation, depletion and amortization | (1,380,650) | (1,248,200) |
Total oil and natural gas properties, net | 1,290,058 | 1,107,430 |
Other property and equipment | 14,460 | 13,508 |
Less accumulated depreciation | (8,160) | (6,566) |
Other property and equipment, net | 6,300 | 6,942 |
Total property and equipment, net | $ 1,296,358 | $ 1,114,372 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Summary of Accounts Payable (Detail) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts Payable Current [Abstract] | ||
Trade payables | $ 27,481 | $ 44,516 |
Royalty payables | 70,019 | 17,483 |
Production & ad valorem taxes | 1,811 | 967 |
Derivative payable | 4,736 | 941 |
Other payables | 12,688 | 12,267 |
Total accounts payable | $ 116,735 | $ 76,174 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Summary of Accrued Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Accrued Liabilities Current [Abstract] | |||
Ad valorem and production taxes | $ 6,193 | $ 4,299 | |
Employee compensation | 6,595 | 8,667 | |
Royalties | 39,969 | 9,660 | |
Short term derivatives | 14,875 | ||
Other | 4,152 | 4,161 | |
Total accrued liabilities | $ 56,909 | $ 41,662 | $ 55,044 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Summary of Revenue Disaggregated by Type (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disaggregation Of Revenue [Line Items] | |||||||||||
Revenues | $ 171,208 | $ 130,123 | $ 103,622 | $ 110,192 | $ 104,056 | $ 91,549 | $ 86,191 | $ 101,863 | $ 515,145 | $ 383,659 | $ 235,034 |
Natural Gas Sales [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Revenues | 274,239 | 241,379 | 134,618 | ||||||||
NGL Sales [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Revenues | 86,152 | 64,109 | 38,204 | ||||||||
Oil Sales [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Revenues | 138,202 | 74,690 | 50,193 | ||||||||
Brokered Natural Gas and Marketing Revenue [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Revenues | $ 16,552 | $ 3,481 | $ 12,019 |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies - Major Customers and Associated Percentage of Revenue (Detail) - Sales Revenue, Net [Member] - Customer Concentration Risk [Member] | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 25.00% | 27.00% | 63.00% |
Antero Resources [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 14.00% | ||
Concord Energy [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 12.00% | ||
Emera Energy Services [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 17.00% | ||
EnLink Midstream [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 17.00% | ||
Marathon Petroleum [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 25.00% | 10.00% | |
Sequent Energy Management [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 20.00% |
Summary of Significant Accou_10
Summary of Significant Accounting Policies - Summary for Concentration of Receivables, Net of Allowances, By Product or Service (Detail) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Revenue, Major Customer [Line Items] | |||
Concentration of receivables, net of allowances | $ 119,332 | $ 77,609 | $ 44,423 |
Product Concentration Risk [Member] | Oil and Natural Gas and Related Products and Services [Member] | |||
Revenue, Major Customer [Line Items] | |||
Concentration of receivables, net of allowances | 94,107 | 52,908 | |
Product Concentration Risk [Member] | Joint Interest Owners [Member] | |||
Revenue, Major Customer [Line Items] | |||
Concentration of receivables, net of allowances | 24,830 | 23,154 | |
Product Concentration Risk [Member] | Derivatives [Member] | |||
Revenue, Major Customer [Line Items] | |||
Concentration of receivables, net of allowances | 372 | 1,528 | |
Product Concentration Risk [Member] | Other [Member] | |||
Revenue, Major Customer [Line Items] | |||
Concentration of receivables, net of allowances | $ 23 | $ 19 |
Summary of Significant Accou_11
Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation [Abstract] | |||
Asset retirement obligations, beginning of period | $ 6,029 | $ 4,806 | $ 3,401 |
Additional liabilities incurred | 418 | 679 | 1,014 |
Accretion | 663 | 544 | 391 |
Asset retirement obligations, end of period | $ 7,110 | $ 6,029 | $ 4,806 |
Summary of Significant Accou_12
Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Balance Sheet (Detail) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Quantifying Misstatement In Current Year Financial Statements [Line Items] | ||||
Accounts receivable | $ 119,332 | $ 77,609 | $ 44,423 | |
Total current assets | 133,930 | 107,062 | 250,415 | |
Total assets | 1,433,769 | 1,223,527 | 1,198,644 | |
Accounts payable | 116,735 | 76,174 | ||
Accrued liabilities | 56,909 | 41,662 | 55,044 | |
Total current liabilities | 208,284 | 149,594 | 131,519 | |
Total liabilities | 746,283 | 651,173 | 642,037 | |
Accumulated deficit | (1,377,319) | (1,396,145) | (1,404,670) | |
Total stockholders' equity | 687,486 | 572,354 | 556,607 | $ 633,374 |
Total liabilities and stockholders' equity | $ 1,433,769 | $ 1,223,527 | 1,198,644 | |
As Reported [Member] | ||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | ||||
Accounts receivable | 43,638 | |||
Total current assets | 249,630 | |||
Total assets | 1,197,859 | |||
Accrued liabilities | 64,150 | |||
Total current liabilities | 140,625 | |||
Total liabilities | 651,143 | |||
Accumulated deficit | (1,414,561) | |||
Total stockholders' equity | 546,716 | |||
Total liabilities and stockholders' equity | 1,197,859 | |||
Adjustment [Member] | ||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | ||||
Accounts receivable | 785 | |||
Total current assets | 785 | |||
Total assets | 785 | |||
Accrued liabilities | (9,106) | |||
Total current liabilities | (9,106) | |||
Total liabilities | (9,106) | |||
Accumulated deficit | 9,891 | |||
Total stockholders' equity | 9,891 | |||
Total liabilities and stockholders' equity | $ 785 |
Summary of Significant Accou_13
Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Statement of Stockholders' Equity (Detail) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Quantifying Misstatement In Current Year Financial Statements [Line Items] | ||||
Accumulated deficit | $ (1,377,319) | $ (1,396,145) | $ (1,404,670) | |
Total stockholders' equity | $ 687,486 | $ 572,354 | 556,607 | $ 633,374 |
As Reported [Member] | ||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | ||||
Accumulated deficit | (1,414,561) | |||
Total stockholders' equity | 546,716 | |||
Adjustment [Member] | ||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | ||||
Accumulated deficit | 9,891 | |||
Total stockholders' equity | $ 9,891 |
Summary of Significant Accou_14
Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Statement of Operations (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Production and ad valorem taxes | $ 10,141 | $ 8,490 | $ 7,927 | ||||||||
Total operating expenses | $ 123,590 | $ 108,929 | $ 92,989 | $ 95,651 | $ 108,431 | $ 94,338 | $ 80,589 | $ 87,632 | 421,159 | 370,990 | 352,436 |
Operating loss | 47,618 | 21,194 | 10,633 | 14,541 | (4,375) | (2,789) | 5,602 | 14,231 | 93,986 | 12,669 | (117,402) |
Loss before income taxes | 18,826 | 8,525 | (206,189) | ||||||||
Income tax benefit (expense) | (546) | ||||||||||
Net loss | $ 36,490 | $ 3,998 | $ (19,036) | $ (2,626) | $ (13,122) | $ (16,694) | $ 11,494 | $ 26,847 | $ 18,826 | $ 8,525 | $ (206,735) |
Basic and diluted loss per share | $ (12.84) | ||||||||||
As Reported [Member] | |||||||||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Production and ad valorem taxes | $ 4,998 | ||||||||||
Total operating expenses | 349,507 | ||||||||||
Operating loss | (114,473) | ||||||||||
Loss before income taxes | (203,260) | ||||||||||
Net loss | $ (203,806) | ||||||||||
Basic and diluted loss per share | $ (12.60) | ||||||||||
Adjustment [Member] | |||||||||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Production and ad valorem taxes | $ 2,929 | ||||||||||
Total operating expenses | 2,929 | ||||||||||
Operating loss | (2,929) | ||||||||||
Loss before income taxes | (2,929) | ||||||||||
Net loss | $ (2,929) | ||||||||||
Basic and diluted loss per share | $ (0.24) |
Summary of Significant Accou_15
Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Statement of Comprehensive Loss (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Net loss | $ 36,490 | $ 3,998 | $ (19,036) | $ (2,626) | $ (13,122) | $ (16,694) | $ 11,494 | $ 26,847 | $ 18,826 | $ 8,525 | $ (206,735) |
Total Comprehensive loss | (206,735) | ||||||||||
As Reported [Member] | |||||||||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Net loss | (203,806) | ||||||||||
Total Comprehensive loss | (203,806) | ||||||||||
Adjustment [Member] | |||||||||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Net loss | (2,929) | ||||||||||
Total Comprehensive loss | $ (2,929) |
Summary of Significant Accou_16
Summary of Significant Accounting Policies - Summary of Reconciliation of Amounts in Previously Reported Consolidated Financial Statements - Statement of Cash Flows (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Net loss | $ 36,490 | $ 3,998 | $ (19,036) | $ (2,626) | $ (13,122) | $ (16,694) | $ 11,494 | $ 26,847 | $ 18,826 | $ 8,525 | $ (206,735) |
Deferred income taxes | 540 | ||||||||||
Accounts receivable | (42,879) | (31,780) | (21,277) | ||||||||
Accounts payable and accrued liabilities | $ 84,231 | $ 18,404 | 794 | ||||||||
As Reported [Member] | |||||||||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Net loss | (203,806) | ||||||||||
Accounts receivable | (20,563) | ||||||||||
Accounts payable and accrued liabilities | (2,849) | ||||||||||
Adjustment [Member] | |||||||||||
Quantifying Misstatement In Current Year Financial Statements [Line Items] | |||||||||||
Net loss | (2,929) | ||||||||||
Accounts receivable | (714) | ||||||||||
Accounts payable and accrued liabilities | $ 3,643 |
Acquisition - Additional Inform
Acquisition - Additional Information (Detail) $ / shares in Units, $ in Millions | Feb. 28, 2019$ / sharesshares | Jan. 18, 2018USD ($)aWellshares | Dec. 31, 2018$ / shares | Dec. 31, 2017$ / shares | Dec. 31, 2016$ / shares |
Business Acquisition [Line Items] | |||||
Common stock, par value | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | ||
Flat Castle Acquisition [Member] | |||||
Business Acquisition [Line Items] | |||||
Area of land purchased | a | 44,500 | ||||
Purchase price | $ 90 | ||||
Purchase price paid through shares of common stock | shares | 2,500,000 | ||||
Transaction costs capitalized related to acquisition | $ 1 | ||||
Flat Castle Acquisition [Member] | Proved Oil And Gas Properties [Member] | |||||
Business Acquisition [Line Items] | |||||
Number of producing wells acquired | Well | 1 | ||||
Purchase price | $ 4 | ||||
Flat Castle Acquisition [Member] | Unproved Oil and Natural Gas Properties [Member] | |||||
Business Acquisition [Line Items] | |||||
Purchase price | $ 86 | ||||
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] | Subsequent Event [Member] | |||||
Business Acquisition [Line Items] | |||||
Common stock, par value | $ / shares | $ 0.01 | ||||
BRMR and Everest Merger Sub Inc. [Member] | Common Stock [Member] | Subsequent Event [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 | 0.066 |
Sale of Oil and Natural Gas P_2
Sale of Oil and Natural Gas Property Interests - Additional Information (Detail) | 12 Months Ended | |||
Dec. 31, 2018USD ($)a | Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($)a | Dec. 31, 2015USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | $ 4,700,000 | |||
Acreage Trades [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | 1,600,000 | |||
Gain (loss) on sale of oil and gas property | $ 0 | |||
Area of land | a | 249.5 | |||
Pipelines [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | $ 400,000 | |||
Pipelines [Member] | Maximum [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Gain (loss) on sale of oil and gas property | (100,000) | |||
Mineral Interests [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | 3,900,000 | |||
Gain (loss) on sale of oil and gas property | 0 | |||
Unproved Lease Properties [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | 4,800,000 | |||
Gain (loss) on sale of oil and gas property | 0 | |||
Assets Held for Sale [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Cost related to sale of oil and gas properties | $ 21,800,000 | |||
Asset retirement obligations related to sale of oil and gas properties | 19,100,000 | |||
Gain (loss) on sale of oil and gas property | $ 1,100,000 | |||
Assets Held for Sale [Member] | Pipelines [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | $ 200,000 | |||
Assets Held for Sale [Member] | Pipelines [Member] | Maximum [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 | (100,000) | |||
Asset Sale [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | 63,800,000 | |||
Gain (loss) on sale of oil and gas property | $ (7,600,000) | |||
Area of land | a | 9,900 | |||
Asset Sale 100 Acres [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | $ 500,000 | |||
Gain (loss) on sale of oil and gas property | $ 0 | |||
Area of land | a | 100 | |||
Asset Sale 150 Acres [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | $ 800,000 | |||
Gain (loss) on sale of oil and gas property | $ 200,000 | |||
Area of land | a | 150 | |||
Asset Sale 1,000 Acres [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | 6,000,000 | |||
Gain (loss) on sale of oil and gas property | $ 1,500,000 | |||
Area of land | a | 1,000 | |||
Asset Sale 400 Acres [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of oil and gas property | $ 3,800,000 | |||
Gain (loss) on sale of oil and gas property | $ 0 | |||
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] | ||||
Proceeds from sale of oil and gas property | $ 300,000 | |||
Gain (loss) on sale of oil and gas property | $ 300,000 | |||
Area of land | a | 50 |
Derivative Instruments - Summar
Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail) | 12 Months Ended |
Dec. 31, 2018MMBTU$ / MMBTUbbl | |
Natural Gas Swaps Production Period January 2019 – March 2019 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 2.90 |
Natural Gas Swaps Production Period January 2019 – December 2019 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 90,000 |
Weighted Average Price ($/MMBtu) | 2.84 |
Basis Swaps Production Period April 2019 – October 2019 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 12,500 |
Weighted Average Price ($/MMBtu) | (0.52) |
Basis Swaps Production Period April 2020 – October 2020 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 12,500 |
Weighted Average Price ($/MMBtu) | (0.52) |
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 ($/MMBtu) | (0.59) |
Natural Gas Collars Production Period October 2019 – December 2019 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 2.95 |
Natural Gas Collars Production Period October 2019 – December 2019 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.65 |
Natural Gas Three-way Collars Production Period January 2019 - March 2019 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 3.40 |
Natural Gas Three-way Collars Production Period January 2019 - March 2019 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.50 |
Natural Gas Three-way Collars Production Period January 2019 - March 2019 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Floor ($/MMBtu) | 3 |
Natural Gas Three-way Collars Production Period January 2019 - December 2019 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 77,500 |
Weighted Average Price, Ceiling ($/MMBtu) | 3.04 |
Natural Gas Three-way Collars Production Period January 2019 - December 2019 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 77,500 |
Weighted Average Price, Floor ($/MMBtu) | 2.30 |
Natural Gas Three-way Collars Production Period January 2019 - December 2019 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 77,500 |
Weighted Average Price, Floor ($/MMBtu) | 2.72 |
Natural Gas Three-way Collars Production Period January 2020 - June 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 2.95 |
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 | 50,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.25 |
Natural Gas Three-way Collars Production Period January 2020 - June 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.70 |
Natural Gas Call/Put Options Production Period January 2019 - December 2019 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 10,000 |
Weighted Average Price ($/MMBtu) | 4.75 |
Natural Gas Call/Put Options Production Period January 2019 - March 2019 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 3.50 |
Natural Gas Call/Put Options Production Period April 2019 - December 2019 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 3 |
Oil Swaps Production Period January 2019 – March 2019 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 61 |
Volume (Bbls/d) | bbl | 1,000 |
Oil Three-way Collars Production Period January 2019 - December 2019 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Ceiling ($/MMBtu) | 60.56 |
Volume (Bbls/d) | bbl | 2,000 |
Oil Three-way Collars Production Period January 2019 - December 2019 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Floor ($/MMBtu) | 40 |
Volume (Bbls/d) | bbl | 2,000 |
Oil Three-way Collars Production Period January 2019 - December 2019 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Floor ($/MMBtu) | 50 |
Volume (Bbls/d) | bbl | 2,000 |
Oil Three-way Collars Production Period January 2020 – June 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Ceiling ($/MMBtu) | 74 |
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 ($/MMBtu) | 55 |
Volume (Bbls/d) | bbl | 2,000 |
Oil Three-way Collars Production Period January 2020 – June 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Floor ($/MMBtu) | 62.50 |
Volume (Bbls/d) | bbl | 2,000 |
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 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivatives, Fair Value [Line Items] | |||
Gross Amount | $ 6,870 | $ 16,440 | |
Netting Adjustments | [1] | (845) | (6,556) |
Net Amount Presented in Balance Sheets | 6,025 | 9,884 | |
Gross Amount | (1,171) | (21,508) | |
Netting Adjustments | [1] | 845 | 6,556 |
Net Amount Presented in Balance Sheets | (326) | (14,952) | |
Other Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 4,960 | 15,971 | |
Netting Adjustments | [1] | (845) | (6,380) |
Net Amount Presented in Balance Sheets | 4,115 | 9,591 | |
Other Noncurrent Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 1,910 | 469 | |
Netting Adjustments | [1] | (176) | |
Net Amount Presented in Balance Sheets | 1,910 | 293 | |
Current Liabilities [Member] | Accrued Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (845) | (21,256) | |
Netting Adjustments | [1] | 845 | 6,380 |
Net Amount Presented in Balance Sheets | (14,876) | ||
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (326) | (252) | |
Netting Adjustments | [1] | 176 | |
Net Amount Presented in Balance Sheets | $ (326) | $ (76) | |
[1] | The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. |
Derivative Instruments - Summ_2
Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments | $ (21,169) | $ 45,365 | $ (52,338) |
Commodity Contract [Member] | Gain (Loss) on Derivative Instruments [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments | $ (21,169) | $ 45,365 | $ (52,338) |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Fair Value Measured on a Recurring Basis (Detail) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | $ 5,699 | $ (5,068) |
Commodity Contract [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | 5,699 | (5,068) |
Level 2 [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | 5,699 | (5,068) |
Level 2 [Member] | Commodity Contract [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | $ 5,699 | $ (5,068) |
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, 2014 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Jan. 01, 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. | ||||||||||||||
Gain on early extinguishment of debt | $ 14,489,000 | ||||||||||||||
Outstanding letters of credit | $ 27,000,000 | $ 27,000,000 | |||||||||||||
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% | ||||||||||||
Subsequent Event [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Outstanding letters of credit | $ 13,500,000 | ||||||||||||||
Subsequent Event [Member] | BRMR and Everest Merger Sub Inc. [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of credit facility extended maturity period | 5 years | ||||||||||||||
Scenario, Forecast [Member] | BRMR and Everest Merger Sub Inc. [Member] | Minimum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Ratio of total funded net debt to EBITDAX | 400.00% | ||||||||||||||
Revolving Credit Facility [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Revolving credit facility | $ 500,000,000 | ||||||||||||||
Credit facility maturity year | 2018 | ||||||||||||||
Applicable Margin | 0.50% | ||||||||||||||
Percentage of additional mortgage to be delivered | 90.00% | ||||||||||||||
Additional Period for the effectiveness of amendment | 60 days | ||||||||||||||
Borrowing base | $ 175,000,000 | $ 225,000,000 | 225,000,000 | $ 225,000,000 | $ 125,000,000 | ||||||||||
Revolving credit facility, extended maturity month and year | 2020-02 | ||||||||||||||
Outstanding borrowings | 32,500,000 | 32,500,000 | |||||||||||||
Available capacity on the Revolving Credit Facility | $ 165,500,000 | $ 165,500,000 | |||||||||||||
Percentage of company's properties and guarantees secured by mortgages | 85.00% | 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] | Subsequent Event [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Borrowing base | 85,000,000 | ||||||||||||||
Available capacity on the Revolving Credit Facility | $ 244,000,000 | ||||||||||||||
Revolving Credit Facility [Member] | Subsequent Event [Member] | BRMR and Everest Merger Sub Inc. [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Borrowing base | $ 375,000,000 | ||||||||||||||
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% | 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 | $ 3,600,000 | $ 3,400,000 | 3,300,000 | ||||||||||||
Principal amount outstanding | 39,500,000 | ||||||||||||||
Gain on early extinguishment of debt | 14,500,000 | ||||||||||||||
8.875% Senior Unsecured Notes Due 2023 [Member] | Level 2 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Fair value of senior unsecured notes | $ 437,900,000 | $ 437,900,000 | |||||||||||||
8.875% Senior Unsecured Notes Due 2023 [Member] | Open Market [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt instrument repurchase amount | $ 23,400,000 | ||||||||||||||
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 | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
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 | $ 0.9 | $ 0.7 | $ 0.7 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) $ in Millions | Feb. 28, 2019 | May 16, 2018Directorshares | May 17, 2017Directorshares | May 18, 2016Directorshares | May 11, 2015Directorshares | Dec. 31, 2018USD ($)shares | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
May 2015 [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Restricted stock expense | $ 0.3 | |||||||
May 2016 [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Restricted stock expense | $ 0.2 | $ 0.3 | ||||||
May 2017 [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Restricted stock expense | $ 0.1 | 0.2 | ||||||
May 2018 [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Restricted stock expense | $ 0.3 | |||||||
Restricted Stock [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Stock-based compensation awards, requisite service period | 3 years | |||||||
Restricted Stock [Member] | May 2015 [Member] | Board of Directors [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Restricted shares of common stock issued | shares | 8,833 | |||||||
Number of non employee directors | Director | 7 | |||||||
Restricted Stock [Member] | May 2016 [Member] | Board of Directors [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Restricted shares of common stock issued | shares | 9,963 | |||||||
Number of non employee directors | Director | 3 | |||||||
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] | ||||||||
Unrecognized compensation cost | $ 0.1 | |||||||
Restricted shares of common stock issued | shares | 15,476 | |||||||
Number of non employee directors | Director | 3 | |||||||
Restricted Stock Units [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Stock-based compensation awards, requisite service period | 3 years | |||||||
Unrecognized compensation cost | $ 4 | |||||||
Weighted average period for shares to vest | 1 year | |||||||
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 | $ 3.5 | |||||||
Weighted average period for shares to vest | 1 year | |||||||
Fair value of performance stock units vested | $ 0.8 | |||||||
BRMR and Everest Merger Sub Inc. [Member] | Common Stock [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Reverse stock split, description | 15-to-1 | |||||||
Reverse stock split | 0.066 | |||||||
2014 Long-Term Incentive Plan [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Number of shares authorized to be issue | shares | 25,000,000 | |||||||
Number of shares are available for future grant | shares | 7,145,866 |
Stock-Based Compensation - Sche
Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | $ 7,891 | $ 9,301 | $ 6,216 |
Restricted Stock Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | 4,014 | 5,301 | 4,006 |
Performance Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | 3,497 | 3,622 | 1,922 |
Restricted Stock Issued to Directors [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | $ 380 | $ 378 | 556 |
Incentive Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | $ (268) |
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 | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of shares, Beginning Balance | 270,490 | |
Number of shares, Granted | 99,901 | |
Number of shares, Vested | (132,406) | |
Number of shares, Forfeited | (4,025) | |
Number of shares, Ending Balance | 233,960 | |
Weighted average grant date fair value, Beginning Balance | $ 37.20 | |
Weighted average grant date fair value, Granted | 25.50 | |
Weighted average grant date fair value, Vested | 42.42 | |
Weighted average grant date fair value, Forfeited | 31.30 | |
Weighted average grant date fair value, Ending Balance | $ 29.27 | |
Aggregate intrinsic value | $ 3,685 | $ 9,738 |
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 | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of shares, Beginning Balance | 264,425 | |
Number of shares, Granted | 99,901 | |
Number of shares, Vested | (11,536) | |
Number of shares, Forfeited | (6,201) | |
Number of shares, Ending Balance | 346,589 | |
Weighted average grant date fair value, Beginning Balance | $ 27.30 | |
Weighted average grant date fair value, Granted | 28.80 | |
Weighted average grant date fair value, Vested | 27.51 | |
Weighted average grant date fair value, Forfeited | 27.61 | |
Weighted average grant date fair value, Ending Balance | $ 27.68 | |
Aggregate intrinsic value | $ 716 | $ 11,257 |
Stock-Based Compensation - Assu
Stock-Based Compensation - Assumptions Used to Determine Fair Value of Performance Stock Units Granted (Detail) - Performance Units [Member] | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Volatility | 89.70% | 50.41% | 49.84% |
Risk-free interest rate | 2.37% | 1.34% | 0.96% |
Equity - Additional Information
Equity - Additional Information (Detail) - Underwritten Public Offering [Member] - USD ($) $ / shares in Units, $ in Millions | Jul. 05, 2016 | Jun. 28, 2016 |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||
Shares Issued | 2,500,000 | |
Stock price, per share | $ 52.50 | |
Proceeds from initial public offering | $ 123.8 |
Earnings (Loss) Per Share - Add
Earnings (Loss) Per Share - Additional Infoamation (Details) - BRMR and Everest Merger Sub Inc. [Member] - Common Stock [Member] - Subsequent Event [Member] | Feb. 28, 2019 |
Business Acquisition [Line Items] | |
Reverse stock split, description | 15-to-1 |
Reverse stock split | 0.066 |
Earnings (Loss) Per Share - Sch
Earnings (Loss) Per Share - Schedule of Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Basic: | |||||||||||
Net income (loss), basic | $ 18,826 | $ 8,525 | $ (206,735) | ||||||||
Net income (loss), shares, basic | 19,999 | 17,479 | 16,096 | ||||||||
Net income (loss), per share, basic | $ 1.81 | $ 0.20 | $ (0.95) | $ (0.13) | $ (0.75) | $ (0.95) | $ 0.66 | $ 1.54 | $ 0.94 | $ 0.49 | $ (12.84) |
Weighted-average number of shares of common stock-diluted: | |||||||||||
Restricted stock and performance unit awards | 88 | 200 | |||||||||
Diluted: | |||||||||||
Net income (loss), diluted | $ 18,826 | $ 8,525 | $ (206,735) | ||||||||
Net income (loss), shares, diluted | 20,087 | 17,679 | 16,096 | ||||||||
Net income (loss), per share, diluted | $ 1.80 | $ 0.20 | $ (0.95) | $ (0.13) | $ (0.74) | $ (0.95) | $ 0.65 | $ 1.52 | $ 0.94 | $ 0.48 | $ (12.84) |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Former Chairman, President and Chief Executive Officer [Member] | |||
Related Party Transaction [Line Items] | |||
Flight charter services fees | $ 0.6 | $ 0.6 | $ 0.6 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |||
Lease agreement, term | The Company leases office space under an operating lease that expires in 2024. | ||
Rent expense | $ 0.6 | $ 0.6 | $ 0.9 |
Commitments and Contingencies_2
Commitments and Contingencies - Future Minimum Lease Payments Required Under Lease Agreements (Detail) $ in Thousands | Dec. 31, 2018USD ($) |
Commitments And Contingencies Disclosure [Abstract] | |
2019 | $ 1,360 |
2020 | 1,060 |
2021 | 929 |
2022 | 755 |
2023 | 755 |
Thereafter | 1,619 |
Total minimum lease payments | $ 6,478 |
Commitments and Contingencies_3
Commitments and Contingencies - Other Commitments (Detail) $ in Thousands | Dec. 31, 2018USD ($) | |
Other Commitments [Line Items] | ||
2019 | $ 107,641 | |
2020 | 103,189 | |
2021 | 98,230 | |
2022 | 100,523 | |
2023 | 98,598 | |
Thereafter | 762,472 | |
Total | 1,270,653 | |
Drilling Rig Commitments [Member] | ||
Other Commitments [Line Items] | ||
2019 | 1,287 | [1] |
Total | 1,287 | [1] |
Firm Transportation [Member] | ||
Other Commitments [Line Items] | ||
2019 | 80,083 | [2] |
2020 | 80,303 | [2] |
2021 | 80,083 | [2] |
2022 | 80,083 | [2] |
2023 | 80,083 | [2] |
Thereafter | 700,549 | [2] |
Total | 1,101,184 | [2] |
Gas Processing, Gathering, and Compression Services [Member] | ||
Other Commitments [Line Items] | ||
2019 | 26,271 | [3] |
2020 | 22,886 | [3] |
2021 | 18,147 | [3] |
2022 | 20,440 | [3] |
2023 | 18,515 | [3] |
Thereafter | 61,923 | [3] |
Total | $ 168,182 | [3] |
[1] | Drilling rig commitments - The Company had contracts for the service of two rigs, which have both expired and the Company has entered into well-to-well contracts. 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, as applicable. | |
[2] | 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. | |
[3] | 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. |
Commitments and Contingencies_4
Commitments and Contingencies - Other Commitments (Parenthetical) (Detail) | Dec. 31, 2018Rig |
Commitments And Contingencies Disclosure [Abstract] | |
Number of drilling rigs under service contract | 2 |
Income Tax - Additional Informa
Income Tax - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax [Line Items] | |||
Percentage of annual effective income tax rate | 0.00% | ||
Pre-tax book income | $ 18,826,000 | $ 8,525,000 | $ (206,189,000) |
U.S. federal tax loss carryforwards ("NOL") | 667,000,000 | ||
Valuation allowance | 208,324,000 | 213,800,000 | 359,098,000 |
Reserve for uncertain tax positions | 0 | $ 0 | $ 0 |
Federal [Member] | |||
Income Tax [Line Items] | |||
U.S. federal tax loss carryforwards ("NOL") | $ 667,000,000 | ||
Tax loss carryforwards expiration year | 2034 |
Income Tax - Segregation of Inc
Income Tax - Segregation of Income Tax Provision Based on Location of Operations (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current | |||
Federal | $ 0 | $ 0 | $ 0 |
State | 6 | ||
Total current | 6 | ||
Deferred | |||
State | 540 | ||
Total deferred | 540 | ||
Total income tax expense (benefit) | $ 546 |
Income Tax - Schedule of Effect
Income Tax - Schedule of Effective Income Tax Rate Reconciliation (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Income (loss) before income taxes | $ 18,826 | $ 8,525 | $ (206,189) |
Statutory rate | 21.00% | 35.00% | 35.00% |
Income tax benefit computed at statutory rate | $ 3,953 | $ 2,984 | $ (72,166) |
Reconciling items: | |||
State income taxes | 546 | ||
Other, net | 54 | 50 | 854 |
Share-based compensation | 1,201 | (576) | |
Executive compensation limitation | 268 | 496 | |
Change in valuation allowance | $ (5,476) | (145,449) | 71,312 |
Change in Federal tax rate | $ 142,495 | ||
Total income tax expense (benefit) | $ 546 |
Income Tax - Components of Defe
Income Tax - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred tax asset: | |||
Oil and gas properties and equipment | $ 62,616 | $ 93,854 | $ 193,095 |
Federal tax loss carryforwards | 140,059 | 114,652 | 145,628 |
Derivative instruments and other | 1,064 | 16,829 | |
Other, net | 7,398 | 4,639 | 4,259 |
Deferred tax asset | 210,073 | 214,209 | 359,811 |
Valuation allowance | (208,324) | (213,800) | (359,098) |
Net deferred tax assets | 1,749 | 409 | 713 |
Deferred tax liability: | |||
Derivative instruments and other | 1,197 | ||
Other, net | 552 | 409 | 713 |
Net deferred tax liability | $ 1,749 | $ 409 | $ 713 |
Subsidiary Guarantors - Additio
Subsidiary Guarantors - Additional Information (Detail) | Dec. 31, 2018 | Jul. 06, 2015 |
8.875% Senior Unsecured Notes Due 2023 [Member] | ||
Guarantee Obligations [Line Items] | ||
Debt instrument interest rate | 8.875% | 8.875% |
Quarterly Financial Informati_3
Quarterly Financial Information (unaudited) - Additional Infoamation (Details) - BRMR and Everest Merger Sub Inc. [Member] - Common Stock [Member] - Subsequent Event [Member] | Feb. 28, 2019 |
Business Acquisition [Line Items] | |
Reverse stock split, description | 15-to-1 |
Reverse stock split | 0.066 |
Quarterly Financial Informati_4
Quarterly Financial Information (unaudited) (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total operating revenues | $ 171,208 | $ 130,123 | $ 103,622 | $ 110,192 | $ 104,056 | $ 91,549 | $ 86,191 | $ 101,863 | $ 515,145 | $ 383,659 | $ 235,034 |
Total operating expenses | 123,590 | 108,929 | 92,989 | 95,651 | 108,431 | 94,338 | 80,589 | 87,632 | 421,159 | 370,990 | 352,436 |
Operating income (loss) | 47,618 | 21,194 | 10,633 | 14,541 | (4,375) | (2,789) | 5,602 | 14,231 | 93,986 | 12,669 | (117,402) |
Net income (loss) | $ 36,490 | $ 3,998 | $ (19,036) | $ (2,626) | $ (13,122) | $ (16,694) | $ 11,494 | $ 26,847 | $ 18,826 | $ 8,525 | $ (206,735) |
Income (loss) per common share: | |||||||||||
Basic | $ 1.81 | $ 0.20 | $ (0.95) | $ (0.13) | $ (0.75) | $ (0.95) | $ 0.66 | $ 1.54 | $ 0.94 | $ 0.49 | $ (12.84) |
Diluted | $ 1.80 | $ 0.20 | $ (0.95) | $ (0.13) | $ (0.74) | $ (0.95) | $ 0.65 | $ 1.52 | $ 0.94 | $ 0.48 | $ (12.84) |
Supplemental Oil and Natural _3
Supplemental Oil and Natural Gas Information - Summary of Capitalized Costs (Detail) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Oil and natural gas properties: | ||
Unproved properties | $ 482,475 | $ 459,549 |
Proved properties | 2,188,233 | 1,896,081 |
Total oil and natural gas properties | 2,670,708 | 2,355,630 |
Less accumulated depreciation, depletion and amortization | (1,380,650) | (1,248,200) |
Net oil and natural gas properties | $ 1,290,058 | $ 1,107,430 |
Supplemental Oil and Natural _4
Supplemental Oil and Natural Gas Information - Summary of Costs Incurred in Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Acquisition costs: | |||
Unproved properties | $ 107,862 | $ 57,498 | $ 24,764 |
Proved properties | 4,072 | ||
Development cost | 239,467 | 257,119 | 150,778 |
Exploration cost | 20,957 | 18,791 | 20,127 |
Total acquisition, development and exploration costs | $ 372,358 | $ 333,408 | $ 195,669 |
Supplemental Oil and Natural _5
Supplemental Oil and Natural Gas Information - Proved Developed and Proved Undeveloped Reserves (Detail) | 12 Months Ended | |||
Dec. 31, 2018BcfeBcfMBbls | Dec. 31, 2017BcfeBcfMBbls | Dec. 31, 2016BcfeBcfMBbls | Dec. 31, 2015BcfeBcfMBbls | |
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves (energy), beginning balance | Bcfe | 1,458.6 | 469.4 | 348.8 | |
Revisions (energy) | Bcfe | (42.8) | 695.6 | 14.8 | |
Extensions and discoveries (energy) | Bcfe | 558.1 | 405.1 | 196.1 | |
Acquisitions (energy) | Bcfe | 16.3 | 1.9 | 4.1 | |
Divestitures (energy) | Bcfe | (0.2) | (10.7) | ||
Production (energy) | Bcfe | (125.3) | (113.4) | (83.7) | |
Proved Developed and Undeveloped Reserves (energy), ending balance | Bcfe | 1,864.7 | 1,458.6 | 469.4 | |
Proved developed reserves (energy) | Bcfe | 670.7 | 456 | 297.8 | 278.4 |
Proved undeveloped reserves (energy) | Bcfe | 1,194.1 | 1,002.6 | 171.6 | 70.3 |
Natural Gas [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, beginning balance | Bcf | 1,090.1 | 386.4 | 274.1 | |
Revisions | Bcf | 5.6 | 515.1 | (0.1) | |
Extensions and discoveries | Bcf | 515.8 | 274.4 | 175.4 | |
Acquisitions | Bcf | 9.9 | 1.6 | 3.8 | |
Divestitures | Bcf | (0.2) | (5.9) | ||
Production | Bcf | (90) | (87.4) | (60.9) | |
Proved Developed and Undeveloped Reserves, ending balance | Bcf | 1,531.2 | 1,090.1 | 386.4 | |
Proved developed reserves | Bcf | 501 | 334.6 | 226.1 | 209.5 |
Proved undeveloped reserves | Bcf | 1,030.2 | 755.5 | 160.4 | 64.5 |
Natural Gas Liquids [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, beginning balance | 41,930.6 | 8,675.5 | 7,758.7 | |
Revisions | (8,307.5) | 20,327.3 | 1,273.7 | |
Extensions and discoveries | 4,059.4 | 15,598.8 | 2,156 | |
Acquisitions | 551 | 42.6 | 24.8 | |
Divestitures | (91.5) | |||
Production | (3,503) | (2,713.6) | (2,446.2) | |
Proved Developed and Undeveloped Reserves, ending balance | 34,730.9 | 41,930.6 | 8,675.5 | |
Proved developed reserves | 20,213.8 | 13,782.9 | 7,520 | 7,245.7 |
Proved undeveloped reserves | 14,517.2 | 28,147.7 | 1,155.5 | 513 |
Oil [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, beginning balance | 19,480.8 | 5,157.7 | 4,693.1 | |
Revisions | 231.2 | 9,746.8 | 1,196.8 | |
Extensions and discoveries | 2,995.7 | 6,192.9 | 1,300.2 | |
Acquisitions | 522 | 5.8 | 15.1 | |
Divestitures | (703.7) | |||
Production | (2,377.8) | (1,622.4) | (1,343.8) | |
Proved Developed and Undeveloped Reserves, ending balance | 20,852.1 | 19,480.8 | 5,157.7 | |
Proved developed reserves | 8,058.7 | 6,449.6 | 4,439.5 | 4,239.2 |
Proved undeveloped reserves | 12,793.4 | 13,031.2 | 718.1 | 453.9 |
Supplemental Oil And Natural _6
Supplemental Oil And Natural Gas Information - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2018Bcfe | Dec. 31, 2017BcfeWell | Dec. 31, 2016Bcfe | |
Reserve Quantities [Line Items] | |||
Extensions | 558.1 | 405.1 | 196.1 |
Revisions | (42.8) | 695.6 | 14.8 |
Revisions due to (reductions) improvements in SEC pricing | 15 | 607.2 | (50.8) |
Revisions due to changes in differentials | 6.8 | 61.4 | (17.9) |
Revision due to outperforming previous estimate | 67.5 | 69.6 | 83.5 |
Acquisition of proved developed and proved undeveloped leasehold acreage | 16.3 | 1.9 | 4.1 |
Divestiture of proved developed and proved undeveloped leasehold acreage | 0.2 | 10.7 | |
Developments | 148.3 | ||
Revisions offset due to decision to not develop certain proved, undeveloped reserves within five years | 42.6 | ||
Revisions offset due to change in well spacing | (98) | ||
Revisions offset due to change in five year development plan | (34.1) | ||
Discount Rate [Member] | Valuation Technique, Discounted Cash Flow [Member] | |||
Reserve Quantities [Line Items] | |||
Discount rate | 10 | ||
Utica [Member] | |||
Reserve Quantities [Line Items] | |||
Developments | 361 | ||
Number of nonproductive development wells | Well | 1 | ||
Utica [Member] | Non-operated Well [Member] | |||
Reserve Quantities [Line Items] | |||
Developments | 0.3 | ||
Utica [Member] | Operated Assets [Member] | |||
Reserve Quantities [Line Items] | |||
Developments | 398.2 | ||
Ohio Marcellus [Member] | |||
Reserve Quantities [Line Items] | |||
Developments | 43.8 | ||
Number of productive development wells | Well | 3 | ||
Marcellus Shale [Member] | Operated Assets [Member] | |||
Reserve Quantities [Line Items] | |||
Developments | 11.6 |
Supplemental Oil and Natural _7
Supplemental Oil and Natural Gas Information - Standardized Measure of Discounted Net Future Cash Flows (Detail) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract] | ||||
Future cash inflows (total revenues) | $ 6,730,000 | $ 4,750,238 | $ 1,143,142 | |
Future production costs | (2,964,098) | (2,332,310) | (725,724) | |
Future development costs (capital costs) | (855,932) | (879,399) | (116,988) | |
Future income tax expense | (136,472) | |||
Future net cash flows | 2,773,498 | 1,538,529 | 300,430 | |
10% annual discount for estimated timing of cash flows | (1,444,188) | (808,843) | (94,449) | |
Standardized measure of Discounted Future Net Cash Flow | $ 1,329,310 | $ 729,686 | $ 205,981 | $ 212,865 |
Supplemental Oil and Natural _8
Supplemental Oil and Natural Gas Information - Changes in Standardized Measure of Discounted Net Cash Flows (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized Measure, beginning of the year | $ 729,686 | $ 205,981 | $ 212,865 |
Net change in prices and production costs | 369,578 | 653,347 | (33,507) |
Net change in future development costs | 87,466 | (385,042) | 1,552 |
Sales, less production costs | (321,802) | (226,324) | (99,768) |
Extensions | 363,708 | 135,734 | 79,941 |
Acquisitions | 7,468 | 2,365 | 1,045 |
Divestitures | (20) | (5,231) | |
Revisions of previous quantity estimates | 19,910 | 322,917 | 15,754 |
Previously estimated development costs incurred | 65,035 | 34,102 | 4,886 |
Net changes in taxes | (37,345) | ||
Accretion of discount | 72,969 | 20,598 | 21,287 |
Changes in timing and other | (27,343) | (33,992) | 7,157 |
Standardized Measure, end of year | $ 1,329,310 | $ 729,686 | $ 205,981 |