Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Mar. 05, 2020 | Jun. 28, 2019 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Montage Resources Corporation | ||
Entity Central Index Key | 0001600470 | ||
Entity Current Reporting Status | Yes | ||
Entity Shell Company | false | ||
Entity File Number | 001-36511 | ||
Entity Tax Identification Number | 46-4812998 | ||
Entity Address, Address Line One | 122 West John Carpenter Freeway | ||
Entity Address, Address Line Two | Suite 300 | ||
Entity Address, City or Town | Irving | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 75039 | ||
City Area Code | 469 | ||
Local Phone Number | 444-1647 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Accelerated Filer | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
Entity Common Stock, Shares Outstanding | 35,826,888 | ||
Entity Public Float | $ 129.1 | ||
Entity Interactive Data Current | Yes | ||
Entity Incorporation, State or Country Code | DE | ||
Document Annual Report | true | ||
Document Transition Report | false | ||
Title of 12(b) Security | Common Stock, Par Value $0.01 Per Share | ||
Trading Symbol | MR | ||
Security Exchange Name | NYSE | ||
Documents Incorporated by Reference | Documents incorporated by reference: Portions of the registrant’s proxy statement for its 2020 annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days after the registrant’s fiscal year end are incorporated by reference into Part III of this Annual Report on Form 10-K. |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 12,056 | $ 5,959 |
Accounts receivable | 77,402 | 119,332 |
Assets held for sale | 1,047 | |
Other current assets | 35,509 | 8,639 |
Total current assets | 126,014 | 133,930 |
Oil and natural gas properties, successful efforts method: | ||
Unproved properties | 508,576 | 482,475 |
Proved oil and gas properties, net | 1,251,105 | 807,583 |
Other property and equipment, net | 11,226 | 6,300 |
Total property and equipment, net | 1,770,907 | 1,296,358 |
OTHER NONCURRENT ASSETS | ||
Other assets | 7,616 | 3,481 |
Operating lease right-of-use assets | 36,975 | |
Assets held for sale | 9,665 | |
TOTAL ASSETS | 1,951,177 | 1,433,769 |
CURRENT LIABILITIES | ||
Accounts payable | 119,907 | 116,735 |
Accrued capital expenditures | 43,500 | 12,979 |
Accrued liabilities | 53,866 | 56,909 |
Accrued interest payable | 21,308 | 21,661 |
Liabilities associated with assets held for sale | 2,815 | |
Operating lease liability | 12,666 | |
Total current liabilities | 254,062 | 208,284 |
NONCURRENT LIABILITIES | ||
Debt, net of unamortized discount and debt issuance costs | 500,541 | 497,778 |
Revolving credit facility | 130,000 | 32,500 |
Asset retirement obligations | 29,877 | 7,110 |
Other liabilities | 8,029 | 611 |
Operating lease liability | 24,569 | |
Liabilities associated with assets held for sale | 7,013 | |
Total liabilities | 954,091 | 746,283 |
COMMITMENTS AND CONTINGENCIES | ||
STOCKHOLDERS' EQUITY | ||
Preferred stock, 50,000,000 authorized, no shares issued and outstanding | ||
Common stock, $0.01 par value, 1,000,000,000 authorized, 35,770,934 and 20,169,063 shares issued and outstanding, respectively | 383 | 3,043 |
Additional paid in capital | 2,352,309 | 2,065,119 |
Treasury stock, shares at cost; 2,508,485 and 1,747,624 shares, respectively | (10,049) | (3,357) |
Accumulated deficit | (1,345,557) | (1,377,319) |
Total stockholders’ equity | 997,086 | 687,486 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ 1,951,177 | $ 1,433,769 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Statement Of Financial Position [Abstract] | ||
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 1,000,000,000 | 1,000,000,000 |
Common stock, shares issued | 35,770,934 | 20,169,063 |
Common stock, shares outstanding | 35,770,934 | 20,169,063 |
Treasury stock, shares | 2,508,485 | 1,747,624 |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
REVENUES | |||
Revenues | $ 634,441 | $ 515,145 | $ 383,659 |
OPERATING EXPENSES | |||
Lease operating | 43,359 | 28,289 | 20,525 |
Transportation, gathering and compression | $ 208,826 | $ 138,766 | $ 124,839 |
Cost, Product and Service [Extensible List] | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember | us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember |
Production and ad valorem taxes | $ 12,141 | $ 10,141 | $ 8,490 |
Brokered natural gas and marketing expense | 42,700 | 16,886 | 3,191 |
Depreciation, depletion, amortization and accretion | 156,003 | 134,940 | 119,362 |
Exploration | 58,917 | 49,563 | 50,208 |
General and administrative | 70,941 | 44,389 | 44,553 |
Rig termination and standby | 1,081 | 1 | |
Gain on sale of assets | (476) | (1,815) | (179) |
Other expense | 60 | ||
Total operating expenses | 593,552 | 421,159 | 370,990 |
OPERATING INCOME | 40,889 | 93,986 | 12,669 |
OTHER INCOME (EXPENSE) | |||
Gain (loss) on derivative instruments | 48,596 | (21,169) | 45,365 |
Interest expense, net | (59,055) | (53,990) | (49,490) |
Other income (expense) | 16 | (1) | (19) |
Total other expense, net | (10,443) | (75,160) | (4,144) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 30,446 | 18,826 | 8,525 |
INCOME FROM CONTINUING OPERATIONS | 30,446 | 18,826 | 8,525 |
Income from discontinued operations, net of income tax | 1,316 | ||
NET INCOME | $ 31,762 | $ 18,826 | $ 8,525 |
Basic: | |||
Weighted average common stock outstanding | 33,211 | 19,999 | 17,479 |
Income from continuing operations | $ 0.92 | $ 0.94 | $ 0.49 |
Income from discontinued operations | 0.04 | ||
Net income | $ 0.96 | $ 0.94 | $ 0.49 |
Diluted: | |||
Weighted average common stock outstanding | 33,324 | 20,087 | 17,679 |
Income from continuing operations | $ 0.91 | $ 0.94 | $ 0.48 |
Income from discontinued operations | 0.04 | ||
Net income | $ 0.95 | $ 0.94 | $ 0.48 |
Oil and Gas [Member] | |||
REVENUES | |||
Revenues | $ 591,699 | $ 498,593 | $ 380,178 |
Brokered Natural Gas and Marketing Revenue [Member] | |||
REVENUES | |||
Revenues | 42,274 | $ 16,552 | $ 3,481 |
Other Revenue [Member] | |||
REVENUES | |||
Revenues | $ 468 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Treasury Stock [Member] | Accumulated Deficit [Member] |
Beginning Balances at Dec. 31, 2016 | $ 556,607 | $ 2,607 | $ 1,958,731 | $ (61) | $ (1,404,670) |
Beginning Balance, shares at Dec. 31, 2016 | 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) | |||
Issuance of restricted stock | $ 2 | (2) | |||
Issuance of restricted stock, shares | 15,476 | ||||
Shares of common stock issued in asset acquisition, net of equity issuance costs | 90,020 | $ 378 | 89,642 | ||
Shares of common stock issued in asset acquisition, net of equity issuance costs, shares | 2,521,573 | ||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings | (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 | ||||
Stock-based compensation | 8,784 | 8,784 | |||
Equity issuance costs | (30) | (30) | |||
Shares of common stock issued in asset acquisition, net of equity issuance costs | 275,759 | $ 150 | 275,609 | ||
Shares of common stock issued in asset acquisition, net of equity issuance costs, shares | 15,013,520 | ||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings | (6,675) | $ 23 | (6) | (6,692) | |
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares | 588,351 | ||||
Reverse split | $ (2,833) | 2,833 | |||
Net income (loss) | 31,762 | 31,762 | |||
Ending Balances at Dec. 31, 2019 | $ 997,086 | $ 383 | $ 2,352,309 | $ (10,049) | $ (1,345,557) |
Ending Balance, shares at Dec. 31, 2019 | 35,770,934 |
Consolidated Statements of St_2
Consolidated Statements of Stockholders' Equity (Parenthetical) | 12 Months Ended | ||
Dec. 31, 2019$ / shares | Dec. 31, 2018$ / shares | Dec. 31, 2017$ / shares | |
Statement Of Stockholders Equity [Abstract] | |||
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 |
Reverse split ratio | 0.067 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income | $ 31,762 | $ 18,826 | $ 8,525 |
Adjustments to reconcile net income to net cash provided by operating activities | |||
Depreciation, depletion, amortization and accretion | 156,552 | 134,940 | 119,362 |
Exploration expense | 47,775 | 28,324 | 31,417 |
Stock-based compensation | 8,784 | 7,891 | 9,301 |
Net cash for plugging wells | (1,044) | ||
(Gain) loss on derivative instruments | (48,596) | 21,169 | (45,365) |
Net cash receipts (payments) on settled derivatives | 20,323 | (26,985) | (2,224) |
Gain on sale of assets | (601) | (1,815) | (179) |
Amortization of deferred financing costs | 2,781 | 2,256 | 2,098 |
Amortization of debt discount | 1,330 | 1,327 | 1,324 |
Changes in operating assets and liabilities: | |||
Accounts receivable | 67,652 | (42,879) | (31,780) |
Other assets | 1,893 | (2,192) | 1,863 |
Accounts payable and accrued liabilities | (33,182) | 84,231 | 18,404 |
Net cash provided by operating activities | 255,429 | 225,093 | 112,746 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Capital expenditures for oil and gas properties | (349,710) | (275,601) | (291,779) |
Capital expenditures for other property and equipment | (632) | (1,007) | (2,007) |
Proceeds from sale of assets | 1,959 | 10,358 | 1,317 |
Cash acquired in merger | 12,894 | ||
Change in deposits and other long-term assets | (53) | ||
Net cash used in investing activities | (335,542) | (266,250) | (292,469) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Debt issuance costs | (4,264) | (497) | (1,750) |
Repayments of long-term debt | (321) | (506) | (453) |
Proceeds from revolving credit facility | 97,500 | 32,500 | |
Equity issuance costs | (30) | (344) | (44) |
Employee tax withholding for settlement of equity compensation awards | (6,675) | (1,261) | (2,035) |
Net cash provided by (used in) financing activities | 86,210 | 29,892 | (4,282) |
Net increase (decrease) in cash and cash equivalents | 6,097 | (11,265) | (184,005) |
Cash and cash equivalents at beginning of period | 5,959 | 17,224 | 201,229 |
Cash and cash equivalents at end of period | 12,056 | 5,959 | 17,224 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | |||
Cash paid for interest | 59,552 | 51,101 | 47,362 |
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES | |||
Asset retirement obligations incurred, including changes in estimate | 2,898 | 418 | 679 |
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 | 17,725 | (15,269) | 22,264 |
Assets held for sale | $ (262) | ||
Asset acquisition through stock issuance | $ 90,020 | ||
BRMR Merger consideration | $ 275,759 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2019 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Organization and Nature of Operations | Note 1—Organization and Nature of Operations Montage Resources Corporation (the “Company”), is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale, Indian Castle/Flat Creek Shales and Marcellus Shale prospective areas. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 and 2018, and the results of its operations, comprehensive income (loss) and its cash flows for the years ended December 31, 2019, 2018, and 2017. Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. The Company’s management believes the major estimates and assumptions impacting the Consolidated Financial Statements are the following: • estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion, amortization and accretion and impairment of capitalized costs of oil and natural gas properties; • estimates of asset retirement obligations; • estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells; • impairment of undeveloped properties and other assets; and • depreciation and depletion of property and equipment. Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions. (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. 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 had no significant accounts receivables determined to be uncollectable as of December 31, 2019 or December 31, 2018. The Company accrues revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. (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, amortization and accretion expense (See “Depreciation, Depletion, Amortization and Accretion ” below). Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s 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, 2019 December 31, 2018 Oil and natural gas properties: Unproved $ 508,576 $ 482,475 Proved 2,783,232 2,188,233 Gross oil and natural gas properties 3,291,808 2,670,708 Less accumulated depreciation, depletion and amortization (1,532,127 ) (1,380,650 ) Oil and natural gas properties, net 1,759,681 1,290,058 Other property and equipment 20,000 14,460 Less accumulated depreciation (8,774 ) (8,160 ) Other property and equipment, net 11,226 6,300 Property and equipment, net $ 1,770,907 $ 1,296,358 Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. 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, 2019 December 31, 2018 Trade payables $ 20,232 $ 27,481 Royalty payables 76,642 70,019 Production & ad valorem taxes 1,025 1,811 Derivative payable 112 4,736 Other payables 21,896 12,688 Total accounts payable $ 119,907 $ 116,735 A summary of accrued liabilities is as follows (in thousands): December 31, 2019 December 31, 2018 Ad valorem and production taxes $ 9,830 $ 6,193 Employee compensation 9,375 6,595 Royalties 23,311 39,969 Short term derivatives 1,362 — Other 9,988 4,152 Total accrued liabilities $ 53,866 $ 56,909 (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 receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense. NGLs The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company 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 and certain costs incurred by third parties. 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, 2019 2018 2017 Revenues (in thousands) Natural gas sales $ 361,318 $ 274,239 $ 241,379 NGL sales 84,552 86,152 64,109 Oil sales 145,829 138,202 74,690 Brokered natural gas and marketing revenue 42,274 16,552 3,481 Other revenue 468 — — Total revenues $ 634,441 $ 515,145 $ 383,659 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 $63.7 million and $94.1 million at December 31, 2019 and December 31, 2018, respectively. (g) Major Customers The Company sells production volumes to various purchasers. For the years ended December 31, 2019, 2018, and 2017, there were two, one and two 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, 2019 2018 2017 Purchaser BP Energy Company 23% — — Emera Energy Services — — 17% Marathon Petroleum 20% 25% 10% Total 43% 25% 27% 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, 2019 and December 31, 2018 (in thousands): December 31, 2019 December 31, 2018 Receivables by product or service: Sale of oil and natural gas and related products and services $ 63,730 $ 94,107 Joint interest owners 12,156 24,830 Derivatives 210 372 Other 1,306 23 Total $ 77,402 $ 119,332 Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in Ohio, Pennsylvania and West Virginia. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, 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 $27.1 million and $5.7 million at December 31, 2019 and 2018, 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, 2019, the Company did not have past-due receivables from or payables to any of the counterparties. (i) Depreciation, Depletion, Amortization and Accretion Oil and Natural Gas Properties Depreciation, depletion, amortization and accretion (“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, 2019, 2018, and 2017 totaled approximately $153.8 million, $133.2 million and $117.3 million, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Consolidated Financial Statements. 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, 2019, 2018, and 2017 totaled approximately $2.2 million, $1.8 million and $2.0 million, respectively. This amount is included in depreciation, depletion, amortization and accretion 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. There were no impairments of proved properties for the years ended December 31, 2019, 2018, and 2017. When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $45.8 million, $27.6 million, and $28.3 million for the years ended December 31, 2019, 2018, and 2017, 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, 2019 2018 2017 Asset retirement obligations, beginning of period $ 7,110 $ 6,029 $ 4,806 Accretion 2,368 663 544 Additional liabilities incurred 2,379 418 679 Obligation for wells acquired 20,188 — — Obligation for wells drilled 519 — — Liabilities settled via plugging (723 ) — — Less: current ARO portion (accrued liabilities) (1,964 ) — — Asset retirement obligations, end of period $ 29,877 $ 7,110 $ 6,029 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) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. (p) 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. (q) 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 Consolidated 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. During the years ended December 31, 2019, 2018, and 2017, the Company amortized $4.1 million, $3.6 million and $3.4 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method. (r) Recent Accounting Pronouncements Recently Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Entities are required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases’ classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements.” The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements,” which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption. The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third-party-sponsored lease accounting information system to facilitate the accounting and financial reporting requirements and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment. See Note 6 – Leases Accounting Pronouncements Not Yet Adopted In June 2016, the FASB issued ASU 2016-13, “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments ” |
Acquisition
Acquisition | 12 Months Ended |
Dec. 31, 2019 | |
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 Indian Castle and Flat Creek Shales, to a third party. The third party exercised its option to purchase all of the outstanding equity interests of Cardinal in July 2018. Merger with Blue Ridge Mountain Resources On February 28, 2019, the Company completed its previously announced business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”). As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 15-to-1 (See Note 12— Net Income (Loss) Per Share ) In connection with the BRMR Merger, the Company incurred approximately $25.5 million and $4.0 million of costs for the years ended December 31, 2019 and 2018, respectively, which are included in General and administrative expense on the Consolidated Statements of Operations and Comprehensive Income (Loss). Approximately $131.7 million of revenues and approximately $14.0 million of net income from continuing operations are attributed to the BRMR Merger are included in the Company’s Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019. Approximately $7.2 million of revenues and approximately $1.3 million of net income from discontinued operations are attributed to the BRMR Merger are included in the Company’s Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019. The following table summarizes the purchase price allocation and the values of assets acquired and liabilities assumed (in thousands): Purchase Price February 28, 2019 Fair value of the Company's common stock issued $ 263,487 Fair value of BRMR share-based and other compensation 12,272 Total Fair Value of Consideration $ 275,759 Cash and cash equivalents 12,894 Accounts receivable 25,884 Assets held for sale - current 2,296 Other current assets 1,702 Unproved properties 80,843 Proved oil and gas properties 218,866 Other property and equipment 7,059 Other assets 2,461 Operating lease right-of-use asset 7,900 Assets held for sale - long-term 9,611 Total assets acquired $ 369,516 Accounts payable (16,571 ) Accrued capital expenditures (5,807 ) Accrued liabilities (28,824 ) Operating lease liability - current (1,979 ) Liabilities associated with assets held for sale - current (7,683 ) Asset retirement obligations (20,188 ) Operating lease liability - noncurrent (5,923 ) Liabilities associated with assets held for sale - long-term (6,782 ) Total liabilities assumed $ (93,757 ) Net identifiable assets $ 275,759 The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighed average cost of capital rate. The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin. These inputs required significant judgements and estimates by management at the time of the valuation and are the most sensitive to possible future changes. The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2018. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results. For the Year Ended December 31, (in thousands, except per share data) (unaudited) 2019 2018 Pro forma total revenues $ 677,099 $ 698,850 Pro forma net income $ 44,536 $ 5,919 Pro forma net income per share (basic) $ 1.25 $ 0.17 Pro forma net income per share (diluted) $ 1.24 $ 0.16 |
Sale of Oil and Natural Gas Pro
Sale of Oil and Natural Gas Property Interests | 12 Months Ended |
Dec. 31, 2019 | |
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, 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. |
Assets Held for Sale and Discon
Assets Held for Sale and Discontinued Operations | 12 Months Ended |
Dec. 31, 2019 | |
Discontinued Operations And Disposal Groups [Abstract] | |
Assets Held for Sale and Discontinued Operations | Note 5—Assets Held for Sale and Discontinued Operations Assets Held for Sale As a result of the BRMR Merger, the Company acquired certain assets that met the criteria for assets held for sale at the acquisition date, comprised of the net assets of Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of BRMR. These assets are located primarily in Kentucky and Tennessee. The following summarizes assets and liabilities held for sale at December 31, 2019: (in thousands) December 31, 2019 Accounts receivable $ 343 Other current assets 704 Total current assets held for sale $ 1,047 Proved oil and gas properties, net $ 9,528 Other noncurrent assets 137 Total noncurrent assets held for sale $ 9,665 Accounts payable $ 2,067 Accrued liabilities 570 Other current liabilities 178 Total current liabilities associated with assets held for sale $ 2,815 Asset retirement obligations $ 6,488 Other liabilities 525 Total noncurrent liabilities associated with assets held for sale $ 7,013 Discontinued Operations The Company determined that the planned divestiture of MHP met the assets held for sale criteria and the criteria for classification as discontinued operations as of December 31, 2019. The Company included the results of operations for MHP for the year ended December 31, 2019 in discontinued operations as follows: (in thousands) For the Year Ended December 31, 2019 Revenues $ 7,160 Depreciation, depletion, amortization and accretion (550 ) Other operating expenses (5,296 ) Other income 2 Income from discontinued operations, net of tax 1,316 Gain on disposal of discontinued operations, net of tax — Income from discontinued operations, net of tax $ 1,316 The Company had maintained an accrued liability of $3.5 million related to litigation involving MHP and a third-party regarding certain royalty and overriding royalty deductions and related payments under several farm-out agreements. The litigation concluded in April 2019 and, as a result, the Company removed the accrued liability and recognized corresponding income from discontinued operations for the year ended December 31, 2019. Total operating and investing cash flows of discontinued operations for the year ended December 31, 2019 were as follows: (in thousands) For the Year Ended December 31, 2019 Net cash provided by operating activities $ 425 Net cash provided by investing activities $ 26 |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Leases | Note 6—Leases The Company leases drilling rigs, compressors, vehicles, office space, and other equipment under non-cancelable operating leases expiring through 2036. Certain lease agreements may include options to renew the lease, terminate the lease early, or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including the options to extend or terminate the lease when such an option is reasonably certain to be exercised . As discussed in Note 2— Summary of Significant Accounting Policies On January 1, 2019, the Company recorded a total of $10.4 million in right-of-use assets and corresponding new lease liabilities on its Consolidated Balance Sheets representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date. The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts, and terms recognized under the prior lease accounting guidance. Leases with an initial term of 12 months or less, taking into account extensions if reasonably certain to be exercised, are considered short-term leases and are not recorded on the Consolidated Balance Sheet. The Company incurred $16.0 million in operating lease cost during the year ended December 31, 2019. The operating lease right-of-use assets were reported in other noncurrent assets and the current and noncurrent portions of the operating lease liabilities were reported in current liabilities and noncurrent liabilities, respectively, on the Consolidated Balance Sheets. As of December 31, 2019, the operating right-of-use assets were $37.0 million and operating lease liabilities were $37.2 million, of which $12.7 million was classified as current. As of December 31, 2019, the weighted average remaining lease term was 3.7 Supplemental cash flow information related to the Company’s operating leases is included in the table below (in thousands): For the Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 5,542 Investing cash flows for operating leases $ 10,489 ROU assets added in exchange for lease obligations (upon adoption) $ 10,434 ROU assets and lease obligations acquired in BRMR Merger $ 7,900 ROU assets added in exchange for lease obligations, net of terminations (since adoption) $ 31,714 The Company’s lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands): Operating Leases 2020 $ 14,424 2021 13,004 2022 5,524 2023 3,611 2024 2,110 Thereafter 2,631 Total lease payments $ 41,304 Less imputed interest (4,069 ) Total lease liability $ 37,235 As discussed in Note 2— Summary of Significant Accounting Policies 2019 1,360 2020 1,060 2021 929 2022 755 2023 755 Thereafter 1,619 Total minimum lease payments $ 6,478 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Note 7—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. By using derivative instruments to hedge exposures to changes in commodity prices, the Company is exposed to the credit risk of its 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. The creditworthiness of counterparties is subject to periodic review. As of December 31, 2019, the Company’s derivative instruments were with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., EDF Energy, J Aron, KeyBank, N.A., Morgan Stanley, Royal Bank of Canada, and Wells Fargo. 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, 2019, for future production periods: Natural Gas Derivatives: Description Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Swaps: 50,000 January 2020 – December 2020 $ 2.67 20,000 January 2020 – March 2020 $ 2.80 80,000 January 2020 – June 2020 $ 2.67 20,000 April 2020 – June 2020 $ 2.75 30,000 July 2020 – December 2020 $ 2.60 25,000 January 2020 – March 2021 $ 2.60 20,000 July 2020 – March 2021 $ 2.58 Natural Gas Collars: Floor purchase price (put) 50,000 January 2020 – December 2020 $ 2.49 Ceiling sold price (call) 50,000 January 2020 – December 2020 $ 2.88 Floor purchase price (put) 30,000 January 2020 – March 2020 $ 2.65 Ceiling sold price (call) 30,000 January 2020 – March 2020 $ 2.98 Floor purchase price (put) 15,000 April 2020 – June 2020 $ 2.50 Ceiling sold price (call) 15,000 April 2020 – June 2020 $ 2.80 Natural Gas Three-way Collars: Floor purchase price (put) 30,000 January 2020 – December 2020 $ 2.70 Floor sold price (put) 30,000 January 2020 – December 2020 $ 2.40 Ceiling sold price (call) 30,000 January 2020 – December 2020 $ 3.05 Floor purchase price (put) 30,000 January 2020 – March 2020 $ 2.72 Floor sold price (put) 30,000 January 2020 – March 2020 $ 2.25 Ceiling sold price (call) 30,000 January 2020 – March 2020 $ 3.15 Floor purchase price (put) 50,000 January 2020 – June 2020 $ 2.82 Floor sold price (put) 50,000 January 2020 – June 2020 $ 2.40 Ceiling sold price (call) 50,000 January 2020 – June 2020 $ 3.11 Floor purchase price (put) 45,000 January 2021 – December 2021 $ 2.55 Floor sold price (put) 45,000 January 2021 – December 2021 $ 2.25 Ceiling sold price (call) 45,000 January 2021 – December 2021 $ 2.81 Natural Gas Call/Put Options: Floor sold price (put) 50,000 January 2020 – December 2020 $ 2.30 Floor sold price (put) 50,000 January 2020 – June 2020 $ 2.25 Swaption sold price (call) 50,000 January 2021 – December 2021 $ 2.75 Swaption sold price (call) 50,000 January 2022 – December 2022 $ 3.00 Basis Swaps: Appalachia - Dominion 12,500 April 2020 – October 2020 $ (0.52 ) Appalachia - Dominion 20,000 January 2020 – December 2020 $ (0.59 ) Appalachia - Dominion 20,000 January 2020 – March 2020 $ (0.39 ) Oil Derivatives : Description Volume (Bbls/d) Production Period Weighted Average Price Oil Swaps: 1,500 January 2020 – December 2020 $ 57.07 1,000 July 2020 – December 2020 $ 56.53 250 July 2020 – March 2021 $ 53.20 250 January 2021 – March 2021 $ 53.00 Oil Collars: Floor purchase price (put) 500 January 2020 – December 2020 $ 50.00 Ceiling sold price (call) 500 January 2020 – December 2020 $ 64.00 Floor purchase price (put) 500 July 2020 – December 2020 $ 52.00 Ceiling sold price (call) 500 July 2020 – December 2020 $ 60.00 Floor purchase price (put) 500 January 2020 – March 2020 $ 60.00 Ceiling sold price (call) 500 January 2020 – March 2020 $ 67.00 Oil Three-way Collars: Floor purchase price (put) 2,000 January 2020 – June 2020 $ 62.50 Floor sold price (put) 2,000 January 2020 – June 2020 $ 55.00 Ceiling sold price (call) 2,000 January 2020 – June 2020 $ 74.00 Oil Call/Put Options: Swaption sold price (call) 500 January 2021 – December 2021 $ 56.80 Floor sold price (put) 500 July 2020 – December 2020 $ 45.00 NGL Derivatives: Description Volume (Bbls/d) Production Period Weighted Average Price ($/Bbl) Propane Swaps: 750 January 2020 – December 2020 $ 21.46 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, 2019 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 33,762 $ (3,719 ) 30,043 Other current assets Commodity derivatives - noncurrent 833 (45 ) 788 Other assets Total assets $ 34,595 $ (3,764 ) $ 30,831 Liabilities Commodity derivatives - current $ (5,081 ) $ 3,719 $ (1,362 ) Accrued liabilities Commodity derivatives - noncurrent (2,397 ) 45 (2,352 ) Other liabilities Total liabilities $ (7,478 ) $ 3,764 $ (3,714 ) As of December 31, 2018 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 4,960 $ (845 ) $ 4,115 Other current assets Commodity derivatives - noncurrent 1,910 — 1,910 Other assets Total assets $ 6,870 $ (845 ) $ 6,025 Liabilities Commodity derivatives - current $ (845 ) $ 845 $ — Accrued liabilities Commodity derivatives - noncurrent (326 ) — (326 ) Other liabilities Total liabilities $ (1,171 ) $ 845 $ (326 ) (a) The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the Consolidated Statements of Operations for the periods presented (in thousands): For the Year Ended December 31, Location of Gain (Loss) 2019 2018 2017 Commodity derivatives Gain (loss) on derivative instruments $ 48,596 $ (21,169 ) $ 45,365 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 8—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 Value As of December 31, 2019: (in thousands) Commodity derivative instruments $ — $ 27,117 $ — $ 27,117 Total $ — $ 27,117 $ — $ 27,117 As of December 31, 2018: (in thousands) Commodity derivative instruments $ — $ 5,699 $ — $ 5,699 Total $ — $ 5,699 $ — $ 5,699 Nonfinancial Assets and Liabilities Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. (See Note 3 — Acquisition ). 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— Summary of Significant Accounting Policies The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 2— Summary of Significant Accounting Policies The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 9— Debt |
Debt
Debt | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Debt | Note 9—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. 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, 2019. Based on Level 2 market data inputs, the fair value of the senior unsecured notes at December 31, 2019 was approximately $471.1 million. Revolving Credit Facility During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”) entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October). The credit agreement governing the revolving credit facility (as amended and restated, the “Credit Agreement”) was amended on January 12, 2015. The primary change effected by such amendment was to add the Company 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, the Company 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 (as such terms are defined in the Credit Agreement), and to permit the sale of certain conventional properties. The amendment to the Credit Agreement also increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5%. 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 (as defined in the Credit Agreement) to EBITDAX. On August 1, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $175 million to $225 million. On February 28, 2019, the Company amended and restated the Credit Agreement to increase its revolving credit facility from $500 million to $1 billion. Further, the amended and restated Credit Agreement, among other things, increased the borrowing base from $225 million to $375 million (subject to scheduled and interim redeterminations based on the Company’s oil and natural gas reserves and other adjustments described therein) and extended the maturity date thereof to February 2024 (subject to earlier maturity in certain circumstances specified therein). The amended and restated Credit Agreement also adjusted the ratio of Consolidated Total Funded Net Debt to EBITDAX 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. On May 6, 2019, the borrowing base under the Credit Agreement was redetermined, which increased the borrowing base from $375 million to $400 million. On September 19, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, confirm the redetermination of the borrowing base under the Credit Agreement, which increased the borrowing base from $400 million to $500 million. On November 11, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, (a) provide that the Company, may under certain circumstances, voluntarily repurchase, prepay or otherwise redeem the Company’s outstanding 8.875% senior unsecured notes due 2023 and any Permitted Refinancing Debt thereof (as such term is defined in the Credit Agreement), provided that the aggregate amount spent for such repurchase, prepayment or redemption since November 11, 2019 does not exceed $50 million; and (b) reduce the ratio of Consolidated Total Funded Net Debt to EBITDAX that the Company is required to maintain in order to make certain Restricted Payments (as such terms are defined in the Credit Agreement) from 3:1 to 2.75:1. At December 31, 2019 , the borrowing base under the revolving credit facility was $500 million and the Company had $130.0 million in outstanding borrowings thereunder . After giving effect to outstanding letters of credit issued by the Company totaling $29.2 million, the Company had available borrowing capacity under the revolving credit facility of $340.8 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, 2019. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.375%-0.500% of the unused facility based on utilization. |
Benefit Plans
Benefit Plans | 12 Months Ended |
Dec. 31, 2019 | |
Compensation And Retirement Disclosure [Abstract] | |
Benefit Plans | Note 10—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, as amended (“the 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 $1.0 million, $0.9 million and $0.7 million related to matching contributions, classified under general and administrative, for the years ended December 31, 2019, 2018, and 2017, respectively. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2019 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Stock-Based Compensation | Note 11—Stock-Based Compensation At the Company’s 2019 Annual Meeting of Stockholders held on June 14, 2019, the Company’s stockholders approved the Company’s 2019 Long-Term Incentive Plan (the “2019 Plan”), which was previously approved by the Company’s Board of Directors. The 2019 Plan replaces the Company’s 2014 Long-Term Incentive Plan, as amended (the “Prior Plan”). Upon stockholder approval, (i) the 2019 Plan became effective, and (ii) the Prior Plan terminated, and no additional awards will be granted under the Prior Plan; provided that awards outstanding under the Prior Plan as of the date the 2019 Plan became effective will remain in full force and effect under the Prior Plan according to their respective terms. The Company is authorized to grant up to 2,650,000 shares of common stock under the 2019 Plan. The 2019 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, 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 1,745,810 shares were available for future grants under the Plan as of December 31, 2019. Stock-based compensation expense was as follows for the years ended December 31, 2019, 2018, and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 Restricted stock units $ 4,141 $ 4,014 $ 5,301 Performance units 3,706 3,497 3,622 Restricted and unrestricted stock 937 380 378 Total expense $ 8,784 $ 7,891 $ 9,301 Restricted Stock Units Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to 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, 2019, there was $2.4 million of total unrecognized compensation cost related to restricted stock units. The weighted average period for the units to vest is approximately one year. A summary of employee restricted stock unit awards activity during the year ended December 31, 2019 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2018 233,960 $ 29.27 $ 3,685 Granted 417,584 6.46 Vested (212,140 ) 28.71 Forfeited (1,845 ) 13.11 Total awarded and unvested, December 31, 2019 437,559 $ 7.83 $ 3,474 Performance Units Performance unit awards vest subject to the satisfaction of a three-year A summary of performance stock unit awards activity during the year ended December 31, 2019 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2018 346,589 $ 27.68 $ 716 Granted 261,139 7.25 Vested (270,068 ) 27.57 Forfeited (17,540 ) 24.86 Total awarded and unvested, December 31, 2019 320,120 $ 11.26 $ 2,522 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, 2019, 2018, and 2017: Year Ended December 31, 2019 2018 2017 Volatility 65.10 % 89.70 % 50.41 % Risk-free interest rate 1.83 % 2.37 % 1.34 % The fair value of the performance stock units vested during the years ended December 31, 2019 and December 31, 2017 was approximately $3.7 million and $0.8 million, respectively. Restricted Stock Issued to Directors 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 were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 18, 2017. 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 were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 17, 2018. 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 were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 16, 2019. Effective February 28, 2019, the Company issued an aggregate of 70,409 restricted shares of common stock to two of its officers in connection with retention bonus arrangements entered into between the Company and each of these officers. Twenty-five percent of the restricted shares vested on August 28, 2019, and the remaining 75% of the restricted shares vest in substantially equal installments on February 28, 2020, August 28, 2020 and February 28, 2021. Pursuant to the Company’s Non-Employee Director Compensation Policy, on June 18, 2019, the Company awarded an aggregate of 53,328 restricted shares of common stock to eight of the non-employee members of its Board of Directors, which shares are scheduled to fully vest on June 18, 2020. The other non-employee member of the Company’s Board of Directors declined to receive any compensation for his service on the Company’s Board of Directors for 2019. Pursuant to the Company’s Non-Employee Director Compensation Policy, on August 2, 2019 and October 8, 2019, the Company issued an aggregate of 26,935 and 22,661 unrestricted shares of common stock, respectively, which vested immediately to four of the non-employee members of its Board of Directors. As of December 31, 2019, there was $0.9 million of total unrecognized compensation cost related to restricted stock units issued to Directors. |
Net Income (Loss) Per Share
Net Income (Loss) Per Share | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Net Income (Loss) Per Share | Note 12—Net Income (Loss) Per Share Net Income (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 table below retroactively reflects, in accordance with ASC 505 “Equity”, the stock split that occurred on February 28, 2019 for the years ended December 31, 2018 and 2017, respectively. The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the years ended December 31, 2019, 2018, and 2017: Year Ended December 31, (in thousands, except per share data) 2019 2018 2017 Income Shares Per Share Income Shares Per Share Income Shares Per Share Basic: Net income, shares, basic $ 31,762 33,211 $ 0.96 $ 18,826 19,999 $ 0.94 $ 8,525 17,479 $ 0.49 Weighted-average number of shares of common stock-diluted: Restricted stock and performance unit awards — 113 — 88 — 200 Diluted: Net income, shares, diluted $ 31,762 33,324 $ 0.95 $ 18,826 20,087 $ 0.94 $ 8,525 17,679 $ 0.48 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 13—Related Party Transactions During the years ended December 31, 2018 and 2017, the Company incurred approximately $0.6 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which were owned by the Company’s former Chairman, President and Chief Executive Officer. The Company incurred less than $0.1 million for these services for the year ended December 31, 2019. The fees were paid in accordance with a standard service contract that did not obligate the Company to any minimum terms. The Company no longer utilizes any flight charter services under this arrangement. Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap Investments L.P. (“EnCap”). EnCap has representatives on the Company’s Board of Directors, and affiliates of EnCap collectively beneficially own approximately 40% 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, 2019 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 14—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. During the year ended December 31, 2019, the Company removed an accrued liability related to certain litigation involving MHP (See Note 5— Assets Held for Sale and Discontinued Operations . (b) Environmental Matters The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected. (c) Other Commitments (in thousands) Firm transportation (i) Gas processing, gathering, and compression services (ii) Total Year Ending December 31: 2020 $ 100,101 $ 40,811 $ 140,912 2021 99,828 41,383 141,211 2022 99,828 43,399 143,227 2023 99,828 41,260 141,088 2024 100,101 39,498 139,599 Thereafter 722,369 211,001 933,370 Total $ 1,222,055 $ 417,352 $ 1,639,407 (i) Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements the Company’s proportionate share of costs based on its working interest. (ii) Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing and gathering 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. See Note 6— Leases |
Income Tax
Income Tax | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Note 15—Income Tax The components of the Company’s income tax expense from continuing operations are as follows (in thousands): For the Year Ended December 31, 2019 2018 2017 Current Federal $ — $ — $ — State — — — Total current — — — Deferred Federal — — — State — — — Total deferred — — — Total income tax expense (benefit) $ — $ — $ — The Company’s income tax expense from continuing operations 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, 2019 2018 2017 Income from continuing operations $ 30,446 $ 18,826 $ 8,525 Statutory rate 21 % 21 % 35 % Income tax benefit computed at statutory rate 6,394 3,953 2,984 Reconciling items: State income taxes 200 — — Deferred true-up (6,686 ) — — Share-based compensation — 1,201 (576 ) Other permanent differences 2,376 54 50 Executive compensation limitation 1,263 268 496 Change in valuation allowance 7,959 (5,476 ) (145,449 ) Change in State tax rate (11,506 ) — 142,495 Income tax expense (benefit) $ — $ — $ — 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, 2019 2018 2017 Deferred tax asset: Oil and gas properties and equipment $ 11,613 $ 62,616 $ 93,854 Federal tax loss carryforwards 306,743 140,059 114,652 Derivative instruments and other — — 1,064 Interest expense limitation carryforward 25,932 — — Operating lease right-of-use liabilities 8,278 — — Other, net 5,240 7,398 4,639 Deferred tax asset 357,806 210,073 214,209 Valuation allowance (343,577 ) (208,324 ) (213,800 ) Net deferred tax assets $ 14,229 $ 1,749 $ 409 Deferred tax liability: Derivative instruments and other $ 6,009 $ 1,197 $ — Other, net — 552 409 Operating lease right-of-use assets 8,220 — — Net deferred tax liability $ 14,229 $ 1,749 $ 409 Reflected in the accompanying Consolidated Balance Sheets as: Net deferred tax asset $ — $ — $ — Net deferred tax liability $ — $ — $ — Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of an asset or liability and its reported amount in the Consolidated Financial Statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rates currently in effect in each of the jurisdictions in which we have operations. In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. Due to the history of losses in recent years, management believes that it is more likely than not that the Company will not be able to realize our net deferred tax assets, and therefore a valuation allowance on the entire net deferred tax asset is maintained. The Company has U.S. federal tax loss carryforwards (“NOL”) of approximately $1.4 billion as of December 31, 2019 of which $386 million could be permanently lost. The NOL carryforwards will begin to expire in 2034. In connection with the BRMR Merger (See Note 3— Acquisition in the Company’s stock, the Company’s use of remaining U.S. tax attributes may be further limited. The tax years ended December 31, 2016 through 2019 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, 2019, 2018, and 2017 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. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2007. |
Subsidiary Guarantors
Subsidiary Guarantors | 12 Months Ended |
Dec. 31, 2019 | |
Text Block [Abstract] | |
Subsidiary Guarantors | Note 16—Subsidiary Guarantors Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, joint and severally, guarantee the Company’s 8.875% senior unsecured notes. Each such subsidiary of the Company in existence immediately prior to the BRMR Merger guaranteed the Company’s 8.875% senior unsecured notes. As a result of the BRMR Merger, and within the timeframe required by the indenture governing the Company’s 8.875% senior unsecured notes, the Company caused BRMR and each of its subsidiaries that guaranteed the Company’s revolving credit facility to guarantee the Company’s 8.875% senior unsecured notes (See Note 9— Debt A subsidiary guarantor may be released from its obligations under the guarantee: • in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or • if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture governing the senior unsecured notes. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2019 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 17—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 in the accompanying notes to the Consolidated Financial Statements. |
Quarterly Financial Information
Quarterly Financial Information (unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Information (unaudited) | Note 18—Quarterly Financial Information (unaudited) Summarized quarterly financial data for the years ended December 31, 2019 and 2018 are presented in the following table. Quarterly financial data for the year ended December 31, 2018 retroactively reflects the 15-to-1 First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2019 Total operating revenues $ 141,497 $ 155,540 $ 163,295 $ 174,109 Total operating expenses 136,642 145,370 158,394 153,146 Operating income 4,855 10,170 4,901 20,963 Income (loss) from continuing operations (13,916 ) 24,807 5,521 14,034 Income (loss) from discontinued operations (182 ) 2,705 (1,237 ) 30 Net income (loss) (14,098 ) 27,512 4,284 14,064 Income (loss) per common share: Basic and diluted from continuing operations $ (0.54 ) $ 0.69 $ 0.15 $ 0.39 Basic and diluted from discontinued operations $ (0.01 ) $ 0.08 $ (0.03 ) $ — Basic and diluted $ (0.55 ) $ 0.77 $ 0.12 $ 0.39 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 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 |
Supplemental Oil and Natural Ga
Supplemental Oil and Natural Gas Information (unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Text Block [Abstract] | |
Supplemental Oil and Natural Gas Information (unaudited) | Note 19—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, 2019 2018 Oil and natural gas properties: Unproved properties $ 508,576 $ 482,475 Proved properties 2,783,232 2,188,233 Total oil and natural gas properties 3,291,808 2,670,708 Less accumulated depreciation, depletion and amortization (1,532,127 ) (1,380,650 ) Net oil and natural gas properties $ 1,759,681 $ 1,290,058 (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, 2019 2018 2017 Acquisition costs: Unproved properties $ 106,758 $ 107,862 $ 57,498 Proved properties 201,884 4,072 — Development cost 339,628 239,467 257,119 Exploration cost 11,142 20,957 18,791 Asset retirement obligations 29,346 — — Total acquisition, development and exploration costs $ 688,758 $ 372,358 $ 333,408 (c) Reserve Quantity Information The following information represents estimates of the Company’s proved reserves as of December 31, 2019 and December 31, 2018, 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, 2019, 2018, and 2017 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 primarily in the Appalachian Basin of Ohio, Pennsylvania and West Virginia. 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, primarily within the States of Ohio, Pennsylvania and West Virginia. All of the estimates of the proved reserves at December 31, 2019 and 2018 and December 31, 2017, 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, 2019, 2018, and 2017 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, 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 9.9 551.4 522.2 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 Revisions (77.0 ) 4,454.5 (1,569.8 ) (59.6 ) Extensions and discoveries 418.7 19,016.3 11,078.1 599.2 Acquisitions 418.9 14,844.0 2,915.2 525.5 Production (154.1 ) (4,686.3 ) (2,950.8 ) (200.0 ) End of year, December 31, 2019 2,137.7 68,359.4 30,324.8 2,729.8 Proved developed reserves: 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 December 31, 2019 1,183.2 39,316.3 12,512.6 1,494.2 Proved undeveloped reserves: 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 December 31, 2019 954.5 29,043.2 17,812.2 1,235.6 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 2019 Changes in Reserves • Extensions of 599.2 Bcfe from the development of 100.5 Bcfe of unproved wells to proved developed, of which 70.2 Bcfe is from the development of the Company’s operated Marcellus asset, 23.3 Bcfe is from the Company’s operated Utica asset and 7.0 Bcfe was added from participation in non-operated wells. Extensions of 498.7 Bcfe from the development of unproved wells to proved undeveloped, of which 269.4 Bcfe is from the Company’s operated Utica asset and 229.3 Bcfe is from the Company’s operated Marcellus asset • 525.5 • Revisions to previous estimates are comprised of 59.6 Bcfe of negative revisions primarily due to a negative adjustment of 277.3 due to downward SEC pricing and differentials and 44.2 Bcfe due adjustments in the drilling schedule. The negative revisions have been offset by a positive revision of 261.9 Bcfe due to well performance, capital allocation, and lease operating expense (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, 2019 and 2018 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, 2019, 2018, and 2017 (in thousands): December 31, 2019 2018 2017 Future cash inflows (total revenues) $ 8,212,521 $ 6,730,000 $ 4,750,238 Future production costs (3,867,182 ) (2,964,098 ) (2,332,310 ) Future development costs (capital costs) (982,321 ) (855,932 ) (879,399 ) Future income tax expense (633,086 ) (136,472 ) — Future net cash flows 2,729,932 2,773,498 1,538,529 10% annual discount for estimated timing of cash flows (1,534,108 ) (1,444,188 ) (808,843 ) Standardized measure of Discounted Future Net Cash Flow $ 1,195,824 $ 1,329,310 $ 729,686 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. F-37 (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, 2019 2018 2017 Standardized Measure, beginning of the year $ 1,329,310 $ 729,686 $ 205,981 Net change in prices and production costs (531,056 ) 369,578 653,347 Net change in future development costs 28,481 87,466 (385,042 ) Sales, less production costs (327,373 ) (321,802 ) (226,324 ) Extensions 251,343 363,708 135,734 Acquisitions 387,117 7,468 2,365 Divestitures — (20 ) — Revisions of previous quantity estimates 7,345 19,910 322,917 Previously estimated development costs incurred 245,931 65,035 34,102 Net changes in taxes (237,482 ) (37,345 ) — Accretion of discount 132,931 72,969 20,598 Changes in timing and other (90,723 ) (27,343 ) (33,992 ) Standardized Measure, end of year $ 1,195,824 $ 1,329,310 $ 729,686 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 and 2018, and the results of its operations, comprehensive income (loss) and its cash flows for the years ended December 31, 2019, 2018, and 2017. Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. The Company’s management believes the major estimates and assumptions impacting the Consolidated Financial Statements are the following: • estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion, amortization and accretion and impairment of capitalized costs of oil and natural gas properties; • estimates of asset retirement obligations; • estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells; • impairment of undeveloped properties and other assets; and • depreciation and depletion of property and equipment. Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions. |
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. 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 had no significant accounts receivables determined to be uncollectable as of December 31, 2019 or December 31, 2018. The Company accrues revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. |
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, amortization and accretion expense (See “Depreciation, Depletion, Amortization and Accretion ” below). Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s 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, 2019 December 31, 2018 Oil and natural gas properties: Unproved $ 508,576 $ 482,475 Proved 2,783,232 2,188,233 Gross oil and natural gas properties 3,291,808 2,670,708 Less accumulated depreciation, depletion and amortization (1,532,127 ) (1,380,650 ) Oil and natural gas properties, net 1,759,681 1,290,058 Other property and equipment 20,000 14,460 Less accumulated depreciation (8,774 ) (8,160 ) Other property and equipment, net 11,226 6,300 Property and equipment, net $ 1,770,907 $ 1,296,358 Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. 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, 2019 December 31, 2018 Trade payables $ 20,232 $ 27,481 Royalty payables 76,642 70,019 Production & ad valorem taxes 1,025 1,811 Derivative payable 112 4,736 Other payables 21,896 12,688 Total accounts payable $ 119,907 $ 116,735 A summary of accrued liabilities is as follows (in thousands): December 31, 2019 December 31, 2018 Ad valorem and production taxes $ 9,830 $ 6,193 Employee compensation 9,375 6,595 Royalties 23,311 39,969 Short term derivatives 1,362 — Other 9,988 4,152 Total accrued liabilities $ 53,866 $ 56,909 |
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 receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense. NGLs The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company 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 and certain costs incurred by third parties. 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, 2019 2018 2017 Revenues (in thousands) Natural gas sales $ 361,318 $ 274,239 $ 241,379 NGL sales 84,552 86,152 64,109 Oil sales 145,829 138,202 74,690 Brokered natural gas and marketing revenue 42,274 16,552 3,481 Other revenue 468 — — Total revenues $ 634,441 $ 515,145 $ 383,659 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 $63.7 million and $94.1 million at December 31, 2019 and December 31, 2018, respectively. |
Major Customers | (g) Major Customers The Company sells production volumes to various purchasers. For the years ended December 31, 2019, 2018, and 2017, there were two, one and two 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, 2019 2018 2017 Purchaser BP Energy Company 23% — — Emera Energy Services — — 17% Marathon Petroleum 20% 25% 10% Total 43% 25% 27% 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, 2019 and December 31, 2018 (in thousands): December 31, 2019 December 31, 2018 Receivables by product or service: Sale of oil and natural gas and related products and services $ 63,730 $ 94,107 Joint interest owners 12,156 24,830 Derivatives 210 372 Other 1,306 23 Total $ 77,402 $ 119,332 Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in Ohio, Pennsylvania and West Virginia. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, 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 $27.1 million and $5.7 million at December 31, 2019 and 2018, 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, 2019, the Company did not have past-due receivables from or payables to any of the counterparties. |
Depreciation, Depletion, Amortization, and Accretion | (i) Depreciation, Depletion, Amortization and Accretion Oil and Natural Gas Properties Depreciation, depletion, amortization and accretion (“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, 2019, 2018, and 2017 totaled approximately $153.8 million, $133.2 million and $117.3 million, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Consolidated Financial Statements. 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, 2019, 2018, and 2017 totaled approximately $2.2 million, $1.8 million and $2.0 million, respectively. This amount is included in depreciation, depletion, amortization and accretion 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. There were no impairments of proved properties for the years ended December 31, 2019, 2018, and 2017. When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $45.8 million, $27.6 million, and $28.3 million for the years ended December 31, 2019, 2018, and 2017, 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, 2019 2018 2017 Asset retirement obligations, beginning of period $ 7,110 $ 6,029 $ 4,806 Accretion 2,368 663 544 Additional liabilities incurred 2,379 418 679 Obligation for wells acquired 20,188 — — Obligation for wells drilled 519 — — Liabilities settled via plugging (723 ) — — Less: current ARO portion (accrued liabilities) (1,964 ) — — Asset retirement obligations, end of period $ 29,877 $ 7,110 $ 6,029 The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement. |
Off-Balance Sheet Arrangements | (o) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. |
Segment Reporting | (p) 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 | (q) 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 Consolidated 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. During the years ended December 31, 2019, 2018, and 2017, the Company amortized $4.1 million, $3.6 million and $3.4 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method. |
Recent Accounting Pronouncements | (r) Recent Accounting Pronouncements Recently Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Entities are required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases’ classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements.” The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements,” which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption. The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third-party-sponsored lease accounting information system to facilitate the accounting and financial reporting requirements and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment. See Note 6 – Leases Accounting Pronouncements Not Yet Adopted In June 2016, the FASB issued ASU 2016-13, “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments ” |
Leases | As discussed in Note 2— Summary of Significant Accounting Policies |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 December 31, 2018 Oil and natural gas properties: Unproved $ 508,576 $ 482,475 Proved 2,783,232 2,188,233 Gross oil and natural gas properties 3,291,808 2,670,708 Less accumulated depreciation, depletion and amortization (1,532,127 ) (1,380,650 ) Oil and natural gas properties, net 1,759,681 1,290,058 Other property and equipment 20,000 14,460 Less accumulated depreciation (8,774 ) (8,160 ) Other property and equipment, net 11,226 6,300 Property and equipment, net $ 1,770,907 $ 1,296,358 |
Schedule of Accounts Payable | A summary of accounts payable is as follows (in thousands): December 31, 2019 December 31, 2018 Trade payables $ 20,232 $ 27,481 Royalty payables 76,642 70,019 Production & ad valorem taxes 1,025 1,811 Derivative payable 112 4,736 Other payables 21,896 12,688 Total accounts payable $ 119,907 $ 116,735 |
Summary of Accrued Liabilities | A summary of accrued liabilities is as follows (in thousands): December 31, 2019 December 31, 2018 Ad valorem and production taxes $ 9,830 $ 6,193 Employee compensation 9,375 6,595 Royalties 23,311 39,969 Short term derivatives 1,362 — Other 9,988 4,152 Total accrued liabilities $ 53,866 $ 56,909 |
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, 2019 2018 2017 Revenues (in thousands) Natural gas sales $ 361,318 $ 274,239 $ 241,379 NGL sales 84,552 86,152 64,109 Oil sales 145,829 138,202 74,690 Brokered natural gas and marketing revenue 42,274 16,552 3,481 Other revenue 468 — — Total revenues $ 634,441 $ 515,145 $ 383,659 |
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, 2019 2018 2017 Asset retirement obligations, beginning of period $ 7,110 $ 6,029 $ 4,806 Accretion 2,368 663 544 Additional liabilities incurred 2,379 418 679 Obligation for wells acquired 20,188 — — Obligation for wells drilled 519 — — Liabilities settled via plugging (723 ) — — Less: current ARO portion (accrued liabilities) (1,964 ) — — Asset retirement obligations, end of period $ 29,877 $ 7,110 $ 6,029 |
Sales Revenue, 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, 2019 2018 2017 Purchaser BP Energy Company 23% — — Emera Energy Services — — 17% Marathon Petroleum 20% 25% 10% Total 43% 25% 27% |
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, 2019 and December 31, 2018 (in thousands): December 31, 2019 December 31, 2018 Receivables by product or service: Sale of oil and natural gas and related products and services $ 63,730 $ 94,107 Joint interest owners 12,156 24,830 Derivatives 210 372 Other 1,306 23 Total $ 77,402 $ 119,332 |
Acquisition (Tables)
Acquisition (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Business Combinations [Abstract] | |
Summary of Purchase Price Allocation and Values of Assets Acquired and Liabilities Assumed | The following table summarizes the purchase price allocation and the values of assets acquired and liabilities assumed (in thousands): Purchase Price February 28, 2019 Fair value of the Company's common stock issued $ 263,487 Fair value of BRMR share-based and other compensation 12,272 Total Fair Value of Consideration $ 275,759 Cash and cash equivalents 12,894 Accounts receivable 25,884 Assets held for sale - current 2,296 Other current assets 1,702 Unproved properties 80,843 Proved oil and gas properties 218,866 Other property and equipment 7,059 Other assets 2,461 Operating lease right-of-use asset 7,900 Assets held for sale - long-term 9,611 Total assets acquired $ 369,516 Accounts payable (16,571 ) Accrued capital expenditures (5,807 ) Accrued liabilities (28,824 ) Operating lease liability - current (1,979 ) Liabilities associated with assets held for sale - current (7,683 ) Asset retirement obligations (20,188 ) Operating lease liability - noncurrent (5,923 ) Liabilities associated with assets held for sale - long-term (6,782 ) Total liabilities assumed $ (93,757 ) Net identifiable assets $ 275,759 |
Unaudited Pro Forma Financial Information | The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2018. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results. For the Year Ended December 31, (in thousands, except per share data) (unaudited) 2019 2018 Pro forma total revenues $ 677,099 $ 698,850 Pro forma net income $ 44,536 $ 5,919 Pro forma net income per share (basic) $ 1.25 $ 0.17 Pro forma net income per share (diluted) $ 1.24 $ 0.16 |
Assets Held for Sale and Disc_2
Assets Held for Sale and Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Summary of Assets Held for Sale and Discontinued Operations | The Company included the results of operations for MHP for the year ended December 31, 2019 in discontinued operations as follows: (in thousands) For the Year Ended December 31, 2019 Revenues $ 7,160 Depreciation, depletion, amortization and accretion (550 ) Other operating expenses (5,296 ) Other income 2 Income from discontinued operations, net of tax 1,316 Gain on disposal of discontinued operations, net of tax — Income from discontinued operations, net of tax $ 1,316 Total operating and investing cash flows of discontinued operations for the year ended December 31, 2019 were as follows: (in thousands) For the Year Ended December 31, 2019 Net cash provided by operating activities $ 425 Net cash provided by investing activities $ 26 |
Assets Held for Sale [Member] | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Summary of Assets Held for Sale and Discontinued Operations | The following summarizes assets and liabilities held for sale at December 31, 2019: (in thousands) December 31, 2019 Accounts receivable $ 343 Other current assets 704 Total current assets held for sale $ 1,047 Proved oil and gas properties, net $ 9,528 Other noncurrent assets 137 Total noncurrent assets held for sale $ 9,665 Accounts payable $ 2,067 Accrued liabilities 570 Other current liabilities 178 Total current liabilities associated with assets held for sale $ 2,815 Asset retirement obligations $ 6,488 Other liabilities 525 Total noncurrent liabilities associated with assets held for sale $ 7,013 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Supplemental Cash Flow Information Related to Operating Leases | Supplemental cash flow information related to the Company’s operating leases is included in the table below (in thousands): For the Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 5,542 Investing cash flows for operating leases $ 10,489 ROU assets added in exchange for lease obligations (upon adoption) $ 10,434 ROU assets and lease obligations acquired in BRMR Merger $ 7,900 ROU assets added in exchange for lease obligations, net of terminations (since adoption) $ 31,714 |
Schedule of Lease Liabilities | The Company’s lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands): Operating Leases 2020 $ 14,424 2021 13,004 2022 5,524 2023 3,611 2024 2,110 Thereafter 2,631 Total lease payments $ 41,304 Less imputed interest (4,069 ) Total lease liability $ 37,235 |
Schedule of Future Minimum Lease Commitments Under Non-cancellable Leases | Future minimum lease commitments under non-cancellable leases at December 31, 2018 were as follows: 2019 1,360 2020 1,060 2021 929 2022 755 2023 755 Thereafter 1,619 Total minimum lease payments $ 6,478 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Derivative Instrument Positions for Future Production Periods | Below is a summary of the Company’s derivative instrument positions, as of December 31, 2019, for future production periods: Natural Gas Derivatives: Description Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Swaps: 50,000 January 2020 – December 2020 $ 2.67 20,000 January 2020 – March 2020 $ 2.80 80,000 January 2020 – June 2020 $ 2.67 20,000 April 2020 – June 2020 $ 2.75 30,000 July 2020 – December 2020 $ 2.60 25,000 January 2020 – March 2021 $ 2.60 20,000 July 2020 – March 2021 $ 2.58 Natural Gas Collars: Floor purchase price (put) 50,000 January 2020 – December 2020 $ 2.49 Ceiling sold price (call) 50,000 January 2020 – December 2020 $ 2.88 Floor purchase price (put) 30,000 January 2020 – March 2020 $ 2.65 Ceiling sold price (call) 30,000 January 2020 – March 2020 $ 2.98 Floor purchase price (put) 15,000 April 2020 – June 2020 $ 2.50 Ceiling sold price (call) 15,000 April 2020 – June 2020 $ 2.80 Natural Gas Three-way Collars: Floor purchase price (put) 30,000 January 2020 – December 2020 $ 2.70 Floor sold price (put) 30,000 January 2020 – December 2020 $ 2.40 Ceiling sold price (call) 30,000 January 2020 – December 2020 $ 3.05 Floor purchase price (put) 30,000 January 2020 – March 2020 $ 2.72 Floor sold price (put) 30,000 January 2020 – March 2020 $ 2.25 Ceiling sold price (call) 30,000 January 2020 – March 2020 $ 3.15 Floor purchase price (put) 50,000 January 2020 – June 2020 $ 2.82 Floor sold price (put) 50,000 January 2020 – June 2020 $ 2.40 Ceiling sold price (call) 50,000 January 2020 – June 2020 $ 3.11 Floor purchase price (put) 45,000 January 2021 – December 2021 $ 2.55 Floor sold price (put) 45,000 January 2021 – December 2021 $ 2.25 Ceiling sold price (call) 45,000 January 2021 – December 2021 $ 2.81 Natural Gas Call/Put Options: Floor sold price (put) 50,000 January 2020 – December 2020 $ 2.30 Floor sold price (put) 50,000 January 2020 – June 2020 $ 2.25 Swaption sold price (call) 50,000 January 2021 – December 2021 $ 2.75 Swaption sold price (call) 50,000 January 2022 – December 2022 $ 3.00 Basis Swaps: Appalachia - Dominion 12,500 April 2020 – October 2020 $ (0.52 ) Appalachia - Dominion 20,000 January 2020 – December 2020 $ (0.59 ) Appalachia - Dominion 20,000 January 2020 – March 2020 $ (0.39 ) Oil Derivatives : Description Volume (Bbls/d) Production Period Weighted Average Price Oil Swaps: 1,500 January 2020 – December 2020 $ 57.07 1,000 July 2020 – December 2020 $ 56.53 250 July 2020 – March 2021 $ 53.20 250 January 2021 – March 2021 $ 53.00 Oil Collars: Floor purchase price (put) 500 January 2020 – December 2020 $ 50.00 Ceiling sold price (call) 500 January 2020 – December 2020 $ 64.00 Floor purchase price (put) 500 July 2020 – December 2020 $ 52.00 Ceiling sold price (call) 500 July 2020 – December 2020 $ 60.00 Floor purchase price (put) 500 January 2020 – March 2020 $ 60.00 Ceiling sold price (call) 500 January 2020 – March 2020 $ 67.00 Oil Three-way Collars: Floor purchase price (put) 2,000 January 2020 – June 2020 $ 62.50 Floor sold price (put) 2,000 January 2020 – June 2020 $ 55.00 Ceiling sold price (call) 2,000 January 2020 – June 2020 $ 74.00 Oil Call/Put Options: Swaption sold price (call) 500 January 2021 – December 2021 $ 56.80 Floor sold price (put) 500 July 2020 – December 2020 $ 45.00 NGL Derivatives: Description Volume (Bbls/d) Production Period Weighted Average Price ($/Bbl) Propane Swaps: 750 January 2020 – December 2020 $ 21.46 |
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, 2019 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 33,762 $ (3,719 ) 30,043 Other current assets Commodity derivatives - noncurrent 833 (45 ) 788 Other assets Total assets $ 34,595 $ (3,764 ) $ 30,831 Liabilities Commodity derivatives - current $ (5,081 ) $ 3,719 $ (1,362 ) Accrued liabilities Commodity derivatives - noncurrent (2,397 ) 45 (2,352 ) Other liabilities Total liabilities $ (7,478 ) $ 3,764 $ (3,714 ) As of December 31, 2018 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 4,960 $ (845 ) $ 4,115 Other current assets Commodity derivatives - noncurrent 1,910 — 1,910 Other assets Total assets $ 6,870 $ (845 ) $ 6,025 Liabilities Commodity derivatives - current $ (845 ) $ 845 $ — Accrued liabilities Commodity derivatives - noncurrent (326 ) — (326 ) Other liabilities Total liabilities $ (1,171 ) $ 845 $ (326 ) (a) The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. |
Summary of Gains and Losses on Derivative Instruments | The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the Consolidated Statements of Operations for the periods presented (in thousands): For the Year Ended December 31, Location of Gain (Loss) 2019 2018 2017 Commodity derivatives Gain (loss) on derivative instruments $ 48,596 $ (21,169 ) $ 45,365 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. Level 1 Level 2 Level 3 Total Value As of December 31, 2019: (in thousands) Commodity derivative instruments $ — $ 27,117 $ — $ 27,117 Total $ — $ 27,117 $ — $ 27,117 As of December 31, 2018: (in thousands) Commodity derivative instruments $ — $ 5,699 $ — $ 5,699 Total $ — $ 5,699 $ — $ 5,699 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Schedule of Stock Based Compensation Expense | Stock-based compensation expense was as follows for the years ended December 31, 2019, 2018, and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 Restricted stock units $ 4,141 $ 4,014 $ 5,301 Performance units 3,706 3,497 3,622 Restricted and unrestricted stock 937 380 378 Total expense $ 8,784 $ 7,891 $ 9,301 |
Summary of Employee Restricted Stock Unit Awards Activity | A summary of employee restricted stock unit awards activity during the year ended December 31, 2019 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2018 233,960 $ 29.27 $ 3,685 Granted 417,584 6.46 Vested (212,140 ) 28.71 Forfeited (1,845 ) 13.11 Total awarded and unvested, December 31, 2019 437,559 $ 7.83 $ 3,474 |
Summary of Performance Stock Unit Awards Activity | A summary of performance stock unit awards activity during the year ended December 31, 2019 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2018 346,589 $ 27.68 $ 716 Granted 261,139 7.25 Vested (270,068 ) 27.57 Forfeited (17,540 ) 24.86 Total awarded and unvested, December 31, 2019 320,120 $ 11.26 $ 2,522 |
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, 2019, 2018, and 2017: Year Ended December 31, 2019 2018 2017 Volatility 65.10 % 89.70 % 50.41 % Risk-free interest rate 1.83 % 2.37 % 1.34 % |
Net Income (Loss) Per Share (Ta
Net Income (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Calculation of Basic and Diluted Weighted-Average Number of Shares of Common Stock and EPS | The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the years ended December 31, 2019, 2018, and 2017: Year Ended December 31, (in thousands, except per share data) 2019 2018 2017 Income Shares Per Share Income Shares Per Share Income Shares Per Share Basic: Net income, shares, basic $ 31,762 33,211 $ 0.96 $ 18,826 19,999 $ 0.94 $ 8,525 17,479 $ 0.49 Weighted-average number of shares of common stock-diluted: Restricted stock and performance unit awards — 113 — 88 — 200 Diluted: Net income, shares, diluted $ 31,762 33,324 $ 0.95 $ 18,826 20,087 $ 0.94 $ 8,525 17,679 $ 0.48 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments And Contingencies Disclosure [Abstract] | |
Other Commitments | (c) Other Commitments (in thousands) Firm transportation (i) Gas processing, gathering, and compression services (ii) Total Year Ending December 31: 2020 $ 100,101 $ 40,811 $ 140,912 2021 99,828 41,383 141,211 2022 99,828 43,399 143,227 2023 99,828 41,260 141,088 2024 100,101 39,498 139,599 Thereafter 722,369 211,001 933,370 Total $ 1,222,055 $ 417,352 $ 1,639,407 (i) Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements the Company’s proportionate share of costs based on its working interest. (ii) Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing and gathering 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, 2019 | |
Income Tax Disclosure [Abstract] | |
Components of Income Tax Expense From Continuing Operations | The components of the Company’s income tax expense from continuing operations are as follows (in thousands): For the Year Ended December 31, 2019 2018 2017 Current Federal $ — $ — $ — State — — — Total current — — — Deferred Federal — — — State — — — Total deferred — — — Total income tax expense (benefit) $ — $ — $ — |
Schedule of Effective Income Tax Rate Reconciliation | The Company’s income tax expense from continuing operations 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, 2019 2018 2017 Income from continuing operations $ 30,446 $ 18,826 $ 8,525 Statutory rate 21 % 21 % 35 % Income tax benefit computed at statutory rate 6,394 3,953 2,984 Reconciling items: State income taxes 200 — — Deferred true-up (6,686 ) — — Share-based compensation — 1,201 (576 ) Other permanent differences 2,376 54 50 Executive compensation limitation 1,263 268 496 Change in valuation allowance 7,959 (5,476 ) (145,449 ) Change in State tax rate (11,506 ) — 142,495 Income tax expense (benefit) $ — $ — $ — |
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, 2019 2018 2017 Deferred tax asset: Oil and gas properties and equipment $ 11,613 $ 62,616 $ 93,854 Federal tax loss carryforwards 306,743 140,059 114,652 Derivative instruments and other — — 1,064 Interest expense limitation carryforward 25,932 — — Operating lease right-of-use liabilities 8,278 — — Other, net 5,240 7,398 4,639 Deferred tax asset 357,806 210,073 214,209 Valuation allowance (343,577 ) (208,324 ) (213,800 ) Net deferred tax assets $ 14,229 $ 1,749 $ 409 Deferred tax liability: Derivative instruments and other $ 6,009 $ 1,197 $ — Other, net — 552 409 Operating lease right-of-use assets 8,220 — — Net deferred tax liability $ 14,229 $ 1,749 $ 409 Reflected in the accompanying Consolidated Balance Sheets as: Net deferred tax asset $ — $ — $ — Net deferred tax liability $ — $ — $ — |
Quarterly Financial Informati_2
Quarterly Financial Information (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Summarized quarterly financial data for the years ended December 31, 2019 and 2018 are presented in the following table. Quarterly financial data for the year ended December 31, 2018 retroactively reflects the 15-to-1 First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2019 Total operating revenues $ 141,497 $ 155,540 $ 163,295 $ 174,109 Total operating expenses 136,642 145,370 158,394 153,146 Operating income 4,855 10,170 4,901 20,963 Income (loss) from continuing operations (13,916 ) 24,807 5,521 14,034 Income (loss) from discontinued operations (182 ) 2,705 (1,237 ) 30 Net income (loss) (14,098 ) 27,512 4,284 14,064 Income (loss) per common share: Basic and diluted from continuing operations $ (0.54 ) $ 0.69 $ 0.15 $ 0.39 Basic and diluted from discontinued operations $ (0.01 ) $ 0.08 $ (0.03 ) $ — Basic and diluted $ (0.55 ) $ 0.77 $ 0.12 $ 0.39 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 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 |
Supplemental Oil and Natural _2
Supplemental Oil and Natural Gas Information (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 2018 Oil and natural gas properties: Unproved properties $ 508,576 $ 482,475 Proved properties 2,783,232 2,188,233 Total oil and natural gas properties 3,291,808 2,670,708 Less accumulated depreciation, depletion and amortization (1,532,127 ) (1,380,650 ) Net oil and natural gas properties $ 1,759,681 $ 1,290,058 |
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, 2019 2018 2017 Acquisition costs: Unproved properties $ 106,758 $ 107,862 $ 57,498 Proved properties 201,884 4,072 — Development cost 339,628 239,467 257,119 Exploration cost 11,142 20,957 18,791 Asset retirement obligations 29,346 — — Total acquisition, development and exploration costs $ 688,758 $ 372,358 $ 333,408 |
Proved Developed and Proved Undeveloped Reserves | The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2019, 2018, and 2017 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, 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 9.9 551.4 522.2 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 Revisions (77.0 ) 4,454.5 (1,569.8 ) (59.6 ) Extensions and discoveries 418.7 19,016.3 11,078.1 599.2 Acquisitions 418.9 14,844.0 2,915.2 525.5 Production (154.1 ) (4,686.3 ) (2,950.8 ) (200.0 ) End of year, December 31, 2019 2,137.7 68,359.4 30,324.8 2,729.8 Proved developed reserves: 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 December 31, 2019 1,183.2 39,316.3 12,512.6 1,494.2 Proved undeveloped reserves: 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 December 31, 2019 954.5 29,043.2 17,812.2 1,235.6 |
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, 2019, 2018, and 2017 (in thousands): December 31, 2019 2018 2017 Future cash inflows (total revenues) $ 8,212,521 $ 6,730,000 $ 4,750,238 Future production costs (3,867,182 ) (2,964,098 ) (2,332,310 ) Future development costs (capital costs) (982,321 ) (855,932 ) (879,399 ) Future income tax expense (633,086 ) (136,472 ) — Future net cash flows 2,729,932 2,773,498 1,538,529 10% annual discount for estimated timing of cash flows (1,534,108 ) (1,444,188 ) (808,843 ) Standardized measure of Discounted Future Net Cash Flow $ 1,195,824 $ 1,329,310 $ 729,686 |
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, 2019 2018 2017 Standardized Measure, beginning of the year $ 1,329,310 $ 729,686 $ 205,981 Net change in prices and production costs (531,056 ) 369,578 653,347 Net change in future development costs 28,481 87,466 (385,042 ) Sales, less production costs (327,373 ) (321,802 ) (226,324 ) Extensions 251,343 363,708 135,734 Acquisitions 387,117 7,468 2,365 Divestitures — (20 ) — Revisions of previous quantity estimates 7,345 19,910 322,917 Previously estimated development costs incurred 245,931 65,035 34,102 Net changes in taxes (237,482 ) (37,345 ) — Accretion of discount 132,931 72,969 20,598 Changes in timing and other (90,723 ) (27,343 ) (33,992 ) Standardized Measure, end of year $ 1,195,824 $ 1,329,310 $ 729,686 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Oil and natural gas properties: | ||
Unproved properties | $ 508,576 | $ 482,475 |
Proved properties | 2,783,232 | 2,188,233 |
Gross oil and natural gas properties | 3,291,808 | 2,670,708 |
Less accumulated depreciation, depletion and amortization | (1,532,127) | (1,380,650) |
Total oil and natural gas properties, net | 1,759,681 | 1,290,058 |
Other property and equipment | 20,000 | 14,460 |
Less accumulated depreciation | (8,774) | (8,160) |
Other property and equipment, net | 11,226 | 6,300 |
Total property and equipment, net | $ 1,770,907 | $ 1,296,358 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Summary of Accounts Payable (Detail) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Accounts Payable Current [Abstract] | ||
Trade payables | $ 20,232 | $ 27,481 |
Royalty payables | 76,642 | 70,019 |
Production & ad valorem taxes | 1,025 | 1,811 |
Derivative payable | 112 | 4,736 |
Other payables | 21,896 | 12,688 |
Total accounts payable | $ 119,907 | $ 116,735 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Summary of Accrued Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Accrued Liabilities Current [Abstract] | ||
Ad valorem and production taxes | $ 9,830 | $ 6,193 |
Employee compensation | 9,375 | 6,595 |
Royalties | 23,311 | 39,969 |
Short term derivatives | 1,362 | |
Other | 9,988 | 4,152 |
Total accrued liabilities | $ 53,866 | $ 56,909 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Summary of Revenue Disaggregated by Type (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation Of Revenue [Line Items] | |||||||||||
Total revenues | $ 174,109 | $ 163,295 | $ 155,540 | $ 141,497 | $ 171,208 | $ 130,123 | $ 103,622 | $ 110,192 | $ 634,441 | $ 515,145 | $ 383,659 |
Natural Gas Sales [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Total revenues | 361,318 | 274,239 | 241,379 | ||||||||
NGL Sales [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Total revenues | 84,552 | 86,152 | 64,109 | ||||||||
Oil Sales [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Total revenues | 145,829 | 138,202 | 74,690 | ||||||||
Brokered Natural Gas and Marketing Revenue [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Total revenues | 42,274 | $ 16,552 | $ 3,481 | ||||||||
Other Revenue [Member] | |||||||||||
Disaggregation Of Revenue [Line Items] | |||||||||||
Total revenues | $ 468 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019USD ($)CustomerSegment | Dec. 31, 2018USD ($)Customer | Dec. 31, 2017USD ($)Customer | |
Summary Of Significant Accounting Policies [Line Items] | |||
Accounts receivable | $ 77,402 | $ 119,332 | |
Depreciation, depletion, amortization and accretion | $ 156,552 | 134,940 | $ 119,362 |
Number of operating segment | Segment | 1 | ||
Amortization of deferred financing costs and debt discount | $ 4,100 | 3,600 | 3,400 |
Oil and Gas Properties [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Depreciation, depletion, amortization and accretion | 153,800 | 133,200 | 117,300 |
Other property and equipment [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Depreciation | $ 2,200 | 1,800 | 2,000 |
Other property and equipment [Member] | Minimum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Property and equipment, expected lives | 5 years | ||
Other property and equipment [Member] | Maximum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Property and equipment, expected lives | 40 years | ||
Proved Oil And Gas Properties [Member] | Marcellus Shale [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Impairment of oil and gas properties | $ 0 | 0 | 0 |
Unproved Oil And Gas Properties [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Impairment of oil and gas properties | 45,800 | 27,600 | $ 28,300 |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Fair value of commodity derivative contracts | $ 27,100 | $ 5,700 | |
Sales Revenue, Net [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Number of customers | Customer | 2 | 1 | 2 |
Revenue From Contract With Customer [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Accounts receivable | $ 63,700 | $ 94,100 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 43.00% | 25.00% | 27.00% |
BP Energy Company [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 23.00% | ||
Emera Energy Services [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 | 20.00% | 25.00% | 10.00% |
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, 2019 | Dec. 31, 2018 |
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $ 77,402 | $ 119,332 |
Product Concentration Risk [Member] | Oil and Natural Gas and Related Products and Services [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 63,730 | 94,107 |
Product Concentration Risk [Member] | Joint Interest Owners [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 12,156 | 24,830 |
Product Concentration Risk [Member] | Derivatives [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 210 | 372 |
Product Concentration Risk [Member] | Other [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $ 1,306 | $ 23 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |||
Asset retirement obligations, beginning of period | $ 7,110 | $ 6,029 | $ 4,806 |
Accretion | 2,368 | 663 | 544 |
Additional liabilities incurred | 2,379 | 418 | 679 |
Obligation for wells acquired | 20,188 | ||
Obligation for wells drilled | 519 | ||
Liabilities settled via plugging | (723) | ||
Less: current ARO portion (accrued liabilities) | (1,964) | ||
Asset retirement obligations, end of period | $ 29,877 | $ 7,110 | $ 6,029 |
Acquisition - Additional Inform
Acquisition - Additional Information (Detail) $ / shares in Units, $ in Thousands | Feb. 28, 2019USD ($)$ / sharesshares | Jan. 18, 2018USD ($)aWellshares | Dec. 31, 2019USD ($)$ / shares | Sep. 30, 2019USD ($) | Jun. 30, 2019USD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2018USD ($)$ / shares | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2019USD ($)$ / shares | Dec. 31, 2019USD ($)$ / shares | Dec. 31, 2018USD ($)$ / shares | Dec. 31, 2017USD ($)$ / shares |
Business Acquisition [Line Items] | ||||||||||||||
Common stock, par value | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | ||||||||
Revenue | $ 174,109 | $ 163,295 | $ 155,540 | $ 141,497 | $ 171,208 | $ 130,123 | $ 103,622 | $ 110,192 | $ 634,441 | $ 515,145 | $ 383,659 | |||
Net income from continuing operations | 14,034 | 5,521 | 24,807 | (13,916) | 30,446 | $ 18,826 | $ 8,525 | |||||||
Net income from discontinued operations | $ 30 | $ (1,237) | $ 2,705 | $ (182) | 1,316 | |||||||||
Flat Castle Acquisition [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Area of land purchased | a | 44,500 | |||||||||||||
Purchase price | $ 90,000 | |||||||||||||
Purchase price paid through shares of common stock | shares | 2,500,000 | |||||||||||||
Transaction costs capitalized related to acquisition | $ 1,000 | |||||||||||||
Flat Castle Acquisition [Member] | Proved Oil And Gas Properties [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Number of producing wells acquired | Well | 1 | |||||||||||||
Purchase price | $ 4,000 | |||||||||||||
Flat Castle Acquisition [Member] | Unproved Oil and Natural Gas Properties [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Purchase price | $ 86,000 | |||||||||||||
Cardinal Midstream II, LLC [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Third party options exercised month and year | 2018-07 | |||||||||||||
BRMR and Everest Merger Sub Inc. [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Purchase price | $ 275,759 | |||||||||||||
Common stock, par value | $ / shares | $ 0.01 | |||||||||||||
Net income from continuing operations | $ 14,000 | |||||||||||||
Net income from discontinued operations | 1,300 | |||||||||||||
BRMR and Everest Merger Sub Inc. [Member] | Continuing Operations [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Revenue | 131,700 | |||||||||||||
BRMR and Everest Merger Sub Inc. [Member] | Discontinued Operations [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Revenue | $ 7,200 | |||||||||||||
BRMR and Everest Merger Sub Inc. [Member] | General And Administrative Expense [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Acquisition costs | $ 25,500 | $ 4,000 | ||||||||||||
BRMR and Everest Merger Sub Inc. [Member] | Common Stock [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Purchase price paid through shares of common stock | shares | 0.29506 | |||||||||||||
Reverse stock split, description | 15-to-1 | 15-to-1 |
Acquisition - Summary of Purcha
Acquisition - Summary of Purchase Price Allocation and Values of Assets Acquired and Liabilities Assumed (Detail) - BRMR and Everest Merger Sub Inc. [Member] $ in Thousands | Feb. 28, 2019USD ($) |
Business Acquisition [Line Items] | |
Fair value of the Company's common stock issued | $ 263,487 |
Fair value of BRMR share-based and other compensation | 12,272 |
Total Fair Value of Consideration | 275,759 |
Cash and cash equivalents | 12,894 |
Accounts receivable | 25,884 |
Assets held for sale - current | 2,296 |
Other current assets | 1,702 |
Unproved properties | 80,843 |
Proved oil and gas properties | 218,866 |
Other property and equipment | 7,059 |
Other assets | 2,461 |
Operating lease right-of-use asset | 7,900 |
Assets held for sale - long-term | 9,611 |
Total assets acquired | 369,516 |
Accounts payable | (16,571) |
Accrued capital expenditures | (5,807) |
Accrued liabilities | (28,824) |
Operating lease liability - current | (1,979) |
Liabilities associated with assets held for sale - current | (7,683) |
Asset retirement obligations | (20,188) |
Operating lease liability - noncurrent | (5,923) |
Liabilities associated with assets held for sale - long-term | (6,782) |
Total liabilities assumed | (93,757) |
Net identifiable assets | $ 275,759 |
Acquisition - Unaudited Pro For
Acquisition - Unaudited Pro Forma Financial Information (Detail) - BRMR and Everest Merger Sub Inc. [Member] - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Business Acquisition [Line Items] | ||
Pro forma total revenues | $ 677,099 | $ 698,850 |
Pro forma net income | $ 44,536 | $ 5,919 |
Pro forma net income per share (basic) | $ 1.25 | $ 0.17 |
Pro forma net income per share (diluted) | $ 1.24 | $ 0.16 |
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 | |
Asset Sale 100 Acres [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Gain (loss) on sale of oil and gas property | $ 0 | |
Proceeds from sale of oil and gas property | $ 500,000 | |
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] | ||
Gain (loss) on sale of oil and gas property | $ 200,000 | |
Proceeds from sale of oil and gas property | $ 800,000 | |
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] | ||
Gain (loss) on sale of oil and gas property | $ 1,500,000 | |
Proceeds from sale of oil and gas property | $ 6,000,000 | |
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] | ||
Gain (loss) on sale of oil and gas property | $ 0 | |
Proceeds from sale of oil and gas property | $ 3,800,000 | |
Area of land | a | 400 | |
Asset Sale 50 Acres [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Gain (loss) on sale of oil and gas property | $ 300,000 | |
Proceeds from sale of oil and gas property | $ 300,000 | |
Area of land | a | 50 | |
Assets Held for Sale [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) |
Assets Held for Sale and Disc_3
Assets Held for Sale and Discontinued Operations - Summary of Assets and Liabilities Held for Sale (Details) $ in Thousands | Dec. 31, 2019USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Total current assets held for sale | $ 1,047 |
Total noncurrent assets held for sale | 9,665 |
Accrued liabilities | 3,500 |
Total current liabilities associated with assets held for sale | 2,815 |
Total noncurrent liabilities associated with assets held for sale | 7,013 |
Assets Held for Sale [Member] | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Accounts receivable | 343 |
Other current assets | 704 |
Total current assets held for sale | 1,047 |
Proved oil and gas properties, net | 9,528 |
Other noncurrent assets | 137 |
Total noncurrent assets held for sale | 9,665 |
Accounts payable | 2,067 |
Accrued liabilities | 570 |
Other current liabilities | 178 |
Total current liabilities associated with assets held for sale | 2,815 |
Asset retirement obligations | 6,488 |
Other liabilities | 525 |
Total noncurrent liabilities associated with assets held for sale | $ 7,013 |
Assets Held for Sale and Disc_4
Assets Held for Sale and Discontinued Operations - Summary of Results of Operations for Discontinued Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2019 | |
Discontinued Operations And Disposal Groups [Abstract] | |||||
Revenues | $ 7,160 | ||||
Depreciation, depletion, amortization and accretion | (550) | ||||
Other operating expenses | (5,296) | ||||
Other income | 2 | ||||
Income from discontinued operations, net of tax | 1,316 | ||||
Income from discontinued operations, net of tax | $ 30 | $ (1,237) | $ 2,705 | $ (182) | $ 1,316 |
Assets Held for Sale and Disc_5
Assets Held for Sale and Discontinued Operations - Additional Information (Details) $ in Millions | Dec. 31, 2019USD ($) |
Discontinued Operations And Disposal Groups [Abstract] | |
Accrued liabilities | $ 3.5 |
Assets Held for Sale and Disc_6
Assets Held for Sale and Discontinued Operations - Summary of Operating and Investing Cash Flow of Discontinued Operations (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Discontinued Operations And Disposal Groups [Abstract] | |
Net cash provided by operating activities | $ 425 |
Net cash provided by investing activities | $ 26 |
Leases - Additional Information
Leases - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Jan. 01, 2019 | |
Leases [Abstract] | ||
Operating lease right-of-use assets | $ 36,975 | $ 10,400 |
Operating lease liability | 37,235 | $ 10,400 |
Operating lease cost | 16,000 | |
Operating lease liability current | $ 12,666 | |
Weighted average remaining lease term | 3 years 8 months 12 days | |
Weighted average discount rate | 5.40% |
Leases - Supplemental Cash Flow
Leases - Supplemental Cash Flow Information Related to Operating Leases (Detail) - USD ($) $ in Thousands | Jan. 01, 2019 | Dec. 31, 2019 |
Cash paid for amounts included in the measurement of lease liabilities: | ||
Operating cash flows for operating leases | $ 5,542 | |
Investing cash flows for operating leases | 10,489 | |
ROU assets added in exchange for lease obligations net of terminations (upon / since adoption) | $ 10,434 | 31,714 |
BRMR and Everest Merger Sub Inc. [Member] | ||
Cash paid for amounts included in the measurement of lease liabilities: | ||
ROU assets and lease obligations acquired in BRMR Merger | $ 7,900 |
Leases - Schedule of Lease Liab
Leases - Schedule of Lease Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2019 | Jan. 01, 2019 |
Operating Leases | ||
2020 | $ 14,424 | |
2021 | 13,004 | |
2022 | 5,524 | |
2023 | 3,611 | |
2024 | 2,110 | |
Thereafter | 2,631 | |
Total lease payments | 41,304 | |
Less imputed interest | (4,069) | |
Total lease liability | $ 37,235 | $ 10,400 |
Leases - Schedule of Future Min
Leases - Schedule of Future Minimum Lease Commitments Under Non-cancellable Leases (Details) $ in Thousands | Dec. 31, 2019USD ($) |
Leases [Abstract] | |
2019 | $ 1,360 |
2020 | 1,060 |
2021 | 929 |
2022 | 755 |
2023 | 755 |
Thereafter | 1,619 |
Total minimum lease payments | $ 6,478 |
Derivative Instruments - Summar
Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail) | 12 Months Ended |
Dec. 31, 2019MMBTU$ / MMBTU$ / bblbbl | |
Natural Gas Swaps Production Period January 2020 – December 2020 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price | 2.67 |
Natural Gas Swaps Production Period January 2020 – March 2020 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price | 2.80 |
Natural Gas Swaps Production Period January 2020 – June 2020 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 80,000 |
Weighted Average Price | 2.67 |
Natural Gas Swaps Production Period April 2020 – June 2020 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price | 2.75 |
Natural Gas Swaps Production Period July 2020 – December 2020 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price | 2.60 |
Natural Gas Swaps Production Period January 2020 – March 2021 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 25,000 |
Weighted Average Price | 2.60 |
Natural Gas Swaps Production Period July 2020 – March 2021 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price | 2.58 |
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) |
Basis Swaps Production Period January 2020 - March 2020 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price ($/MMBtu) | (0.39) |
Natural Gas Collars Production Period January 2020 - March 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.65 |
Natural Gas Collars Production Period January 2020 - March 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 2.98 |
Natural Gas Collars Production Period January 2020 - December 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.49 |
Natural Gas Collars Production Period January 2020 - December 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 ($/MMBtu) | 2.88 |
Natural Gas Collars Production Period April 2020 - June 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 15,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.50 |
Natural Gas Collars Production Period April 2020 - June 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 15,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 2.80 |
Natural Gas Three-way Collars Production Period January 2020 - December 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.70 |
Natural Gas Three-way Collars Production Period January 2020 - December 2020 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.40 |
Natural Gas Three-way Collars Production Period January 2020 - December 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 3.05 |
Natural Gas Three-way Collars Production Period January 2020 - March 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.72 |
Natural Gas Three-way Collars Production Period January 2020 - March 2020 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.25 |
Natural Gas Three-way Collars Production Period January 2020 - March 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 3.15 |
Natural Gas Three-way Collars Production Period January 2020 - June 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.82 |
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 ($/MMBtu) | 2.40 |
Natural Gas Three-way Collars Production Period January 2020 - June 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 3.11 |
Natural Gas Three-way Collars Production Period October 2019 - June 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 45,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.55 |
Natural Gas Three-way Collars Production Period October 2019 - June 2020 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 45,000 |
Weighted Average Price, Floor ($/MMBtu) | 2.25 |
Natural Gas Three-way Collars Production Period October 2019 - June 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 45,000 |
Weighted Average Price, Ceiling ($/MMBtu) | 2.81 |
Natural Gas Call/Put Options 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 | 2.25 |
Natural Gas Call/Put Options Production Period January 2020 - December 2020 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price | 2.30 |
Natural Gas Call/Put Options Production Period January 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price | 2.75 |
Natural Gas Call/Put Options Production Period January 2022 - December 2022 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price | 3 |
Oil Swaps Production Period January 2020 - December 2020 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price | 57.07 |
Volume (Bbls/d) | bbl | 1,500 |
Oil Swaps Production Period July 2020 - December 2020 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price | 56.53 |
Volume (Bbls/d) | bbl | 1,000 |
Oil Swaps Production Period July 2020 - March 2021 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price | 53.20 |
Volume (Bbls/d) | bbl | 250 |
Oil Swaps Production Period January 2021 - March 2021 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price | 53 |
Volume (Bbls/d) | bbl | 250 |
Oil Collars Production Period January 2020 - December 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Floor ($/MMBtu) | $ / bbl | 50 |
Volume (Bbls/d) | bbl | 500 |
Oil Collars Production Period January 2020 - December 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Ceiling ($/MMBtu) | $ / bbl | 64 |
Volume (Bbls/d) | bbl | 500 |
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) | $ / bbl | 62.50 |
Volume (Bbls/d) | bbl | 2,000 |
Oil Three-way Collars Production Period January 2020 - June 2020 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Floor ($/MMBtu) | $ / bbl | 55 |
Volume (Bbls/d) | bbl | 2,000 |
Oil Three-way Collars Production Period January 2020 - June 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Ceiling ($/MMBtu) | $ / bbl | 74 |
Volume (Bbls/d) | bbl | 2,000 |
Oil Collars Production Period July 2020 - December 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Floor ($/MMBtu) | $ / bbl | 52 |
Volume (Bbls/d) | bbl | 500 |
Oil Collars Production Period July 2020 - December 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Ceiling ($/MMBtu) | $ / bbl | 60 |
Volume (Bbls/d) | bbl | 500 |
Oil Call/Put Option Production Period July 2020 - December 2020 [Member] | Put Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price | 45 |
Volume (Bbls/d) | bbl | 500 |
Oil Collars Production Period January 2020 - March 2020 [Member] | Put Option [Member] | Purchase [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Floor ($/MMBtu) | $ / bbl | 60 |
Volume (Bbls/d) | bbl | 500 |
Oil Collars Production Period January 2020 - March 2020 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price, Ceiling ($/MMBtu) | $ / bbl | 67 |
Volume (Bbls/d) | bbl | 500 |
Oil Call/Put Option Production Period January 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price | 56.80 |
Volume (Bbls/d) | bbl | 500 |
Propane Swaps Production Period January 2020 - December 2020 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price | $ / bbl | 21.46 |
Volume (Bbls/d) | bbl | 750 |
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, 2019 | Dec. 31, 2018 | |
Derivatives, Fair Value [Line Items] | |||
Gross Amount | $ 34,595 | $ 6,870 | |
Netting Adjustments | [1] | (3,764) | (845) |
Net Amount Presented in Balance Sheets | 30,831 | 6,025 | |
Gross Amount | (7,478) | (1,171) | |
Netting Adjustments | [1] | 3,764 | 845 |
Net Amount Presented in Balance Sheets | (3,714) | (326) | |
Other Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 33,762 | 4,960 | |
Netting Adjustments | [1] | (3,719) | (845) |
Net Amount Presented in Balance Sheets | 30,043 | 4,115 | |
Other Noncurrent Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 833 | 1,910 | |
Netting Adjustments | [1] | (45) | |
Net Amount Presented in Balance Sheets | 788 | 1,910 | |
Current Liabilities [Member] | Accrued Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (5,081) | (845) | |
Netting Adjustments | [1] | 3,719 | 845 |
Net Amount Presented in Balance Sheets | (1,362) | ||
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (2,397) | (326) | |
Netting Adjustments | [1] | 45 | |
Net Amount Presented in Balance Sheets | $ (2,352) | $ (326) | |
[1] | The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. |
Derivative Instruments - Summ_2
Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments | $ 48,596 | $ (21,169) | $ 45,365 |
Commodity Contract [Member] | Gain (Loss) on Derivative Instruments [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments | $ 48,596 | $ (21,169) | $ 45,365 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Detail) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total fair value | $ 27,117 | $ 5,699 |
Commodity Derivative Instruments [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total fair value | 27,117 | 5,699 |
Level 2 [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total fair value | 27,117 | 5,699 |
Level 2 [Member] | Commodity Derivative Instruments [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total fair value | $ 27,117 | $ 5,699 |
Debt - Additional Information (
Debt - Additional Information (Detail) - USD ($) | Nov. 11, 2019 | Nov. 10, 2019 | 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, 2019 | Sep. 19, 2019 | Sep. 18, 2019 | May 06, 2019 | May 05, 2019 | Feb. 27, 2019 | Aug. 01, 2017 | Feb. 23, 2017 |
Debt Instrument [Line Items] | |||||||||||||||||||
Debt instrument, covenant description | The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. | ||||||||||||||||||
Ratio of total funded net debt to EBITDAX | 2.75% | 3.00% | |||||||||||||||||
BRMR and Everest Merger Sub Inc. [Member] | Minimum [Member] | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Ratio of total funded net debt to EBITDAX | 4.00% | 4.00% | 4.00% | 4.00% | |||||||||||||||
Revolving Credit Facility [Member] | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Revolving credit facility | $ 1,000,000,000 | $ 500,000,000 | $ 500,000,000 | ||||||||||||||||
Credit facility maturity year | 2018 | ||||||||||||||||||
Applicable margin | 0.50% | ||||||||||||||||||
Borrowing base | $ 175,000,000 | $ 500,000,000 | $ 500,000,000 | $ 400,000,000 | $ 400,000,000 | $ 375,000,000 | $ 225,000,000 | $ 125,000,000 | |||||||||||
Revolving credit facility, extended maturity month and year | 2024-02 | 2020-02 | |||||||||||||||||
Outstanding borrowings | 130,000,000 | ||||||||||||||||||
Outstanding letters of credit | 29,200,000 | ||||||||||||||||||
Available capacity on the Revolving Credit Facility | $ 340,800,000 | ||||||||||||||||||
Percentage of company's properties and guarantees secured by mortgages | 85.00% | ||||||||||||||||||
Revolving Credit Facility [Member] | Minimum [Member] | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Commitment fees on unused portion of revolving credit facility | 0.375% | ||||||||||||||||||
Revolving Credit Facility [Member] | Maximum [Member] | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Commitment fees on unused portion of revolving credit facility | 0.50% | ||||||||||||||||||
Revolving Credit Facility [Member] | BRMR and Everest Merger Sub Inc. [Member] | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Borrowing base | $ 375,000,000 | ||||||||||||||||||
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 | 2023 | |||||||||||||||||
Notes issued percentage price | 97.903% | ||||||||||||||||||
Debt instrument, proceeds | $ 525,500,000 | ||||||||||||||||||
8.875% Senior Unsecured Notes Due 2023 [Member] | Maximum [Member] | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Debt instrument repurchase amount | $ 50,000,000 | ||||||||||||||||||
8.875% Senior Unsecured Notes Due 2023 [Member] | Level 2 [Member] | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Fair value of senior unsecured notes | $ 471,100,000 | ||||||||||||||||||
12.0% 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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
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 | $ 1 | $ 0.9 | $ 0.7 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) $ in Millions | Oct. 08, 2019Directorshares | Aug. 02, 2019Directorshares | Jun. 18, 2019Directorshares | Feb. 28, 2019Officershares | May 16, 2018Directorshares | May 17, 2017Directorshares | May 18, 2016Directorshares | Dec. 31, 2019USD ($)shares | Dec. 31, 2017USD ($) |
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 | $ | $ 2.4 | ||||||||
Weighted average period for units to vest | 1 year | ||||||||
Restricted Stock Units [Member] | Board of Directors [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Unrecognized compensation cost | $ | $ 0.9 | ||||||||
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 | $ | $ 1.7 | ||||||||
Weighted average period for units to vest | 2 years | ||||||||
Fair value of performance stock units vested | $ | $ 3.7 | $ 0.8 | |||||||
Restricted Stock [Member] | Board of Directors [Member] | May 2016 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Number of common stock issued | 9,963 | ||||||||
Number of non employee directors | Director | 3 | ||||||||
Restricted Stock [Member] | Board of Directors [Member] | May 2017 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Number of common stock issued | 10,212 | ||||||||
Number of non employee directors | Director | 3 | ||||||||
Restricted Stock [Member] | Board of Directors [Member] | May 2018 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Number of common stock issued | 15,476 | ||||||||
Number of non employee directors | Director | 3 | ||||||||
Restricted Stock [Member] | Board of Directors [Member] | June 2019 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Number of common stock issued | 53,328 | ||||||||
Number of non employee directors | Director | 8 | ||||||||
Restricted Stock [Member] | Officer [Member] | February 2019 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Number of common stock issued | 70,409 | ||||||||
Number of officers | Officer | 2 | ||||||||
Restricted Stock [Member] | Officer [Member] | February 2019 [Member] | August 28, 2019 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Vesting percentage | 25.00% | ||||||||
Restricted Stock [Member] | Officer [Member] | February 2019 [Member] | February 28, 2020, August 28, 2020 and February 28, 2021 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Vesting percentage | 75.00% | ||||||||
Unrestricted Stock [Member] | Board of Directors [Member] | August 2019 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Number of common stock issued | 26,935 | ||||||||
Number of non employee directors | Director | 4 | ||||||||
Unrestricted Stock [Member] | Board of Directors [Member] | October 2019 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Number of common stock issued | 22,661 | ||||||||
Number of non employee directors | Director | 4 | ||||||||
2019 Long-Term Incentive Plan [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Number of shares authorized to be issue | 2,650,000 | ||||||||
Number of shares are available for future grants | 1,745,810 |
Stock-Based Compensation - Sche
Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | $ 8,784 | $ 7,891 | $ 9,301 |
Restricted Stock Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | 4,141 | 4,014 | 5,301 |
Performance Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | 3,706 | 3,497 | 3,622 |
Restricted and Unrestricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | $ 937 | $ 380 | $ 378 |
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, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of shares, Beginning Balance | 233,960 | |
Number of shares, Granted | 417,584 | |
Number of shares, Vested | (212,140) | |
Number of shares, Forfeited | (1,845) | |
Number of shares, Ending Balance | 437,559 | |
Weighted average grant date fair value, Beginning Balance | $ 29.27 | |
Weighted average grant date fair value, Granted | 6.46 | |
Weighted average grant date fair value, Vested | 28.71 | |
Weighted average grant date fair value, Forfeited | 13.11 | |
Weighted average grant date fair value, Ending Balance | $ 7.83 | |
Aggregate intrinsic value | $ 3,474 | $ 3,685 |
Stock-Based Compensation - Su_2
Stock-Based Compensation - Summary of Performance Stock Unit Awards Activity (Detail) - Performance Units [Member] - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of shares, Beginning Balance | 346,589 | |
Number of shares, Granted | 261,139 | |
Number of shares, Vested | (270,068) | |
Number of shares, Forfeited | (17,540) | |
Number of shares, Ending Balance | 320,120 | |
Weighted average grant date fair value, Beginning Balance | $ 27.68 | |
Weighted average grant date fair value, Granted | 7.25 | |
Weighted average grant date fair value, Vested | 27.57 | |
Weighted average grant date fair value, Forfeited | 24.86 | |
Weighted average grant date fair value, Ending Balance | $ 11.26 | |
Aggregate intrinsic value | $ 2,522 | $ 716 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Volatility | 65.10% | 89.70% | 50.41% |
Risk-free interest rate | 1.83% | 2.37% | 1.34% |
Net Income (Loss) Per Share - A
Net Income (Loss) Per Share - Additional Information (Detail) | Feb. 28, 2019 | Dec. 31, 2019 |
Business Acquisition [Line Items] | ||
Reverse stock split | 0.067 | |
BRMR and Everest Merger Sub Inc. [Member] | Common Stock [Member] | ||
Business Acquisition [Line Items] | ||
Reverse stock split, description | 15-to-1 | 15-to-1 |
Reverse stock split | 0.067 |
Net Income (Loss) Per Share - C
Net Income (Loss) Per Share - Calculation of Basic and Diluted Weighted-Average Number of Shares of Common Stock and EPS (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Basic: | |||||||
Net income, basic | $ 31,762 | $ 18,826 | $ 8,525 | ||||
Net income, shares, basic | 33,211 | 19,999 | 17,479 | ||||
Net income, per shares, basic | $ 1.81 | $ 0.20 | $ (0.95) | $ (0.13) | $ 0.96 | $ 0.94 | $ 0.49 |
Weighted-average number of shares of common stock-diluted: | |||||||
Restricted stock and performance unit awards | 113 | 88 | 200 | ||||
Diluted: | |||||||
Net income, diluted | $ 31,762 | $ 18,826 | $ 8,525 | ||||
Net income, shares, diluted | 33,324 | 20,087 | 17,679 | ||||
Net income, per shares, diluted | $ 1.80 | $ 0.20 | $ (0.95) | $ (0.13) | $ 0.95 | $ 0.94 | $ 0.48 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Board of Directors [Member] | EnCap and Affiliates [Member] | Montage Resources Corporation [Member] | |||
Related Party Transaction [Line Items] | |||
Percentage of ownership interest | 40.00% | ||
Former Chairman, President and Chief Executive Officer [Member] | |||
Related Party Transaction [Line Items] | |||
Flight charter services fees | $ 0.6 | $ 0.6 | |
Maximum [Member] | Former Chairman, President and Chief Executive Officer [Member] | |||
Related Party Transaction [Line Items] | |||
Flight charter services fees | $ 0.1 |
Commitments and Contingencies -
Commitments and Contingencies - Other Commitments (Detail) $ in Thousands | Dec. 31, 2019USD ($) | |
Other Commitments [Line Items] | ||
2020 | $ 140,912 | |
2021 | 141,211 | |
2022 | 143,227 | |
2023 | 141,088 | |
2024 | 139,599 | |
Thereafter | 933,370 | |
Total | 1,639,407 | |
Firm Transportation [Member] | ||
Other Commitments [Line Items] | ||
2020 | 100,101 | [1] |
2021 | 99,828 | [1] |
2022 | 99,828 | [1] |
2023 | 99,828 | [1] |
2024 | 100,101 | [1] |
Thereafter | 722,369 | [1] |
Total | 1,222,055 | [1] |
Gas Processing, Gathering, and Compression Services [Member] | ||
Other Commitments [Line Items] | ||
2020 | 40,811 | [2] |
2021 | 41,383 | [2] |
2022 | 43,399 | [2] |
2023 | 41,260 | [2] |
2024 | 39,498 | [2] |
Thereafter | 211,001 | [2] |
Total | $ 417,352 | [2] |
[1] | Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements the Company’s proportionate share of costs based on its working interest. | |
[2] | Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing and gathering 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 - Components of Inco
Income Tax - Components of Income Tax Expense From Continuing Operations (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Current | |||
Federal | $ 0 | $ 0 | $ 0 |
Income Tax - Schedule of Effect
Income Tax - Schedule of Effective Income Tax Rate Reconciliation (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||||||
Income from continuing operations | $ 14,034 | $ 5,521 | $ 24,807 | $ (13,916) | $ 30,446 | $ 18,826 | $ 8,525 |
Statutory rate | 21.00% | 21.00% | 35.00% | ||||
Income tax benefit computed at statutory rate | $ 6,394 | $ 3,953 | $ 2,984 | ||||
Reconciling items: | |||||||
State income taxes | 200 | ||||||
Deferred true-up | (6,686) | ||||||
Share-based compensation | 1,201 | (576) | |||||
Other permanent differences | 2,376 | 54 | 50 | ||||
Executive compensation limitation | 1,263 | 268 | 496 | ||||
Change in valuation allowance | 7,959 | $ (5,476) | (145,449) | ||||
Change in State tax rate | $ (11,506) | $ 142,495 |
Income Tax - Components of Defe
Income Tax - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred tax asset: | |||
Oil and gas properties and equipment | $ 11,613 | $ 62,616 | $ 93,854 |
Federal tax loss carryforwards | 306,743 | 140,059 | 114,652 |
Derivative instruments and other | 1,064 | ||
Interest expense limitation carryforward | 25,932 | ||
Operating lease right-of-use liabilities | 8,278 | ||
Other, net | 5,240 | 7,398 | 4,639 |
Deferred tax asset | 357,806 | 210,073 | 214,209 |
Valuation allowance | (343,577) | (208,324) | (213,800) |
Net deferred tax assets | 14,229 | 1,749 | 409 |
Deferred tax liability: | |||
Derivative instruments and other | 6,009 | 1,197 | |
Other, net | 552 | 409 | |
Operating lease right-of-use assets | 8,220 | ||
Net deferred tax liability | $ 14,229 | $ 1,749 | $ 409 |
Income Tax - Additional Informa
Income Tax - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax [Line Items] | |||
Reserve for uncertain tax positions | $ 0 | $ 0 | $ 0 |
Earliest year open to examination | 2007 | ||
Federal [Member] | |||
Income Tax [Line Items] | |||
U.S. federal tax loss carryforwards ("NOL") | $ 1,400,000,000 | ||
Permanently lost amount of U.S. federal tax loss carryforwards ("NOL") | $ 386,000,000 | ||
Tax loss carryforwards expiration year | 2034 |
Subsidiary Guarantors - Additio
Subsidiary Guarantors - Additional Information (Detail) | Dec. 31, 2019 | Nov. 11, 2019 | Jul. 06, 2015 |
8.875% Senior Unsecured Notes Due 2023 [Member] | |||
Guarantee Obligations [Line Items] | |||
Debt instrument interest rate | 8.875% | 8.875% | 8.875% |
Quarterly Financial Informati_3
Quarterly Financial Information (unaudited) - Additional Information (Details) | Feb. 28, 2019 | Dec. 31, 2019 |
Business Acquisition [Line Items] | ||
Reverse stock split | 0.067 | |
BRMR and Everest Merger Sub Inc. [Member] | Common Stock [Member] | ||
Business Acquisition [Line Items] | ||
Reverse stock split, description | 15-to-1 | 15-to-1 |
Reverse stock split | 0.067 |
Quarterly Financial Informati_4
Quarterly Financial Information (unaudited) (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total operating revenues | $ 174,109 | $ 163,295 | $ 155,540 | $ 141,497 | $ 171,208 | $ 130,123 | $ 103,622 | $ 110,192 | $ 634,441 | $ 515,145 | $ 383,659 |
Total operating expenses | 153,146 | 158,394 | 145,370 | 136,642 | 123,590 | 108,929 | 92,989 | 95,651 | 593,552 | 421,159 | 370,990 |
Operating income | 20,963 | 4,901 | 10,170 | 4,855 | 47,618 | 21,194 | 10,633 | 14,541 | 40,889 | 93,986 | 12,669 |
Income from continuing operations | 14,034 | 5,521 | 24,807 | (13,916) | 30,446 | 18,826 | 8,525 | ||||
Income from discontinued operations, net of income tax | 30 | (1,237) | 2,705 | (182) | 1,316 | ||||||
Net income (loss) | $ 14,064 | $ 4,284 | $ 27,512 | $ (14,098) | $ 36,490 | $ 3,998 | $ (19,036) | $ (2,626) | $ 31,762 | $ 18,826 | $ 8,525 |
Income (loss) per common share: | |||||||||||
Basic and diluted from continuing operations | $ 0.39 | $ 0.15 | $ 0.69 | $ (0.54) | |||||||
Basic and diluted from discontinued operations | (0.03) | 0.08 | (0.01) | ||||||||
Basic and diluted | $ 0.39 | $ 0.12 | $ 0.77 | $ (0.55) | |||||||
Basic | $ 1.81 | $ 0.20 | $ (0.95) | $ (0.13) | $ 0.96 | $ 0.94 | $ 0.49 | ||||
Diluted | $ 1.80 | $ 0.20 | $ (0.95) | $ (0.13) | $ 0.95 | $ 0.94 | $ 0.48 |
Supplemental Oil and Natural _3
Supplemental Oil and Natural Gas Information (unaudited) - Summary of Capitalized Costs (Detail) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Oil and natural gas properties: | ||
Unproved properties | $ 508,576 | $ 482,475 |
Proved properties | 2,783,232 | 2,188,233 |
Total oil and natural gas properties | 3,291,808 | 2,670,708 |
Less accumulated depreciation, depletion and amortization | (1,532,127) | (1,380,650) |
Net oil and natural gas properties | $ 1,759,681 | $ 1,290,058 |
Supplemental Oil and Natural _4
Supplemental Oil and Natural Gas Information (unaudited) - Summary of Costs Incurred in Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Acquisition costs: | |||
Unproved properties | $ 106,758 | $ 107,862 | $ 57,498 |
Proved properties | 201,884 | 4,072 | |
Development cost | 339,628 | 239,467 | 257,119 |
Exploration cost | 11,142 | 20,957 | 18,791 |
Asset retirement obligations | 29,346 | ||
Total acquisition, development and exploration costs | $ 688,758 | $ 372,358 | $ 333,408 |
Supplemental Oil and Natural _5
Supplemental Oil and Natural Gas Information (unaudited) - Proved Developed and Proved Undeveloped Reserves (Detail) | 12 Months Ended | |||
Dec. 31, 2019BcfeBcfMBbls | Dec. 31, 2018BcfeBcfMBbls | Dec. 31, 2017BcfeBcfMBbls | Dec. 31, 2016BcfeBcfMBbls | |
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves (energy), beginning balance | Bcfe | 1,864.7 | 1,458.6 | 469.4 | |
Revisions (energy) | Bcfe | (59.6) | (42.8) | 695.6 | |
Extensions and discoveries (energy) | Bcfe | 599.2 | 558.1 | 405.1 | |
Acquisitions (energy) | Bcfe | 525.5 | 16.3 | 1.9 | |
Divestitures (energy) | Bcfe | (0.2) | |||
Production (energy) | Bcfe | (200) | (125.3) | (113.4) | |
Proved Developed and Undeveloped Reserves (energy), ending balance | Bcfe | 2,729.8 | 1,864.7 | 1,458.6 | |
Proved developed reserves (energy) | Bcfe | 1,494.2 | 670.7 | 456 | 297.8 |
Proved undeveloped reserves (energy) | Bcfe | 1,235.6 | 1,194.1 | 1,002.6 | 171.6 |
Natural Gas [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, beginning balance | Bcf | 1,531.2 | 1,090.1 | 386.4 | |
Revisions | Bcf | (77) | 5.6 | 515.1 | |
Extensions and discoveries | Bcf | 418.7 | 515.8 | 274.4 | |
Acquisitions | Bcf | 418.9 | 9.9 | 1.6 | |
Divestitures | Bcf | (0.2) | |||
Production | Bcf | (154.1) | (90) | (87.4) | |
Proved Developed and Undeveloped Reserves, ending balance | Bcf | 2,137.7 | 1,531.2 | 1,090.1 | |
Proved developed reserves | Bcf | 1,183.2 | 501 | 334.6 | 226.1 |
Proved undeveloped reserves | Bcf | 954.5 | 1,030.2 | 755.5 | 160.4 |
Natural Gas Liquids [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, beginning balance | 34,730.9 | 41,930.6 | 8,675.5 | |
Revisions | 4,454.5 | (8,307.5) | 20,327.3 | |
Extensions and discoveries | 19,016.3 | 4,059.4 | 15,598.8 | |
Acquisitions | 14,844 | 551.4 | 42.6 | |
Production | (4,686.3) | (3,503) | (2,713.6) | |
Proved Developed and Undeveloped Reserves, ending balance | 68,359.4 | 34,730.9 | 41,930.6 | |
Proved developed reserves | 39,316.3 | 20,213.8 | 13,782.9 | 7,520 |
Proved undeveloped reserves | 29,043.2 | 14,517.2 | 28,147.7 | 1,155.5 |
Oil [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed and Undeveloped Reserves, beginning balance | 20,852.1 | 19,480.8 | 5,157.7 | |
Revisions | (1,569.8) | 231.2 | 9,746.8 | |
Extensions and discoveries | 11,078.1 | 2,995.7 | 6,192.9 | |
Acquisitions | 2,915.2 | 522.2 | 5.8 | |
Production | (2,950.8) | (2,377.8) | (1,622.4) | |
Proved Developed and Undeveloped Reserves, ending balance | 30,324.8 | 20,852.1 | 19,480.8 | |
Proved developed reserves | 12,512.6 | 8,058.7 | 6,449.6 | 4,439.5 |
Proved undeveloped reserves | 17,812.2 | 12,793.4 | 13,031.2 | 718.1 |
Supplemental Oil and Natural _6
Supplemental Oil and Natural Gas Information (unaudited) - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2019Bcfe | Dec. 31, 2018Bcfe | Dec. 31, 2017BcfeWell | |
Reserve Quantities [Line Items] | |||
Extensions | 599.2 | 558.1 | 405.1 |
Developments | 100.5 | 148.3 | |
Revisions | (59.6) | (42.8) | 695.6 |
Revisions due to (reductions) improvements in SEC pricing | 15 | 607.2 | |
Revisions due to changes in pricing differentials | 6.8 | 61.4 | |
Revision due to outperforming previous estimate | 67.5 | 69.6 | |
Revisions offset due to decision to not develop certain proved, undeveloped reserves within five years | 42.6 | ||
Acquisition of proved developed, proved assets and proved undeveloped leasehold acreage | 525.5 | 16.3 | 1.9 |
Divestiture of non-operated proved developed well | 0.2 | ||
Revisions offset due to change in well spacing | (98) | ||
Revisions offset due to change in five year development plan | (34.1) | ||
Undeveloped extensions | 498.7 | ||
Revisions due to downward in SEC pricing and differentials | (277.3) | ||
Revision due to adjustments in drilling schedule | 44.2 | ||
Revisions offset due to change in well performance, capital allocation and operating expense | 261.9 | ||
Discount Rate [Member] | Valuation Technique, Discounted Cash Flow [Member] | |||
Reserve Quantities [Line Items] | |||
Discount rate | 10 | ||
Non-operated Well [Member] | |||
Reserve Quantities [Line Items] | |||
Developments | 7 | ||
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 | 23.3 | 398.2 | |
Undeveloped extensions | 269.4 | ||
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 | 70.2 | 11.6 | |
Undeveloped extensions | 229.3 |
Supplemental Oil and Natural _7
Supplemental Oil and Natural Gas Information (unaudited) - Standardized Measure of Discounted Net Future Cash Flows (Detail) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract] | ||||
Future cash inflows (total revenues) | $ 8,212,521 | $ 6,730,000 | $ 4,750,238 | |
Future production costs | (3,867,182) | (2,964,098) | (2,332,310) | |
Future development costs (capital costs) | (982,321) | (855,932) | (879,399) | |
Future income tax expense | (633,086) | (136,472) | ||
Future net cash flows | 2,729,932 | 2,773,498 | 1,538,529 | |
10% annual discount for estimated timing of cash flows | (1,534,108) | (1,444,188) | (808,843) | |
Standardized measure of Discounted Future Net Cash Flow | $ 1,195,824 | $ 1,329,310 | $ 729,686 | $ 205,981 |
Supplemental Oil and Natural _8
Supplemental Oil and Natural Gas Information (unaudited) - Changes in Standardized Measure of Discounted Net Cash Flows (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
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 | $ 1,329,310 | $ 729,686 | $ 205,981 |
Net change in prices and production costs | (531,056) | 369,578 | 653,347 |
Net change in future development costs | 28,481 | 87,466 | (385,042) |
Sales, less production costs | (327,373) | (321,802) | (226,324) |
Extensions | 251,343 | 363,708 | 135,734 |
Acquisitions | 387,117 | 7,468 | 2,365 |
Divestitures | (20) | ||
Revisions of previous quantity estimates | 7,345 | 19,910 | 322,917 |
Previously estimated development costs incurred | 245,931 | 65,035 | 34,102 |
Net changes in taxes | (237,482) | (37,345) | |
Accretion of discount | 132,931 | 72,969 | 20,598 |
Changes in timing and other | (90,723) | (27,343) | (33,992) |
Standardized Measure, end of year | $ 1,195,824 | $ 1,329,310 | $ 729,686 |