Document and Entity Information
Document and Entity Information | 9 Months Ended |
Sep. 30, 2018 | |
Document and Entity Information [Abstract] | |
Document Type | S-1/A |
Amendment Flag | true |
Amendment Description | Amendment filing is to update financials to Q3 |
Document Period End Date | Sep. 30, 2018 |
Trading Symbol | ROAN |
Entity Registrant Name | ROAN RESOURCES, INC. |
Entity Central Index Key | 1,326,428 |
Entity Filer Category | Non-accelerated Filer |
Entity Small Business | false |
Entity Emerging Growth Company | false |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets | |||
Cash and cash equivalents | $ 3,900 | $ 1,471 | $ 6,853 |
Accounts receivable | |||
Oil, natural gas and natural gas liquid sales | 47,365 | 74,527 | 15,701 |
Affiliates | 14,689 | 4,695 | |
Oil, natural gas and natural gas liquid sales-Affiliates | 4,695 | ||
Joint interest owners and other | 110,991 | 320 | 36,086 |
Other | 320 | 2,640 | |
Prepaid drilling advances | 49,279 | ||
Derivative contracts | 203 | 152 | |
Other current assets | 6,412 | 930 | 2,966 |
Total current assets | 232,839 | 82,095 | 64,246 |
Long-term assets | |||
Oil and natural gas properties, successful efforts method | 2,429,892 | 1,876,951 | 325,380 |
Accumulated depreciation, depletion, amortization and impairment | (183,557) | (78,307) | (27,002) |
Oil and natural gas properties, net | 2,246,335 | 1,798,644 | 298,378 |
Other property and equipment, net | 2,935 | 1,147 | |
Deferred financing costs | 4,417 | 2,710 | |
Derivative assets | 996 | ||
Other assets | 459 | ||
Total assets | 2,486,526 | 1,885,592 | 363,083 |
Current liabilities | |||
Accounts payable and accrued liabilities | 198,020 | 10,245 | 28,222 |
Accounts payable and accrued liabilities - Affiliates | 7,748 | 183,820 | |
Accounts payable-Affiliates | 13,102 | ||
Accrued capital expenditures-Affiliates | 151,763 | ||
Revenue payable | 88,029 | 13,009 | |
Revenue payable - Affiliates | 18,955 | ||
Drilling advances | 57,374 | 25,363 | |
Derivative contracts | 64,261 | 9,279 | |
Asset retirement obligations | 535 | 3 | |
Total current liabilities | 415,967 | 203,344 | 66,594 |
Noncurrent liabilities | |||
Long-term debt | 394,639 | 85,339 | 20,000 |
Deferred tax liabilities | 299,662 | ||
Asset retirement obligations | 12,876 | 10,769 | 2,242 |
Derivative contracts | 18,901 | 1,371 | |
Other | 662 | ||
Total liabilities | 1,142,707 | 300,823 | 88,836 |
Commitments and contingencies | |||
Equity | |||
Common stock, $0.001 par value; 800,000,000 shares authorized; 152,539,532 shares issued and outstanding at September 30, 2018 | 153 | ||
Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at September 30, 2018 | |||
Additional paid-in capital | 1,643,431 | ||
Accumulated deficit | (299,765) | ||
Members' equity | 1,584,769 | 274,247 | |
Total equity | 1,343,819 | 1,584,769 | |
Total liabilities and equity | $ 2,486,526 | $ 1,885,592 | $ 363,083 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Operations - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Revenues | ||||||
(Loss) gain on derivative contracts | $ (100,920) | $ 2,385 | $ (6,797) | $ 0 | $ 0 | |
Total revenues | 210,769 | 101,020 | 159,588 | 54,965 | 5,685 | |
Operating expenses | ||||||
Production expenses | 30,111 | 10,450 | 16,872 | 5,090 | 549 | |
Gathering, transportation and processing | 0 | 11,360 | 18,602 | 5,920 | 273 | |
Production taxes | 10,892 | 2,057 | 3,685 | 1,087 | 190 | |
Exploration expenses | 30,129 | 4,475 | 32,629 | 5,258 | 121 | |
Depreciation, depletion, amortization and accretion | 83,630 | 22,176 | 37,012 | 24,909 | 2,060 | |
Accretion of asset retirement obligations | 620 | 364 | 87 | 31 | ||
General and administrative | 40,283 | 22,062 | 31,357 | 5,581 | 2,074 | |
Gain on sale of oil and natural gas properties | 0 | (838) | (838) | |||
Total operating expenses | 195,045 | 71,742 | 139,683 | 47,932 | 5,298 | |
Total operating income | 15,724 | 29,278 | 19,905 | 7,033 | 387 | |
Other income (expense) | ||||||
Interest expense | (4,978) | (441) | (1,461) | (86) | ||
Other income | 13 | 4 | ||||
Net (loss) income before income taxes | 10,746 | 28,837 | ||||
Total other (expense) income | (1,448) | (86) | 4 | |||
Income tax expense | 299,662 | 0 | 0 | |||
Net (loss) income | $ (288,916) | [1] | $ 28,837 | $ 18,457 | $ 6,947 | $ 391 |
Earnings per unit | ||||||
Basic | $ (1.90) | $ 0.35 | $ 0.01 | $ 0.01 | $ 0 | |
Diluted | $ (1.90) | $ 0.35 | $ 0.01 | $ 0.01 | $ 0 | |
Weighted average number of units outstanding | ||||||
Basic | 152,129 | 83,578 | 2,001,370 | 1,242,852 | 403,392 | |
Diluted | 152,129 | 83,578 | 2,001,370 | 1,242,852 | 403,392 | |
Oil sales | ||||||
Revenues | ||||||
Revenues | $ 197,356 | $ 45,702 | $ 76,876 | $ 30,565 | $ 3,972 | |
Natural gas sales | ||||||
Revenues | ||||||
Revenues | 31,900 | 29,857 | 46,303 | 16,093 | 1,055 | |
Natural gas sales | Affiliates | ||||||
Revenues | ||||||
Revenues | 17,056 | 1,027 | ||||
Natural gas liquid sales | ||||||
Revenues | ||||||
Revenues | 38,127 | 21,199 | 35,217 | $ 8,307 | $ 658 | |
Natural gas liquid sales | Affiliates | ||||||
Revenues | ||||||
Revenues | $ 27,250 | $ 850 | ||||
Natural Gas and NGL [Member] | Affiliates | ||||||
Revenues | ||||||
Revenues | $ 7,989 | |||||
[1] | Amounts are allocated to stockholders' equity and members' equity to reflect the Reorganization. See Note 10 - Equity for discussion of the Reorganization. |
Condensed Consolidated Statem_2
Condensed Consolidated Statement of Equity - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Accumulated Deficit | Members' Equity | |
Beginning balance at Dec. 31, 2014 | $ 15,126 | |||||
Contributions from Citizen Members | 82,775 | |||||
Net income | 391 | |||||
Ending balance at Dec. 31, 2015 | 98,292 | |||||
Contributions from Citizen Members | 169,008 | |||||
Net income | 6,947 | |||||
Ending balance at Dec. 31, 2016 | 274,247 | |||||
Contributions from Citizen Members | 95,557 | |||||
Distributions to Citizen Members | (85,614) | |||||
Acquisition of oil and natural gas properties in exchange for equity units | 1,281,743 | |||||
Equity-based compensation | 379 | |||||
Net income | 18,457 | |||||
Ending balance at Dec. 31, 2017 | 1,584,769 | |||||
Ending balance at Dec. 31, 2017 | 1,584,769 | $ 0 | $ 0 | $ 0 | $ 1,584,769 | |
Ending balance, Shares at Dec. 31, 2017 | 0 | |||||
Acquisition of oil and natural gas properties in exchange for equity units | 39,906 | 39,906 | ||||
Equity-based compensation | [1] | 8,060 | 192 | 7,868 | ||
Net income | [1] | (288,916) | (299,765) | 10,849 | ||
Issuance of common stock upon Reorganization | $ 153 | 1,643,239 | (1,643,392) | |||
Issuance of common stock upon Reorganization (shares) | 152,540,000 | |||||
Ending balance at Sep. 30, 2018 | $ 1,343,819 | $ 153 | $ 1,643,431 | $ (299,765) | $ 0 | |
Ending balance, Shares at Sep. 30, 2018 | 152,540,000 | |||||
[1] | Amounts are allocated to stockholders' equity and members' equity to reflect the Reorganization. See Note 10 - Equity for discussion of the Reorganization. |
Condensed Consolidated Statem_3
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities | |||||
Net (loss) income | $ (288,916) | $ 28,837 | $ 18,457 | $ 6,947 | $ 391 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||||
Depreciation, depletion, amortization and accretion | 83,630 | 22,176 | 37,012 | 24,909 | 2,060 |
Accretion of asset retirement obligations | 620 | 364 | 87 | 31 | |
Unproved leasehold amortization and impairment and dry hole expense | 25,642 | 4,475 | 25,377 | 5,258 | |
Gain on sale of oil and natural gas properties | 0 | (838) | (838) | ||
Amortization of deferred financing costs | 571 | 39 | 175 | ||
Amortization of deferred rent | 662 | 0 | |||
Loss (gain) on derivative contracts | 100,920 | (2,385) | 6,797 | 0 | 0 |
Net cash (paid) received upon settlement of derivative contracts | (27,462) | 2,385 | 2,705 | ||
Gain on sale of oil and natural gas property | (838) | ||||
Equity-based compensation | 8,060 | 0 | 379 | ||
Deferred income taxes | 299,662 | 0 | |||
Other | (111) | (8) | (11) | (41) | |
Changes in operating assets and liabilities increasing (decreasing) cash: | |||||
Accounts receivable - Oil, natural gas and natural gas liquid sales | 27,162 | (10,820) | (62,170) | (12,473) | (3,009) |
Accounts receivable - Affiliates | (9,994) | (1,877) | |||
Accounts receivable-Oil, natural gas and natural gas liquid sales-Affiliates | (4,695) | ||||
Accounts receivable - Joint interest owners and other | (110,671) | (8,410) | (10,069) | (33,663) | (2,416) |
Prepaid drilling advances | (55,815) | 0 | |||
Accounts receivable-Other | 1,340 | (1,735) | (847) | ||
Other current assets | (5,398) | (1,805) | (2,314) | (1,218) | (1,799) |
Accounts payable and accrued liabilities | 37,773 | 37,816 | 47,801 | 14,409 | 5,558 |
Accounts payable and accrued liabilities - Affiliates | (24,474) | 1,913 | 13,412 | ||
Drilling advances | 57,374 | (25,363) | (25,363) | 22,760 | 2,590 |
Revenue payable | 88,029 | 13,113 | (5,793) | 10,900 | 2,078 |
Revenue payable-Affiliates | 17,709 | ||||
Net cash provided by operating activities | 206,644 | 59,248 | 60,275 | 36,140 | 4,637 |
Cash flows from investing activities | |||||
Acquisition of oil and natural gas properties | (22,935) | (42,701) | (42,701) | (144,774) | (47,874) |
Capital expenditures for oil and natural gas properties | (485,580) | (138,152) | (167,122) | (96,335) | (18,117) |
Acquisition of other property and equipment | (2,353) | (153) | (1,332) | ||
Proceeds from sale of oil and natural gas properties | 0 | 1,435 | 1,435 | ||
Purchase of investment | 0 | (3,000) | |||
Other | (2,801) | (190) | |||
Net cash used in investing activities | (510,868) | (182,571) | (212,521) | (241,109) | (66,181) |
Cash flows from financing activities | |||||
Proceeds from borrowings | 309,300 | 75,340 | 105,339 | 20,000 | |
Repayment of borrowings | 0 | (40,000) | (40,000) | ||
Deferred financing costs | (2,279) | (2,340) | (2,885) | ||
Deferred offering costs | (368) | 0 | |||
Contributions from Citizen members | 0 | 95,557 | 95,557 | 169,008 | 82,775 |
Distribution to Citizen members | 0 | (11,147) | (11,147) | ||
Net cash provided by financing activities | 306,653 | 117,410 | 146,864 | 189,008 | 82,775 |
Net (decrease) increase in cash and cash equivalents | 2,429 | (5,913) | (5,382) | (15,961) | 21,231 |
Cash and cash equivalents, beginning of period | 1,471 | 6,853 | 6,853 | 22,814 | 1,583 |
Cash and cash equivalents, end of period | 3,900 | 940 | 1,471 | 6,853 | 22,814 |
Supplemental disclosure of cash flow information: | |||||
Cash paid for interest, net of capitalized interest | 4,024 | 341 | 1,036 | 86 | |
Supplemental disclosure of non-cash investing activity: | |||||
Change in accrued capital expenditures | 38,593 | 22,456 | 147,142 | $ 4,922 | $ 2,298 |
Acquisition of oil and natural gas properties for equity | 39,906 | 1,281,743 | 1,281,743 | ||
Distribution to Citizen Members of assets and liabilities | $ 0 | $ (74,467) | $ (74,467) |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (Parenthetical) | Sep. 30, 2018$ / sharesshares |
Statement of Financial Position [Abstract] | |
Common stock, par value (usd per share) | $ / shares | $ 0.001 |
Common shares authorized (shares) | 800,000,000 |
Common shares issued (shares) | 152,539,532 |
Common shares outstanding (shares) | 152,539,532 |
Preferred stock, par value (usd per share) | $ / shares | $ 0.001 |
Preferred shares authorized (shares) | 50,000,000 |
Preferred shares issued (shares) | 0 |
Preferred shares outstanding (shares) | 0 |
Business and Organization
Business and Organization | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Business and Organization | Note 1 – Business and Organization Roan Resources, Inc. (“Roan Inc.”) was formed in September 2018 to facilitate a reorganization and to become the holding company for Roan Resources LLC (“Roan LLC”). In September 2018, a series of transactions were executed with Roan LLC’s members which resulted in Roan LLC becoming a wholly owned subsidiary of Roan Inc. These transactions are hereafter referred to as the “Reorganization” and Roan Inc. with its subsidiaries are collectively referred to as the “Company.” See Note 10 – Equity Roan LLC was initially formed by Citizen Energy II, LLC (“Citizen”) in May 2017. On August 31, 2017, the Company executed a contribution agreement (the “Contribution Agreement”) by and among Roan LLC, Citizen, Linn Energy Holdings, LLC (“LEH”) and Linn Operating, LLC (“LOI”, and together with LEH, “Linn”) pursuant to which, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within an area-of-mutual-interest The contributions of oil and natural gas properties to Roan LLC by Citizen and Linn were determined to meet the definition of a business. However, as Roan LLC had no assets or operations prior to the Contribution, it was determined that Citizen was the acquirer for accounting purposes in accordance with ASC Topic 805, Business Combinations ( ASC 805 ) Note 4 – Acquisitions Note 12 – Transactions with Affiliates The Company was formed to engage in the acquisition, exploration, development, production, and sale of oil and natural gas reserves. The Company’s oil and natural gas properties are located in Central Oklahoma. The Company’s corporate headquarters is located in Oklahoma City, Oklahoma. | Note 1 – Business and Organization Roan Resources LLC (the “Company” or “Roan”) is a Delaware Limited Liability Company formed on May 30, 2017, to engage in the acquisition, development, production, exploration and sale of oil and natural gas reserves. The Company’s oil and natural gas properties are located in Central Oklahoma. The Company’s corporate headquarters is located in Oklahoma City, Oklahoma. On August 31, 2017, the Company executed a contribution agreement (the “Contribution Agreement”) by and among the Company, Citizen Energy II, LLC (“Citizen”), Linn Energy Holdings, LLC (“LEH”) and Linn Operating, LLC (“LOI”, and together with LEH, “Linn”) pursuant to which, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within an area-of-mutual-interest The contributions of oil and natural gas properties to Roan by Citizen and Linn were determined to meet the definition of a business. However, as Roan had no assets or operations prior to the Contribution, it was determined that Citizen was the acquirer for accounting purposes in accordance with ASC 805. As a result, the information in the accompanying financial statements and footnotes for the period prior to the Contribution reflects the historical results of Citizen, as Citizen is the predecessor. Citizen is a Delaware Limited Liability Company formed on July 18, 2014, to engage in the acquisition, development, production, exploration and sale of oil and natural gas properties located in Central Oklahoma. For the period following the Contribution, the information in the accompanying financial statements and footnotes reflects the results of Roan. See Note 4 – Acquisitions and Divestitures In conjunction with the Contribution Agreement, the Company entered into Master Services Agreements with both Citizen and Linn (“MSAs”). Under the MSAs, Citizen and Linn provide certain services in respect to the oil and natural gas properties they contributed to the Company. Such services include serving as operator of the oil and natural gas properties contributed, land administration, marketing, information technology and accounting services. As a result of Citizen and Linn continuing to serve as operator of the contributed assets and contracting directly with vendors for goods and services for operations, Citizen and Linn collect amounts due from joint interest owners for their share of costs and bills the Company for its share of costs. See Note 12 – Transactions with Affiliates |
Basis of Presentation and Signi
Basis of Presentation and Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Significant Accounting Policies | Note 2 – Basis of Presentation and Significant Accounting Policies Basis of Presentation The accompanying financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Use of Estimates The preparation of financial statements and related footnotes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management’s estimates and assumptions is the estimate of proved oil, natural gas and natural gas liquid (“NGLs”) reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from these estimates. Revenue Recognition Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. The Company recognizes revenues from the sale of oil, natural gas and NGLs using the sales method, whereby revenue is recorded based on the Company’s share of volumes sold. If the Company’s aggregate sales volumes for a well are greater (or less) than its proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make up the overproduced (or under produced) imbalance. There were no material imbalances at December 31, 2017 or 2016. Business Combinations The Company accounts for all business combinations using the acquisition method, which involves the use of significant judgment. In a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The Company estimates the fair values of assets acquired and liabilities assumed in a business combination using various assumptions (all of which are Level 3 inputs within the fair value hierarchy). The most significant assumptions typically relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of the proved and unproved oil and natural gas properties, the Company develops estimates of oil, natural gas and NGL reserves. Estimates of reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Additionally, a risk factor is applied to reserves by reserve type based on industry standards. The Company estimates future prices to apply to the estimated net quantities of reserves based on the applicable ownership percentage acquired and estimates future operating and development costs to arrive at estimates of future net cash flows. The future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. Oil and Natural Gas Properties The Company follows the successful efforts method to account for its exploration and production activities. Under this method, costs incurred to purchase, lease, or otherwise acquire a property, whether unproved or proved, are capitalized when incurred. The Company initially capitalizes exploratory well costs pending a determination whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed as incurred. Additionally, costs to operate and maintain wells and field equipment are expensed as incurred. Depletion is computed on a units-of-production unit-of-production Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. The net carrying values of retired, sold or abandoned proved properties that constitute less than a complete unit of depletable property are charged, net of proceeds, to accumulate depreciation, depletion and amortization unless doing so significantly affect the unit-of-production Proceeds from sales of all or a partial interest in individual unproved properties assessed for impairment on a group basis are accounted for as a recovery of costs. No gain or loss is recognized unless the sales proceeds exceed the original cost of the entire interest in the property, in which a gain will be recognized for the excess. Impairment of Oil and Natural Gas Properties Proved oil and natural gas properties are evaluated for impairment annually or when facts or circumstances indicate that the carrying value of those assets may not be recoverable, such as when there are declines in oil and natural gas prices or well performance. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. An impairment loss is indicated if the sum of the estimated undiscounted future cash flows related to an asset group is less than the carrying value of that asset group. If an impairment loss has been incurred, the loss recognized is the excess of the carrying amount over the estimated fair value. The Company calculates the estimated fair value using a discounted future cash flow model. Management’s assumptions associated with the calculation of future cash flows include oil and natural gas prices based on NYMEX futures price strips, as well as other assumptions, including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes, (v) timing of development, and (vi) estimated reserves. A discount rate, consistent with that used by market participants, is applied to the estimated future cash flows in order to estimate fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments. It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) oil and natural gas futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, and (iv) results of future drilling activities. The Company’s unproved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictated that the carrying value of those assets may not be recoverable. Unproved leasehold costs are amortized on a group basis if individually insignificant, and a valuation allowance is established with a monthly amortization charge to exploration expense for the portion of the properties’ total cost that management estimates may never be transferred to proved properties during the lives of the respective leases. The impairment amortization rate considers the Company’s current drilling plans, the remaining terms of the respective leases and the results of exploratory drilling activity, and can be affected by economic factors including oil and natural gas price outlooks, projected capital costs, and available liquidity. Costs of expired or relinquished leases are charged against the valuation allowance. Drilling Advances The Company’s drilling advances consist of cash provided to the Company from its joint interest partners for planned drilling activities. Advances are applied against the joint interest partner’s share of expenses incurred. As noted above, the Company entered into MSAs with Citizen and Linn to perform services, including operating the contributed assets. Any drilling advances due to or from other joint interest owners are maintained by Citizen and Linn. See Note 12 – Transactions with Affiliates Asset Retirement Obligation The Company is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company’s asset retirement obligations (“ARO”) relate to the plugging of wells and the related abandonment of oil and natural gas properties. AROs are recognized as liabilities with an increase to the carrying amounts of the related assets when the obligation is incurred. The cost of the asset, including ARO, is depreciated over the useful life of the asset. Fair value of ARO is measured using the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value and the liability is settled or the well is sold, at which time the liability is removed. Accretion expense is included in accretion expense in the accompany statements of operations. Derivative Instruments The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the balance sheet as derivative assets and derivative liabilities, on a net basis by counterparty. The Company has not designated any of the derivative contracts as fair value or cash flow hedges for accounting purposes for any of the periods presented. Accordingly, net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments and are included in loss on derivative contracts in the accompanying statements of operations. The Company’s cash flow is impacted when the settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty and are reflected as operating activities in the Company’s statements of cash flows. The Company’s firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market Cash and Cash Equivalents The Company maintains its cash balances at credit-worthy financial institutions that are insured by the Federal Deposit Insurance Corporation (“FDIC”). At times, cash balances may be in excess of FDIC limits. The Company has not incurred any losses related to the amounts in excess of FDIC limits. Accounts Receivable Accounts receivable consists mainly of receivables from oil, natural gas and NGL purchasers and joint interest owners on properties the Company operates. Accounts receivable from the sale of oil, natural gas and NGLs are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. The Company routinely reviews outstanding balances, assesses the financial strength of its purchasers and joint interest owners and records a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts, existing economic conditions and other pertinent factors. No bad debt expense was recorded for the years ended December 31, 2017, 2016 or 2015 and the Company had no reserve for bad debts at December 31, 2017 or 2016. Deferred Financing Costs Costs incurred in connection with the Company’s debt are capitalized and amortized as interest expense over the scheduled maturity period. Unamortized costs are associated with the Company’s revolving credit facility and are reflected as a component of long-term assets on the accompanying balance sheets. Equity-Based Compensation In December 2017, the Company granted certain employees performance share units (“PSUs”) pursuant to the Roan Resources LLC Management Incentive Plan (the “Plan”). PSUs issued under this Plan were recognized as equity awards based on their characteristics. The compensation measurement was based on the grant date fair value of the award. Equity compensation is recognized over the requisite service period. For employees directly involved in exploration and development activities, equity compensation is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses or production expense in the statements of operations. Comprehensive Income The Company has no elements of comprehensive income other than net income. Concentrations of Credit Risk The Company sells oil, natural gas and NGLs to various types of customers. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. Additionally, limitations on capacity at processing plants could also impact the Company’s ability to sell its oil, natural gas and NGLs. The Company is subject to credit risk resulting from the concentration of its oil, natural gas and NGL receivables with two significant purchasers. The Company does not believe the loss of any single purchaser would materially impact its results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers. For the years ended December 31, 2017, 2016, and 2015, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues: Year Ended 2017 2016 2015 Sunoco Inc. 40 % 55 % 61 % EnLink Oklahoma Gas Processing, LP 39 % 31 % * Cimarex Energy Company * * 14 % * Revenue from customer was less than 10% in this year The Company’s derivative transactions have been carried out in the over-the-counter over-the-counter Fair Value Measurements The Company follows a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2— Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3— Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers between levels during 2017 or 2016. The carrying values of the Company’s receivables, payables and long-term debt are estimated to be substantially the same as their fair values at December 31, 2017 and 2016. As noted above, the Company carries its derivative financial instruments at fair value. Commitments and Contingencies The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Earnings per Unit The Company uses the treasury stock method to determine the potential dilutive effect of outstanding performance share units. Refer to Note 11 – Performance Share Units Income Taxes The Company is organized as a Delaware limited liability company. The Company is treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of the Company and any related tax credits, for federal income tax purposes, are deemed to pass to the members and are included in the Company’s tax returns even though such net taxable income or loss and tax credits may not have actually been distributed. Accordingly, no tax provision has been made in the financial statements of the Company since the income tax is an obligation of the members. Risks and Uncertainties Historically, the markets for oil, natural gas, and NGLs have experienced significant price fluctuations. Price fluctuations can result from variations in weather, regional levels of production, availability of transportation capacity, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities. A portion of the Company’s oil and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, transportation or refining facilities or equipment or field labor issues, or intentionally as a result of market conditions such as oil or natural gas prices that the Company deems uneconomic. If a substantial amount of the Company’s production is interrupted or shut in, the Company’s cash flows and, in turn, it’s financial condition and results of operations could be materially and adversely affected. |
Recently Issued Accounting Stan
Recently Issued Accounting Standards | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Changes and Error Corrections [Abstract] | |
Recently Issued Accounting Standards | Note 3—Recently Issued Accounting Standards Recently Adopted Accounting Standards In January 2017, the Company adopted Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting 2016-09 In September 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments 2015-16”), 2015-16 Recent Accounting Standards Issued Not Yet Adopted In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers In February 2016, the FASB issued ASU 2016-02, Leases right-of-use |
Acquisitions
Acquisitions | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Business Combinations [Abstract] | ||
Acquisitions | Note 4 – Acquisitions Linn Acquisition As noted in Note 1 – Business and Organization Note 10 – Equity Because the Linn Acquisition was determined to be a business combination as the acquired oil and natural gas properties met the definition of a business, the acquired assets and liabilities were recorded at fair value as of August 31, 2017, the acquisition date. The following assumptions were used to determine the fair value of the oil and natural gas properties: Discount rate 9.50 % Reserve risk factor (1) 35%-100 % Oil price three years NYMEX WTI forward curve Natural gas price three years NYMEX Henry Hub forward curve NGL price 39% of oil price Price escalation (2) 2.00 % (1) Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%. (2) Prices were escalated at the end of the forward curve The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands): Consideration given Equity units $ 1,281,743 Allocation of purchase price Inventory $ 205 Proved oil and natural gas properties 214,647 Unproved oil and natural gas properties 1,086,600 Total assets acquired 1,301,452 Asset retirement obligations (7,547 ) Revenue suspense (12,162 ) Total fair value of net assets acquired $ 1,281,743 The following unaudited pro forma combined results of operations is provided for the nine months ended September 30, 2017 as though the Linn Acquisition had been completed as of the earliest period presented at the time of the acquisition. The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of the assets acquired in the Linn Acquisition. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition. Nine Months Ended (in thousands) Revenue $ 156,593 Net income $ 55,253 Acquisitions of Unproved Properties During the year ended December 31, 2017, the Company acquired, from unrelated third parties, interests in approximately 23,400 net acres of leasehold in separately negotiated transactions for aggregate cash consideration of $49.7 million, all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties. As discussed in Note 12 – Transactions with Affiliates | Note 4 – Acquisitions and Divestitures 2017 Acquisitions and Divestitures Linn Acquisition As noted in Note 1 – Business and Organization Note 10 – Equity As the Linn Acquisition was determined to be a business combination as the acquired oil and natural gas properties met the definition of a business, the acquired assets and liabilities were recorded at fair value as of August 31, 2017, the acquisition date. The following assumptions were used to determine the fair value of the oil and natural gas properties: Discount rate 9.50% Reserve risk factor (1) 35%-100% Oil price three years NYMEX WTI forward curve Natural gas price three years NYMEX Henry Hub forward curve NGL price 39% of oil price Price escalation (2) 2.00% (1) Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%. (2) Prices were escalated at the end of the forward curve The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands): Consideration given Equity units $ 1,281,743 Allocation of purchase price Inventory 205 Proved oil and natural gas properties 214,647 Unproved oil and natural gas properties 1,086,600 Total assets acquired 1,301,452 Asset retirement obligations (7,547 ) Revenue suspense (12,162 ) Total fair value of net assets acquired $ 1,281,743 Revenues of $34.1 million and revenues less direct operating expenses of $26.6 million associated with the assets from the Linn Acquisition are included in the accompanying statement of operations for the year ended December 31, 2017. The following unaudited pro forma combined results of operations is provided for the year ended December 31, 2017, 2016, and 2015 as though the Linn Acquisition had been completed as of January 1, 2015. The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of the assets acquired in the Linn Acquisition. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition. (Unaudited) Year Ended December 31, 2017 2016 2015 (in thousands) Revenue $ 215,588 $ 90,238 $ 28,139 Net income $ 44,269 $ 26,378 $ 6,299 Other 2017 Acquisitions During the year ended December 31, 2017, the Company also acquired, from unrelated third parties, interests in approximately 23,400 net acres of leasehold in separately negotiated transactions for aggregate cash consideration of $49.7 million, all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties. As discussed in Note 12 – Transactions with Affiliates 2016 Acquisitions April 14, 2016 Acquisition On April 14, 2016, the Company acquired an unrelated third party’s interests in approximately 5,791 net acres of leasehold, and related producing properties located in Central Oklahoma. The seller received aggregate consideration of approximately $8.9 million in cash. The effective date for the acquisition was February 1, 2016, with purchase price adjustments calculated as of the closing date on April 14, 2016. The acquisition was accounted for using the acquisition method under ASC 805, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of April 14, 2016. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumes (in thousands): Other 2016 Acquisitions Consideration given Total cash consideration $ 8,854 Allocation of purchase price Proved oil and natural gas properties 1,128 Unproved oil and natural gas properties 7,774 Total oil and natural gas properties acquired 8,902 Asset retirement obligations (48 ) Total fair value of net assets acquired $ 8,854 During the year ended December 31, 2016, the Company also acquired, from unrelated third parties, interests in approximately 62,461 net acres of unproved leasehold in separately negotiated transactions for aggregate cash consideration of $137.6 million, all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties. |
Oil and Natural Gas Properties
Oil and Natural Gas Properties | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | ||
Oil and Natural Gas Properties | Note 5 – Oil and Natural Gas Properties The Company’s oil and natural gas properties are in the continental United States. The oil and natural gas properties include the following: September 30, December 31, (in thousands) Oil and natural gas properties Proved $ 1,276,950 $ 750,492 Unproved 1,152,942 1,126,459 Less: accumulated depreciation, depletion, amortization and impairment (183,557 ) (78,307 ) Oil and natural gas properties, net $ 2,246,335 $ 1,798,644 The Company recorded depletion expense on capitalized oil and natural gas properties of $82.4 million and $22.0 million for the nine months ended September 30, 2018 and 2017, respectively. For the nine months ended September 30, 2018, the Company recorded amortization expense on its unproved oil and natural gas properties of $25.6 million, which is reflected in exploration expense on the accompanying condensed consolidated statements of operations. There was no such expense recorded for the nine months ended September 30, 2017. Unproved leasehold amortization for the nine months ended September 30, 2018 reflects consideration of the Company’s drilling plans and the lease terms of its existing unproved properties. For the nine months ended September 30, 2017, the Company recorded impairment expense on its unproved oil and natural gas properties of $4.5 million for leases which expired. No impairment of proved oil and natural gas properties was recorded for the nine months ended September 30, 2018. | Note 5 – Oil and Natural Gas Properties The Company’s oil and natural gas properties are in the continental United States. The oil and natural gas properties includes the following: December 31, 2017 2016 (in thousands) Oil and natural gas properties Proved $ 750,492 $ 184,376 Unproved 1,126,459 141,004 Less: accumulated depreciation, depletion, amortization and impairment (78,307 ) (27,002 ) Oil and natural gas properties, net $ 1,798,644 $ 298,378 There were no exploratory well costs pending determination of proved reserves at December 31, 2017 or 2016 nor any unsuccessful exploratory dry hole costs during the years ended December 31, 2016 and 2015. During the year ended December 31, 2017, there was $1.3 million associated with exploratory dry hole costs that is included in exploration costs in the accompanying statements of operations. At December 31, 2017 and 2016, the Company’s estimate of undiscounted future cash flows attributable to its proved oil and natural gas properties indicated that the carrying amount was expected to be recovered. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2017, 2016, and 2015. For the years ended December 31, 2017 and 2016, the Company recorded abandonment and impairment expense on its unproved oil and natural gas properties of $4.5 million and $5.3 million, respectively, for leases which have expired, or are expected to expire. Impairment expense on unproved oil and natural gas properties is included in exploration expense in the accompanying statements of operations. There was no abandonment and impairment expense on unproved oil and natural gas properties during the year ended December 31, 2015. |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Asset Retirement Obligations | Note 6 – Asset Retirement Obligations The following is a reconciliation of the changes in the Company’s asset retirement obligation (“ARO”) for the nine months ended September 30, 2018 (in thousands): Asset retirement obligation, December 31, 2017 $10,769 Liabilities incurred or acquired 1,815 Revisions in estimated cash flows 318 Liabilities settled (111 ) Accretion expense 620 Asset retirement obligation, September 30, 2018 13,411 Less: current portion of obligations 535 Asset retirement obligation – long term $12,876 | Note 6 – Asset Retirement Obligations The following is a reconciliation of the changes in the Company’s ARO for the years ended December 31, 2017 and 2016: Year Ended December 31, 2017 2016 (in thousands) Asset retirement obligation, beginning balance $ 2,245 $ 1,161 Liabilities incurred or acquired 8,118 1,054 Revisions in estimated cash flows 42 (16 ) Liabilities settled — (41 ) Accretion expense 364 87 Asset retirement obligation, ending balance 10,769 2,245 Less: current portion of obligations — 3 $ 10,769 $ 2,242 For the year ended December 31, 2017, liabilities incurred or acquired includes $7.5 million assumed as part of the Linn Acquisition. The current portion of ARO is included in accounts payable and accrued liabilities in the accompanying balance sheets. |
Long-Term Debt
Long-Term Debt | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Debt Disclosure [Abstract] | ||
Long-Term Debt | Note 7 – Long-Term Debt In September 2017, the Company entered into a $750.0 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (as amended, the “2017 Credit Facility”). In September 2018, the redetermination resulted in an increase to the borrowing base to $675.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of September 30, 2018, the Company had $ 394.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility. The 2017 Credit Facility is secured by substantially all of the assets of the Company. The Company amended the 2017 Credit Facility in September 2018 to increase the borrowing base as noted above as well as to allow for permitted additional debt of up to $500 million before any reduction in the borrowing base would occur, to reduce the applicable margin for both London Interbank Offered Rate (“LIBOR”) and alternate base rate (“ABR”) loans by 0.25% for each utilization level, and to reduce the commitment fee rate for the two lowest utilization levels to 0.375%. Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides for a commitment fee, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement): Utilization Level Utilization LIBOR Applicable Commitment Level I <25% 2.00 % 1.00 % 0.375 % Level II >25% but <50% 2.25 % 1.25 % 0.375 % Level III >50% but <75% 2.50 % 1.50 % 0.500 % Level IV >75% but <90% 2.75 % 1.75 % 0.500 % Level V >90% 3.00 % 2.00 % 0.500 % The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report. The 2017 Credit Facility also contains financial covenants requiring the Company to comply with a leverage ratio of the Company’s consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of the Company’s consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash Derivatives and Hedging Asset Retirement and Environmental Obligations As of September 30, 2018, the Company was in compliance with the covenants under the 2017 Credit Facility. Prior to the 2017 Credit Facility, Citizen had a two -year, $500.0 million credit facility (“Citizen 2017 Credit Facility”) with an initial borrowing base of $82.5 million. In August 2017, the Citizen 2017 Credit Facility was terminated and the outstanding balance of $20.3 million was repaid. | Note 7 – Long-Term Debt On September 1, 2016, the Company entered into a credit agreement with lender with an initial borrowing base of $20.0 million (the “2016 Credit Facility”). On October 20, 2016, the Company amended the 2016 Credit Facility to increase the borrowing base to $35.0 million. As of December 31, 2016, the Company had $20.0 million of outstanding borrowings under the 2016 Credit Facility. Amounts borrowed under the 2016 Credit Facility bore interest at London Interbank Offered Rate (“LIBOR”) plus an applicable margin, based on the utilization percentage of the facility as provided for in the credit agreement. Additionally, the 2016 Credit Facility provided for a commitment fee of 0.25% and that was payable at the end of each calendar quarter. At December 31, 2016, the 2016 Credit Facility had an interest rate of 2.37%. On April 19, 2017, Citizen replaced its 2016 Credit Facility and entered into a two-year, On September 5, 2017, the Company entered into a $750 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (the “2017 Credit Facility”). In November 2017, the Company increased the borrowing base to $275.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on October 1 and April 1. As of December 31, 2017, the Company had $85.3 million of outstanding borrowings under the 2017 Credit Facility. Principal maturities of the Company’s borrowings, consistent of amounts outstanding under the 2017 Credit Facility, at December 31, 2017 are as follows (in thousands): 2018 $ — 2019 — 2020 — 2021 — 2022 85,339 $ 85,339 At December 31, 2017, the 2017 Credit Facility had an interest rate of 4.03%. Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the alternate base rate (“ABR”). Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides for a commitment fee of 0.50%, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate loans depending on the Utilization Level (as defined in the credit agreement) as of the date of this filing: Utilization Level Utilization LIBOR Margin Applicable Margin Commitment Fee Level I < 25% 2.25% 1.25% 0.500% Level II ³ 2.50% 1.50% 0.500% Level III ³ 2.75% 1.75% 0.500% Level IV ³ 3.00% 2.00% 0.500% Level V ³ 3.25% 2.25% 0.500% The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is limited from hedging in excess of 85% of its future proved production for the next eight quarters per its most recent reserve report. If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report. The 2017 Credit Facility also contains financial covenants requiring the Company to comply with a leverage ratio of the Company’s consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended to exceed 4.00 to 1.00 and a current ratio of the Company’s consolidated current assets to consolidated current liabilities (as defined in the credit agreement) as of the fiscal quarter ended to be less than 1.00 to 1.00. As of December 31, 2017, the Company was in compliance with the covenants under the 2017 Credit Facility. |
Derivative Instruments
Derivative Instruments | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative Instruments | Note 8 – Derivative Instruments The Company utilizes fixed price swaps and basis swaps to manage the price risk associated with the sale of its oil and natural gas production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential, or Panhandle Eastern Pipeline. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The following table reflects the Company’s open commodity contracts at September 30, 2018: 2018 2019 2020 Total Oil fixed price swaps Volume (Bbl) 1,233,180 5,540,670 1,599,500 8,373,350 Weighted-average price $ 57.09 $ 59.86 $ 63.14 $ 60.08 Natural gas fixed price swaps Volume (MMBtu) 8,004,000 29,200,000 12,325,000 49,529,000 Weighted-average price $ 2.94 $ 2.86 $ 2.63 $ 2.81 Natural gas basis swaps Volume (MMBtu) 4,600,000 21,900,000 3,640,000 30,140,000 Weighted-average price $ 0.54 $ 0.58 $ 0.62 $ 0.58 The Company nets the fair value of derivative instruments by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. See Note 9 – Fair Value Measurements As the Company has elected to not account for commodity derivative instruments as hedging instruments, gains or losses resulting from the change in fair value along with the gains or losses resulting in settlement of derivative contracts are reflected in (loss) gain on derivative contracts included in the consolidated statement of operations. The following table presents the Company’s (loss) gain on derivative contracts and net cash (paid) received upon settlement of its derivative contracts for the nine months ended September 30, 2018 and 2017: Nine Months Ended 2018 2017 (in thousands) (Loss) gain on derivative contracts $ (100,920 ) $ 2,385 Net cash (paid) received upon settlement of derivative contracts $ (27,462 ) $ 2,385 Net cash received upon settlement of derivative contracts prior to contractual maturity $ 377 $ 2,255 | Note 8 – Derivative Instruments The Company utilizes fixed price swaps and basis swaps to manage the price risk associated with forecasted sale of its oil and natural gas production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The following table represents the Company’s open commodity contracts at December 31, 2017: Total Oil fixed price swaps 2018 Volume (bbl) 2,374,000 Weighted-average price per bbl $ 54.47 2019 Volume (bbl) 1,140,250 Weighted-average price per bbl $ 54.09 Natural gas fixed price swaps 2018 Volume (mmbtu) 16,440,000 Weighted-average price per mmbtu $ 3.00 2019 Volume (mmbtu) 10,950,000 Weighted-average price per mmbtu $ 2.97 Natural gas basis swaps 2018 Volume (mmbtu) 16,440,000 Weighted-average price per mmbtu $ 0.55 2019 Volume (mmbtu) 10,950,000 Weighted-average price per mmbtu $ 0.55 The Company nets the fair value of derivative instruments by counterparty in the accompanying balance sheets where the right to offset exists. See Note 9 – Fair Value Measurements The Company has elected to not account for commodity derivative instruments as hedging instruments, gains or losses resulting from the change in fair value along with the gains or losses resulting in settlement of derivative contracts are reflected in loss on derivative contracts included in the statement of operations. For the year ended December 31, 2017, loss on derivatives was $6.8 million, which includes $2.7 million of net gain on derivatives settled in 2017. There were no commodity derivative contracts in 2016 or 2015. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | ||
Fair Value Measurements | Note 9 – Fair Value Measurements The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy: Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 — Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3 — Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the nine months ended September 30, 2018, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company’s recurring fair value measurements are performed for its commodity derivatives. Commodity Derivative Instruments Commodity derivative contracts are stated at fair value in the accompanying condensed consolidated balance sheets. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of September 30, 2018 and December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands): September 30, 2018 Level 1 Level 2 Level 3 Gross Fair Netting Carrying Assets Current commodity derivatives $ — $ 4,282 $ — $ 4,282 $ (4,079 ) $ 203 Noncurrent commodity derivatives — 908 — 908 (908 ) — Total assets $ — $ 5,190 $ — $ 5,190 $ (4,987 ) $ 203 Liabilities Current commodity derivatives $ — $ (68,340 ) $ — $ (68,340 ) $ 4,079 $ (64,261 ) Noncurrent commodity derivatives — (19,809 ) — (19,809 ) 908 (18,901 ) Total liabilities $ — $ (88,149 ) $ — $ (88,149 ) $ 4,987 $ (83,162 ) December 31, 2017 Level 1 Level 2 Level 3 Gross Fair Netting Carrying Assets Current commodity derivatives $ — $ 2,856 $ — $ 2,856 $ (2,704 ) $ 152 Noncurrent commodity derivatives — 2,182 — 2,182 (1,186 ) 996 Total assets $ — $ 5,038 $ — $ 5,038 $ (3,890 ) $ 1,148 Liabilities Current commodity derivatives $ — $ (11,983 ) $ — $ (11,983 ) $ 2,704 $ (9,279 ) Noncurrent commodity derivatives — (2,557 ) — (2,557 ) 1,186 (1,371 ) Total liabilities $ — $ (14,540 ) $ — $ (14,540 ) $ 3,890 $ (10,650 ) Non-Recurring The Company’s non- recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations and the determination of the grant date fair value of the Company’s performance share units. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted- cash flow approach using level 3 inputs. The fair value of assets or liabilities associated with purchase price allocations is on a non- recurring basis and is not measured in periods after initial recognition. The grant date fair value of the Company’s performance share units is determined using a Monte Carlo simulation model and is classified as a Level 3 measurement. Please refer to Note 4 – Acquisitions Note 11 – Equity Compensation Other Financial Instruments The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying values of cash and cash equivalents, accounts payable, revenue payable, and accounts receivable approximate fair values due to the short-term maturities of these instruments and the carrying value of long-term debt approximates fair value as the applicable interest rates are variable and reflective of market rates. | Note 9 – Fair Value Measurements Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company’s recurring fair value measurements are performed for its commodity derivatives. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying values of cash and cash equivalents, accounts payable, revenue payable, and accounts receivable approximate fair values due to the short-term maturities of these instruments. Commodity Derivative Instruments Commodity derivative contracts are stated at fair value in the accompanying balance sheets. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands): December 31, 2017 Level 1 Level 2 Level 3 Gross Fair Netting Carrying Assets Current commodity derivatives $ — $ 2,856 $ — $ 2,856 $ (2,704 ) $ 152 Long-term commodity derivatives — 2,182 — 2,182 (1,186 ) 996 Total assets $ — $ 5,038 $ — $ 5,038 $ (3,890 ) $ 1,148 Liabilities Current commodity derivatives $ — $ (11,983 ) $ — $ (11,983 ) $ 2,704 $ (9,279 ) Long-term commodity derivatives — (2,557 ) — (2,557 ) 1,186 (1,371 ) Total liabilities $ — $ (14,540 ) $ — $ (14,540 ) $ 3,890 $ (10,650 ) Non-Recurring The Company applies the provisions of the fair value measurement standard on a non recurring basis to its non financial assets and liabilities, including proved property and assets acquired and liabilities assumed in a business combination. These assets and liabilities are not measured at fair value on a recurring basis, but are subject to fair value adjustments when facts are circumstances arise that indicate a need for measurement. The Company utilizes fair value on a non recurring basis to review its proved oil and natural gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on management’s estimated net discounted future cash flows of proved property. Unobservable inputs included estimates of oil and natural gas production, as the case may be, from the Company’s reserve reports, commodity prices based on the sales contract terms or forward price curves, operating and development costs, and a discount rate based on a market-based weighted average cost of capital (all of which are Level 3 inputs within the fair value hierarchy). The Company’s other non-recurring Note 4 — Acquisitions and Divestitures discounted-cash risk-adjusted non-recurring Performance Share Units |
Equity
Equity | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Equity [Abstract] | ||
Equity | Note 10 – Equity In September 2018 and in conjunction with the Reorganization, the Company issued 152.5 million shares of its Class A common stock to the members of Roan LLC in exchange for their equity interest in Roan LLC. The Reorganization was accounted for as a reverse recapitalization with Roan Inc. as the accounting acquirer and therefore did not result in any change in the accounting basis for the underlying assets. Net income before taxes and equity-based compensation were allocated ratably to the members of Roan LLC and the stockholders of Roan Inc. for the period before and after the Reorganization, respectively. For comparative purposes, the issuance of the shares to the members of Roan LLC at the time of the Reorganization was reflected on a retroactive basis with the units outstanding during each period presented. For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company Agreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued 1.5 billion membership units representing capital interests in Roan LLC (the “LLC Units”) for a 50% equity interest in Roan LLC, to Linn in exchange for the contribution of oil and natural gas properties. See Note 4 – Acquisitions As discussed in Note 4 – Acquisitions For the period January 1, 2017 through August 31, 2017, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (the “Citizen Operating Agreement”), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B. Class A represented capital interests in Citizen and Class B represented interests in profits, losses and distributions. Distributions were made to the Class A and Class B members pro rata in accordance with their membership interests; however, once the Class A members received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B members received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement. | Note 10 – Equity As of December 31, 2017, the Company’s operations were governed by the provisions of the Amended and Restated LLC Agreement (“LLC Agreement”), effective August 31, 2017, and the Company has one class of membership interests outstanding. The membership units (the “Units”) represent capital interests in the Company. Distributions are made pro rata in accordance with their membership interests. As of December 31, 2017, the Company had 10.0 billion Units authorized and 3.0 billion Units issued and outstanding. Pursuant to the LLC Agreement (and as is customary for limited liability companies), the liability of the Members is limited to their contributed capital. In connection with the Contribution, the Company issued 1.5 billion units, which represents a 50% equity interest in the Company, to Linn in exchange for the contribution of oil and natural gas properties. See Note 4 – Acquisitions and Divestitures As Citizen is deemed the historical acquirer, the issuance of 1.5 billion units to Citizen was reflected on a retroactive basis with Citizen having 1,398 Class A units issued and outstanding at the time of the Contribution. For the period January 1, 2017 through August 31, 2017 and the years ended December 31, 2016 and 2015, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (“Citizen Operating Agreement”), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B. Class A represented capital interests in Citizen and Class B represented interests in profits, losses and distributions. Distributions were made to the Series A and Series B Members pro rata in accordance with their membership interests; however, once the Class A received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement. Citizen’s Class B units were considered profits interest and are accounted for in accordance with ASC Topic 710 (“ASC 710”), Compensation – general The Company’s unit activity for the years ended December 31, 2017, 2016, and 2015 is as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Issued and outstanding units, beginning of the year (1) 1,500,000 813,021 165,771 Issuance of units to Citizen Members (1) — 686,979 647,250 Units issued in exchange for contribution of oil and natural gas properties 1,500,000 — — Issued and outstanding units, end of the year 3,000,000 1,500,000 813,021 (1) Reflects exchange of Citizen units for Roan units on retroactive basis During the years ended December 31, 2017, 2016, and 2015, Citizen’s Members made contributions of $95.6 million, $169.0 million, and $82.8 million, respectively, to Citizen to fund its operations. Assets and liabilities held by Citizen as of August 31, 2017 that were not contributed to the Company were deemed distributions to the Citizen Members, which totaled $85.6 million during the year ended December 31, 2017. |
Equity Compensation
Equity Compensation | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||
Equity Compensation | Note 11 – Equity Compensation The Company has adopted the Roan Resources, Inc. Amended and Restated Management Incentive Plan (the “Plan”), which provides for grants of options, stock appreciation rights, restricted stock unit, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards. Prior to the Reorganization, Roan LLC granted performance share units to certain of its employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of performance share units under the Plan, hereafter referred to as the “PSUs,” and are subject to the terms of the Plan and individual award agreements. The amount of PSUs that can be earned range from 0% to 200% based on the Company’s market value on December 31, 2020 (“Performance Period End Date”). The Company’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the Company’s Class A common stock for the 30 consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the issuance of one share of the Company’s Class A common stock. Other than the security in which the PSUs are settled, no terms of the PSUs were modified in connection with the conversion of the PSUs. The following table summarizes information related to the total number of PSUs awarded as of September 30, 2018: Number of Weighted Total Fair PSUs outstanding at December 31, 2017 16,350,000 $ 1.41 $ 23,054 PSUs granted 6,825,000 $ 1.88 $ 12,810 PSUs vested — $ — $ — Conversion (1) (22,016,250 ) $ — $ — PSUs outstanding at September 30, 2018 1,158,750 $ 30.95 $ 35,864 (1) PSUs were converted on a basis of 0.05 to 1.0. There was no change to the deemed fair value of the awards based on assessment of modification. Compensation expense associated with the PSUs for the nine months ended September 30, 2018 was $8.1 million, and is included in general and administrative expenses on the accompanying condensed consolidated statements of operations. Unrecognized expense as of September 30, 2018 for all outstanding PSU awards was $27.4 million and will be recognized over a weighted- average remaining period of 2.25 years. Under the treasury stock method, the PSUs are antidilutive for the weighted average share calculation and therefore are excluded from dilutive weighted average shares in the accompanying condensed consolidated statements of operations. The grant date fair value of the PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned and estimated Company value on the Performance Period End Date. The grant date fair value of the PSUs is expensed on a straight-line basis from the grant date to the Performance Period End Date. The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSUs granted during the following periods: Six Months Ended Three Months Ended Company enterprise value (in billions) $ 4.56 $ 4.19 Equity volatility 34.0 % 36.0 % Weighted average risk-free interest rate 1.96 % 2.54 % | Note 11 – Performance Share Units The Company has adopted the Plan, which provides for future grants of options, unit appreciation rights, restricted units, phantom units, unit awards, performance awards and other unit-based awards. The Company has reserved 105 million Units for delivery with respect to these awards. During December 2017, Roan made grants of approximately16.4 million PSUs pursuant to the terms of the Plan and individual Performance Share Unit Agreements. The percent of awarded PSUs in which each recipient vests, if any, will range from 0% to 200% based on the Company’s value on December 31, 2020 (“Performance Period End Date”). The Company’s value on the Performance Period End Date will be determined by (a) if prior to an initial public offering, the value of the Company determined in good faith by a designated committee of the Board of Managers of the Company, or (b) if on or following an initial public offering, the market value of the public entity determined with reference to the volume-weighted average price of the publicly traded securities of the public entity for the 30 consecutive trading days immediately preceding the Performance Period End Date, as reported on the stock exchange composite tape. Each vested PSU is exchangeable for one Unit of the Company. The following table summarizes information related to the Company’s PSU awards: Number of Units Weighted Average Fair Value Total Fair Value ($ in Units outstanding at December 31, 2016 — $ — $ — Units granted 16,350,000 $ 1.41 $ 23,054 Units vested — $ — $ — Units outstanding at December 31, 2017 16,350,000 $ 1.41 $ 23,054 Compensation expense associated with the PSU awards for the year ended December 31, 2017 was $0.4 million and is included in general and administrative expenses on the accompany statement of operations. Unrecognized expense as of December 31, 2017 for all outstanding PSU awards was $22.7 million and will be recognized over a weighted-average remaining period of 3.0 years. The grant date fair value of the PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned and estimated Company value on the Performance Period End Date. The grant date fair value of the PSUs is expensed on a straight-line basis from the grant date to the Performance Period End Date. The Monte Carlo simulation process is a generally accepted statistical technique used, in this instance, to simulate the future Unit price and overall market value of the Company. The simulation uses a risk-neutral framework along with the risk-free rate of return, and an estimate for equity volatility of the Company based on peer companies. A Unit price path is simulated for the Company and is used to determine the payout percentages and the Unit price of the Company’s Units as of the Performance Period End Date. The ending Unit price is multiplied by the payout percentage to determine the projected payout, which is then discounted using the risk-free rate of return to the grant date to determine the grant date fair value of the PSUs for that iteration. When enough iterations are generated within a Monte Carlo simulation model, the resulting distribution gives a reasonable estimate of the range of future expected Unit prices and grant date fair value of the PSUs. The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSU awards granted in December 2017: Company enterprise value $ 3.76 billion Equity volatility 35.00 % Weighted average risk-free interest rate 1.94 % |
Transactions with Affiliates
Transactions with Affiliates | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Related Party Transactions [Abstract] | ||
Transactions with Affiliates | Note 12 –Transactions with Affiliates Management Service Agreements Under the MSAs, Citizen and Linn provided certain services in respect to the oil and natural gas properties they contributed to the Company. Such services included serving as operator of the oil and natural gas properties contributed, land administration, marketing, information technology and accounting services. As a result of Citizen and Linn continuing to serve as operator of the contributed assets and contracting directly with vendors for goods and services for operations, Citizen and Linn collected amounts due from joint interest owners for their share of costs and billed the Company for its share of costs. The services provided under the MSAs ended in April 2018 when the Company took over as operator for the oil and natural gas properties contributed by Citizen and Linn. For the nine months ended September 30, 2018, the Company incurred approximately $ 10.0 million in charges related to the services provided under the MSAs, which are recorded in general and administrative expenses in the accompanying condensed consolidated statements of operations. Through April 2018, Citizen and Linn billed the Company for its share of operating costs in accordance with the MSAs. At December 31, 2017, the Company had $55.5 million and $46.5 million due to Linn and Citizen, respectively, included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets. At December 31, 2017, the Company had $19.0 million due to Linn and Citizen for revenue suspense associated with the oil and natural gas properties contributed to the Company included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets. Acquisition of Acreage As provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage within an area of mutual interest on behalf of the Company. As of December 31, 2017, the additional acreage acquired totaled $63.0 million and the Company reflected the amount due to Citizen and Linn in accounts payable and accrued liabilities – affiliates. See Note 4 – Acquisitions Note 10 – Equity Natural Gas Dedication Agreement The Company has a gas dedication agreement with Blue Mountain Midstream LLC (“Blue Mountain”), a subsidiary of Riviera Resources, Inc. (“Riviera”), which has directors and shareholders in common with the Company. Amounts due from Blue Mountain at September 30, 2018 and December 31, 2017 are reflected as accounts receivable – affiliates in the accompanying condensed consolidated balance sheets and represent accrued revenue for the Company’s portion of the production sold to Blue Mountain. Sales to Blue Mountain are reflected as natural gas sales – affiliates and NGL sales – affiliates in the accompanying condensed consolidated statements of operations. See further discussion of this gas dedication agreement in Note 14 – Commitments and Contingencies Corporate Office Lease During 2018, the Company entered into a lease for office space in Oklahoma City, Oklahoma that is owned by a subsidiary of Riviera under a lease with an initial term of 5 years. The Company paid $0.4 million during the nine months ended September 30, 2018 under this lease. Total remaining payments under the lease are $8.3 million. Tax Matters Agreement In conjunction with the Reorganization, the Company entered into a tax matters agreement (“TMA”) with Riviera. See Note 13 – Income Taxes | Note 12 –Transactions with Affiliates Management Service Agreements For the year ended December 31, 2017, the Company incurred approximately $10.0 million in charges related to the services provided under the MSAs which are recorded in general and administrative expenses in the accompanying statements of operations. Citizen and Linn bill the Company for its share of operating costs in accordance with the MSAs. At December 31, 2017, the Company had $46.5 million and $55.5 million due to Citizen and Linn, respectively. These amounts are included in accounts payable – affiliates and accrued capital expenditures—affiliates in the accompany balance sheets. Acquisition of Acreage As provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage within an area of mutual interest on behalf of the Company. As of December 31, 2017, the additional acreage acquired totaled $63.0 million and the Company has reflected the amount due to Citizen and Linn in accrued capital expenditures – affiliates. See Note 14 – Subsequent Events Natural Gas Dedication Agreement The Company has a gas dedication agreement with Blue Mountain Midstream LLC (“Blue Mountain”), which is a subsidiary of Linn. Amounts due from Blue Mountain at December 31, 2017 of $4.7 million are reflected as Accounts Receivable – Oil, natural gas, and natural gas liquids sales – Affiliates and sales to Blue Mountain of $8.0 million for the year ended December 31, 2017 are reflected as Natural gas and natural gas liquids sales – Affiliates. See further discussion of this gas dedication agreement in Note 13 – Commitments and Contingencies Consulting Services Atlas, LLC (“Atlas”) provides the Company supervisory services throughout drilling and completion operations. Atlas is wholly owned jointly by a director and an employee of Citizen. For the years ended December 31, 2017, 2016, and 2015, the Company incurred $2.3 million, $2.0 million, and $0.3 million respectively, in charges related to services provided which are recorded in the balance sheet within oil and natural gas properties, successful efforts on the accompanying balance sheet. As of December 31, 2017 and 2016, the Company had no amounts payable to Atlas. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | ||
Commitments and Contingencies | Note 14 – Commitments and Contingencies Litigation In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. At September 30, 2018, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability. Natural Gas Dedication Agreements The Company has dedicated its natural gas production from the oil and natural gas properties contributed by Citizen under an agreement with a third party. Under this dedication agreement, the Company is required to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement. For the oil and natural gas properties contributed by Linn, the Company assumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement. Volume Commitment Under an agreement with a third party, the Company has a requirement to deliver a minimum volume of natural gas from a specified area, as defined in the agreement. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees on any undelivered volumes as of November 2021. If the Company was unable to deliver any additional natural gas volumes, it would owe deficiency fees of $8.6 million as of September 30, 2018. Based on natural gas volumes delivered as of September 30, 2018, current production from producing wells and expected production from wells planned to be drilled in the specified area, the Company expects to meet the required minimum volume commitment. | Note 13 – Commitments and Contingencies Litigation In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. At December 31, 2017, 2016 and 2015, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability. Rig Commitments The Company has drilling rig contracts with terms extending through 2018. These drilling commitments at December 31, 2017 were approximately $5.1 million. As discussed in Note 12 – Transactions with Affiliates well-by-well Natural Gas Dedication Agreements The Company has dedicated its natural gas production from the oil and natural gas properties contributed by Citizen under an agreement with a third party. Under this dedication agreement, the Company is required to deliver its natural gas production from a geographic area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement. For the oil and natural gas properties contributed by Linn, the Company assumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to deliver all of its natural gas production from its oil and natural gas properties in the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement. Volume Commitment The Company has a minimum volume delivery commitment of natural gas of 18,250,000 mcf by November 2021. Under this commitment, the Company is required to delivery natural gas from a specified area, as defined in the agreement. As of December 31, 2017, the Company has delivered 3,037,500 mcf under this commitment. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees of $0.625 per mcf. |
Subsequent Events
Subsequent Events | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Subsequent Events [Abstract] | ||
Subsequent Events | Note 15 – Subsequent Events Subsequent to September 30, 2018, the Company entered into fixed price swaps for 2,500 Bbls per day of NGL production at a weighted average price of $34.03 for the period of October 2018 to December 2019 and for 20,000 Mcf per day of natural gas production at a weighted average price of $2.93 for the period of January 2019 to December 2019. | Note 14 – Subsequent Events Management has evaluated subsequent events through June 29, 2018, which is the date the financial statements were available to be issued. No events or transactions other than those already disclosed have occurred subsequent to the balance sheet date that might require recognition or disclosure in the financial statements. As discussed in Note 12 – Transactions with Affiliates The MSAs with Citizen and Linn ended in April 2018 with the Company taking over operations of the oil and natural gas properties as of May 2018. In May 2018, the Company amended its 2017 Credit Facility, which provided additional time for the Company to remit its annual financial statements. |
Supplemental Information on Oil
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Unaudited) | Note 15 – Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Unaudited) The following disclosures provide supplemental unaudited information regarding the Company’s oil, natural gas and NGL activities, which were entirely within the United States. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities are summarized as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Acquisition costs of properties: Proved properties $ 214,647 $ 1,079 $ 2,291 Unproved properties 1,018,978 93,705 42,266 Exploratory 8,538 — — Development costs 390,991 152,284 24,446 Costs incurred $ 1,633,154 $ 247,068 $ 69,003 Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities Capitalized costs related to the Company’s oil, natural gas and NGL producing activities are summarized as follows: December 31, 2017 2016 (in thousands) Oil and natural gas properties Proved $ 750,492 $ 184,376 Unproved 1,126,459 141,004 Less: accumulated depreciation, depletion, amortization and impairment (78,307 ) (27,002 ) Oil and natural gas properties, net $ 1,798,644 $ 298,378 Oil, Natural Gas and NGL Reserves Proved oil, natural gas and NGL estimates at December 31, 2017 were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Proved oil, natural gas and NGL estimates at December 31, 2016 and 2015 were prepared by Ralph E. Davis, independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month Oil (mbbl) Natural Gas (mmcf) NGLs (mbbl) Total (Mboe) Proved reserves at December 31, 2014 81 1,798 38 419 Purchase of reserves 45 608 14 160 Extensions and discoveries 279 6,504 632 1,995 Revisions of previous estimates 79 41 42 128 Production (97 ) (434 ) (48 ) (217 ) Proved reserves at December 31, 2015 387 8,517 678 2,484 Purchase of reserves 22 333 33 111 Extensions and discoveries 2,632 33,218 2,956 11,124 Revisions of previous estimates 598 4,145 398 1,687 Production (740 ) (6,382 ) (546 ) (2,350 ) Proved reserves at December 31, 2016 2,900 39,831 3,519 13,057 Purchase of reserves 9,843 163,638 16,870 53,986 Extensions and discoveries 30,554 486,510 61,599 173,238 Revisions of previous estimates (3,583 ) 20,844 (260 ) (369 ) Production (2,294 ) (24,953 ) (2,150 ) (8,603 ) Proved reserves at December 31, 2017 37,420 685,869 79,578 231,309 At December 31, 2015, the Company had approximately 2,484 mboe of proved reserves. During 2015, Citizen’s drilling of 38 gross wells and drilling activity of other operators in the area resulted in extensions and discoveries of 1,995 mboe. Extensions and discoveries were the primary driver in the increase in proved reserves from December 31, 2014 to December 31, 2015. At December 31, 2016, the Company had approximately 13,057 mboe of proved reserves. During 2016, Citizen acquired approximately 62,500 net acres of unproved leasehold and drilled 55 gross wells. Citizen’s drilling activity and the drilling activity of other operators in the area resulted in extensions and discoveries of 11,124 mboe. Extensions and discoveries were the primary driver in the increase in proved reserves from December 31, 2015 to December 31, 2016. At December 31, 2017, the Company had approximately 231,309 mboe of proved reserves. During 2017, the Company acquired unproved leasehold acreage and drilled 93 gross wells. The Company’s drilling activity and the drilling activity of other operators in the area resulted in extensions and discoveries of 173,238 mboe. Purchase of reserves of 53,986 mboe reflects the reserves acquired in the Linn Acquisition. Revisions of previous estimates reflects upward revisions associated with increases in pricing of 3,277 mboe, offset by downward revisions associated with performance of 3,646 mboe. The purchase of reserves and extensions and discoveries were the primary drivers in the increase in reserves from December 31, 2016 to December 31, 2017. The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped (“PUD”) oil, natural gas and NGL reserves of the Company as of December 31, 2017, 2016, and 2015: December 31, 2017 2016 2015 Proved Developed Reserves Oil (mbbl) 12,352 2,900 387 Natural gas (mmcf) 259,193 39,831 8,517 NGL (mbbl) 24,034 3,519 678 Total (mboe) 79,585 13,057 2,484 Proved Undeveloped Reserves Oil (mbbl) 25,068 — — Natural gas (mmcf) 426,676 — — NGL (mbbl) 55,544 — — Total (mboe) 151,724 — — Total Proved Reserves Oil (mbbl) 37,420 2,900 387 Natural gas (mmcf) 685,869 39,831 8,517 NGL (mbbl) 79,578 3,519 678 Total (mboe) 231,309 13,057 2,484 In accordance with SEC regulations, the Company uses the 12-month 12-month All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond the Company’s control such as reservoir performance, prices, economic conditions, and government restrictions. In addition, results of drilling, testing, and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of oil, natural gas, and NGLs that are ultimately recovered. Estimating quantities of proved oil, natural gas and NGL reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as oil, natural gas and NGL prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties the Company owns declines as reserves are depleted. Except to the extent the Company conducts successful exploration and development activities or acquires additional properties containing proved reserves, or both, the Company’s proved reserves will decline as reserves are produced. Results of Operations for Oil, Natural Gas and NGL Producing Activities The following table sets forth the Company’s results of operations for oil, natural gas and NGL producing activities for the years ended December 31, 2017, 2016 and 2015: For the Years Ended December 31, 2017 2016 2015 (in thousands) Oil, natural gas, and NGL sales $ 166,385 $ 54,965 $ 5,685 Production expenses 16,872 5,090 549 Gathering, transportation and processing 18,602 5,920 273 Production taxes 3,685 1,087 190 Exploration expenses 28,154 — — Depreciation, depletion and amortization 36,979 24,909 2,060 Accretion of asset retirement obligations 364 87 31 Impairment 4,475 5,258 121 Results of operations $ 57,254 $ 12,614 $ 2,461 Standardized Measure of Discounted Future Net Cash Flows The following summary sets forth the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and NGL reserves. For the Years Ended December 31, 2017 2016 2015 (in thousands) Future cash inflows $ 5,270,465 $ 271,428 $ 47,310 Future production costs (1,664,724 ) (102,817 ) (21,289 ) Future development costs (745,769 ) — — Future income tax expense (1) — — — Future net cash flows 2,859,972 168,611 26,021 Discount to present value at 10% annual rate (1,664,303 ) (50,339 ) (7,111 ) Standardized measure of discounted future net cash flows $ 1,195,669 $ 118,272 $ 18,910 (1) The Company is a limited liability company treated as a disregarded entity for income tax purposes. Changes in Standardized Measure of Discounted Future Net Cash Flows The following table sets forth the changes in the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and NGL reserves: For the Years Ended December 31, 2017 2016 2015 (in thousands) Standardized measure, beginning of year $ 118,272 $ 18,910 $ 6,500 Sales of oil, natural gas and NGLs produced, net of production costs (124,526 ) (42,868 ) (4,673 ) Net changes in prices and production costs 36,233 18,256 (2,614 ) Extensions and discoveries, net of production and development costs 877,846 104,581 15,235 Changes in estimated future development costs (17,970 ) — — Development costs incurred during the period that reduce future costs 148,505 — — Revisions of previous quantity estimates (5,676 ) 15,573 985 Purchases of reserves 279,026 462 1,428 Accretion of discount 11,827 1,891 650 Changes in production rates and other (127,868 ) 1,467 1,399 Standardized measure, end of year $ 1,195,669 $ 118,272 $ 18,910 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 2 – Summary of Significant Accounting Policies For a description of the Company’s significant accounting policies, refer to Note 2 to the Company’s 2017 audited financial statements. The accompanying condensed consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Principles of Consolidation The condensed consolidated financial statements of the Company include the accounts of Roan Inc. and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Interim Financial Statements The accompanying condensed consolidated financial statements as of December 31, 2017 were derived from the annual financial statements. The unaudited interim condensed consolidated financial statements for the nine months ended September 30, 2018 and 2017 were prepared by the Company in accordance with the accounting policies stated in the audited financial statements. In the opinion of management, the Company’s unaudited condensed consolidated financial statements reflect all known adjustments necessary to fairly state the financial position of the Company and its results of operations and cash flows for such periods. All such adjustments are of a normal, recurring nature. Certain information and disclosures normally included in financial statements prepared in conformity with GAAP have been consolidated or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s annual financial statements and notes thereto. Income Taxes The Company is a corporation and therefore a taxable entity. As a result of the Reorganization, the Company recorded a deferred tax liability based on the change in tax status. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. See Note 13 – Income Taxes Use of Estimates The preparation of financial statements and related footnotes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management’s estimates and assumptions is the estimate of proved oil, natural gas and NGL reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from these estimates. Recent Accounting Standards Issued In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) 2014-09, 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) 2016-08”), 2016-08 Note 3 – Revenue from Contracts with Customers In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) 2016-02”). right-of-use 2016-02 2018-11 Leases (Topic 842): Targeted Improvements 2016-02 |
Revenue from Contracts with Cus
Revenue from Contracts with Customers | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contracts with Customers | Note 3 – Revenue from Contracts with Customers The Company adopted ASC 606 on January 1, 2018 using a modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The adoption does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company’s presentation of revenues and expenses under the gross-versus-net 2016-08. The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standard, ASC Topic 605, Revenue Recognition Nine Months Ended September 30, 2018 Under ASC Under ASC Increase/ (in thousands) Revenues Oil sales $ 197,356 $ 197,431 $ (75 ) Natural gas sales $ 48,956 $ 60,919 $ (11,963 ) Natural gas liquid sales $ 65,377 $ 83,735 $ (18,358 ) Operating expenses Gathering, transportation and processing $ — $ 30,396 $ (30,396 ) Net loss $ (288,916 ) $ (288,916 ) $ — Oil Sales Most of the Company’s oil contracts transfer physical custody and title at or near the wellhead, which is commonly when control of the oil has been transferred to the purchaser. The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price. Any differentials incurred after the transfer of control of the oil are net against oil sales as they represent part of the transaction price of the contract. For its oil contracts, the Company generally records its sales based on the net amount received. Natural Gas and NGL Sales Most of the Company’s natural gas is sold at the wellhead or inlet to the processor’s facility, which is commonly when control of the natural gas has been transferred to the purchaser. The natural gas is sold under percentage of proceeds processing contracts. Under these contracts, the purchaser gathers the natural gas where it is produced and transports it via pipeline to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue gas are then sold by the purchaser. Under the natural gas percentage of proceeds contracts, the Company receives a percentage of the value for the extracted NGLs and the residue gas. For its natural gas processing contracts, the Company generally records its natural gas and NGL sales net of gathering, processing and transportation expenses based on a principal versus agent assessment for individual contracts. Performance Obligations The Company satisfies the performance obligations under its oil and natural gas sales contracts through delivery of its production and transfer of control to a customer. Upon delivery of production, the Company has the right to receive consideration from its customers in amounts that correspond with the value of the production transferred. The Company’s oil sales contracts are short-term in nature with a contract term of one year or less. For those contracts, the Company utilized the practical expedient in ASC 606, which provides an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s natural gas and NGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606 which states the Company 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 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. Contract Balances The Company recognizes sales of oil, natural gas, and NGLs at a point in time when it satisfies a performance obligation and at that point the Company has an unconditional right to receive payment. Accordingly, these contracts do not give rise to contract assets or contract liabilities under ASC 606. The Company had accounts receivable related to revenue from contracts with customers of approximately $62.1 million as of September 30, 2018, which represent this unconditional right to receive payment. Prior Period Performance Obligations To record revenues for oil, natural gas and NGLs, the Company estimates the amount of production delivered at the end of each month and the prices expected to be received for those sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer. For the nine months ended September 30, 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 13 – Income Taxes As discussed in Note 1 – Business and Organization A deferred tax liability was recorded as a result of the Reorganization based on the Company being taxable as a corporation under the Internal Revenue Code of 1986, as amended. The initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization was reflected in income tax expense based on the deferred tax liability resulting from the change in tax status. Due to the nontaxable nature of the Reorganization, there were no adjustments to the tax basis or other tax attributes in the measurement of the deferred taxes except to the extent any gain was recognized by the other parties to the Reorganization. The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate. The Company’s effective combined U.S. federal and state income tax rate for the nine months ended September 30, 2018 excluding discrete items was 25.5%. During the third quarter of 2018, the Company recognized income tax expense of $299.7 million, primarily representing the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization. In conjunction with the Reorganization, the Company entered into a TMA with Riviera. The TMA, in part, provides for indemnification of the Company and entitlement of refunds by Riviera of certain taxes related to Linn Energy, Inc. prior to the spinoff of assets from Linn Energy, Inc. to Riviera. As a result of the TMA and an estimated overpayment of federal taxes by Linn Energy, Inc., the Company has recorded a $7.7 million income tax receivable and a payable of $7.7 million to Riviera at September 30, 2018. The receivable is included in accounts receivable – other and the payable is included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets. The Company’s deferred tax liabilities as of September 30, 2018 include the following (in thousands): Deferred income tax assets (liabilities): Oil and natural gas properties $ (322,911 ) Derivative contracts 22,530 Other 719 Deferred tax liabilities, net $ (299,662 ) |
Basis of Presentation and Sig_2
Basis of Presentation and Significant Accounting Policies (Policies) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Accounting Policies [Abstract] | ||
Basis of Presentation | Basis of Presentation The accompanying financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). | |
Use of Estimates | Use of Estimates The preparation of financial statements and related footnotes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management’s estimates and assumptions is the estimate of proved oil, natural gas and NGL reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from these estimates. | Use of Estimates The preparation of financial statements and related footnotes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management’s estimates and assumptions is the estimate of proved oil, natural gas and natural gas liquid (“NGLs”) reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from these estimates. |
Revenue Recognition | Revenue Recognition Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. The Company recognizes revenues from the sale of oil, natural gas and NGLs using the sales method, whereby revenue is recorded based on the Company’s share of volumes sold. If the Company’s aggregate sales volumes for a well are greater (or less) than its proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make up the overproduced (or under produced) imbalance. There were no material imbalances at December 31, 2017 or 2016. | |
Business Combinations | Business Combinations The Company accounts for all business combinations using the acquisition method, which involves the use of significant judgment. In a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The Company estimates the fair values of assets acquired and liabilities assumed in a business combination using various assumptions (all of which are Level 3 inputs within the fair value hierarchy). The most significant assumptions typically relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of the proved and unproved oil and natural gas properties, the Company develops estimates of oil, natural gas and NGL reserves. Estimates of reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Additionally, a risk factor is applied to reserves by reserve type based on industry standards. The Company estimates future prices to apply to the estimated net quantities of reserves based on the applicable ownership percentage acquired and estimates future operating and development costs to arrive at estimates of future net cash flows. The future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. | |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The Company follows the successful efforts method to account for its exploration and production activities. Under this method, costs incurred to purchase, lease, or otherwise acquire a property, whether unproved or proved, are capitalized when incurred. The Company initially capitalizes exploratory well costs pending a determination whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed as incurred. Additionally, costs to operate and maintain wells and field equipment are expensed as incurred. Depletion is computed on a units-of-production unit-of-production Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. The net carrying values of retired, sold or abandoned proved properties that constitute less than a complete unit of depletable property are charged, net of proceeds, to accumulate depreciation, depletion and amortization unless doing so significantly affect the unit-of-production Proceeds from sales of all or a partial interest in individual unproved properties assessed for impairment on a group basis are accounted for as a recovery of costs. No gain or loss is recognized unless the sales proceeds exceed the original cost of the entire interest in the property, in which a gain will be recognized for the excess. | |
Impairment of Oil and Natural Gas Properties | Impairment of Oil and Natural Gas Properties Proved oil and natural gas properties are evaluated for impairment annually or when facts or circumstances indicate that the carrying value of those assets may not be recoverable, such as when there are declines in oil and natural gas prices or well performance. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. An impairment loss is indicated if the sum of the estimated undiscounted future cash flows related to an asset group is less than the carrying value of that asset group. If an impairment loss has been incurred, the loss recognized is the excess of the carrying amount over the estimated fair value. The Company calculates the estimated fair value using a discounted future cash flow model. Management’s assumptions associated with the calculation of future cash flows include oil and natural gas prices based on NYMEX futures price strips, as well as other assumptions, including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes, (v) timing of development, and (vi) estimated reserves. A discount rate, consistent with that used by market participants, is applied to the estimated future cash flows in order to estimate fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments. It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) oil and natural gas futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, and (iv) results of future drilling activities. The Company’s unproved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictated that the carrying value of those assets may not be recoverable. Unproved leasehold costs are amortized on a group basis if individually insignificant, and a valuation allowance is established with a monthly amortization charge to exploration expense for the portion of the properties’ total cost that management estimates may never be transferred to proved properties during the lives of the respective leases. The impairment amortization rate considers the Company’s current drilling plans, the remaining terms of the respective leases and the results of exploratory drilling activity, and can be affected by economic factors including oil and natural gas price outlooks, projected capital costs, and available liquidity. Costs of expired or relinquished leases are charged against the valuation allowance. | |
Drilling Advances | Drilling Advances The Company’s drilling advances consist of cash provided to the Company from its joint interest partners for planned drilling activities. Advances are applied against the joint interest partner’s share of expenses incurred. As noted above, the Company entered into MSAs with Citizen and Linn to perform services, including operating the contributed assets. Any drilling advances due to or from other joint interest owners are maintained by Citizen and Linn. See Note 12 – Transactions with Affiliates | |
Asset Retirement Obligation | Asset Retirement Obligation The Company is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company’s asset retirement obligations (“ARO”) relate to the plugging of wells and the related abandonment of oil and natural gas properties. AROs are recognized as liabilities with an increase to the carrying amounts of the related assets when the obligation is incurred. The cost of the asset, including ARO, is depreciated over the useful life of the asset. Fair value of ARO is measured using the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value and the liability is settled or the well is sold, at which time the liability is removed. Accretion expense is included in accretion expense in the accompany statements of operations. | |
Derivative Instruments | Derivative Instruments The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the balance sheet as derivative assets and derivative liabilities, on a net basis by counterparty. The Company has not designated any of the derivative contracts as fair value or cash flow hedges for accounting purposes for any of the periods presented. Accordingly, net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments and are included in loss on derivative contracts in the accompanying statements of operations. The Company’s cash flow is impacted when the settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty and are reflected as operating activities in the Company’s statements of cash flows. The Company’s firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market | |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company maintains its cash balances at credit-worthy financial institutions that are insured by the Federal Deposit Insurance Corporation (“FDIC”). At times, cash balances may be in excess of FDIC limits. The Company has not incurred any losses related to the amounts in excess of FDIC limits. | |
Accounts Receivable | Accounts Receivable Accounts receivable consists mainly of receivables from oil, natural gas and NGL purchasers and joint interest owners on properties the Company operates. Accounts receivable from the sale of oil, natural gas and NGLs are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. The Company routinely reviews outstanding balances, assesses the financial strength of its purchasers and joint interest owners and records a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts, existing economic conditions and other pertinent factors. No bad debt expense was recorded for the years ended December 31, 2017, 2016 or 2015 and the Company had no reserve for bad debts at December 31, 2017 or 2016. | |
Deferred Financing Costs | Deferred Financing Costs Costs incurred in connection with the Company’s debt are capitalized and amortized as interest expense over the scheduled maturity period. Unamortized costs are associated with the Company’s revolving credit facility and are reflected as a component of long-term assets on the accompanying balance sheets. | |
Equity-Based Compensation | Equity-Based Compensation In December 2017, the Company granted certain employees performance share units (“PSUs”) pursuant to the Roan Resources LLC Management Incentive Plan (the “Plan”). PSUs issued under this Plan were recognized as equity awards based on their characteristics. The compensation measurement was based on the grant date fair value of the award. Equity compensation is recognized over the requisite service period. For employees directly involved in exploration and development activities, equity compensation is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses or production expense in the statements of operations. | |
Comprehensive Income | Comprehensive Income The Company has no elements of comprehensive income other than net income. | |
Concentrations of Credit Risk | Concentrations of Credit Risk The Company sells oil, natural gas and NGLs to various types of customers. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. Additionally, limitations on capacity at processing plants could also impact the Company’s ability to sell its oil, natural gas and NGLs. The Company is subject to credit risk resulting from the concentration of its oil, natural gas and NGL receivables with two significant purchasers. The Company does not believe the loss of any single purchaser would materially impact its results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers. For the years ended December 31, 2017, 2016, and 2015, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues: Year Ended 2017 2016 2015 Sunoco Inc. 40 % 55 % 61 % EnLink Oklahoma Gas Processing, LP 39 % 31 % * Cimarex Energy Company * * 14 % * Revenue from customer was less than 10% in this year The Company’s derivative transactions have been carried out in the over-the-counter over-the-counter | |
Fair Value Measurements | basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy: Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 — Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3 — Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. | Fair Value Measurements The Company follows a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2— Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3— Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers between levels during 2017 or 2016. The carrying values of the Company’s receivables, payables and long-term debt are estimated to be substantially the same as their fair values at December 31, 2017 and 2016. As noted above, the Company carries its derivative financial instruments at fair value |
Commitments and Contingencies | Commitments and Contingencies The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. | |
Earnings per Unit | Earnings per Unit The Company uses the treasury stock method to determine the potential dilutive effect of outstanding performance share units. Refer to Note 11 – Performance Share Units | |
Income Taxes | Income Taxes The Company is a corporation and therefore a taxable entity. As a result of the Reorganization, the Company recorded a deferred tax liability based on the change in tax status. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. See Note 13 – Income Taxes | Income Taxes The Company is organized as a Delaware limited liability company. The Company is treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of the Company and any related tax credits, for federal income tax purposes, are deemed to pass to the members and are included in the Company’s tax returns even though such net taxable income or loss and tax credits may not have actually been distributed. Accordingly, no tax provision has been made in the financial statements of the Company since the income tax is an obligation of the members. |
Risks and Uncertainties | Risks and Uncertainties Historically, the markets for oil, natural gas, and NGLs have experienced significant price fluctuations. Price fluctuations can result from variations in weather, regional levels of production, availability of transportation capacity, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities. A portion of the Company’s oil and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, transportation or refining facilities or equipment or field labor issues, or intentionally as a result of market conditions such as oil or natural gas prices that the Company deems uneconomic. If a substantial amount of the Company’s production is interrupted or shut in, the Company’s cash flows and, in turn, it’s financial condition and results of operations could be materially and adversely affected. | |
Recently Issued Accounting Standards | Recent Accounting Standards Issued In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) 2014-09, 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) 2016-08”), 2016-08 Note 3 – Revenue from Contracts with Customers In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) 2016-02”). right-of-use 2016-02 2018-11 Leases (Topic 842): Targeted Improvements 2016-02 | Recently Adopted Accounting Standards In January 2017, the Company adopted Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting 2016-09 In September 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments 2015-16”), 2015-16 Recent Accounting Standards Issued Not Yet Adopted In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers In February 2016, the FASB issued ASU 2016-02, Leases right-of-use |
Principles of Consolidation | Principles of Consolidation The condensed consolidated financial statements of the Company include the accounts of Roan Inc. and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. | |
Interim Financial Statements | Interim Financial Statements The accompanying condensed consolidated financial statements as of December 31, 2017 were derived from the annual financial statements. The unaudited interim condensed consolidated financial statements for the nine months ended September 30, 2018 and 2017 were prepared by the Company in accordance with the accounting policies stated in the audited financial statements. In the opinion of management, the Company’s unaudited condensed consolidated financial statements reflect all known adjustments necessary to fairly state the financial position of the Company and its results of operations and cash flows for such periods. All such adjustments are of a normal, recurring nature. Certain information and disclosures normally included in financial statements prepared in conformity with GAAP have been consolidated or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s annual financial statements and notes thereto. | |
Revenue from Contracts with Customers | Oil Sales Most of the Company’s oil contracts transfer physical custody and title at or near the wellhead, which is commonly when control of the oil has been transferred to the purchaser. The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price. Any differentials incurred after the transfer of control of the oil are net against oil sales as they represent part of the transaction price of the contract. For its oil contracts, the Company generally records its sales based on the net amount received. Natural Gas and NGL Sales Most of the Company’s natural gas is sold at the wellhead or inlet to the processor’s facility, which is commonly when control of the natural gas has been transferred to the purchaser. The natural gas is sold under percentage of proceeds processing contracts. Under these contracts, the purchaser gathers the natural gas where it is produced and transports it via pipeline to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue gas are then sold by the purchaser. Under the natural gas percentage of proceeds contracts, the Company receives a percentage of the value for the extracted NGLs and the residue gas. For its natural gas processing contracts, the Company generally records its natural gas and NGL sales net of gathering, processing and transportation expenses based on a principal versus agent assessment for individual contracts. Performance Obligations The Company satisfies the performance obligations under its oil and natural gas sales contracts through delivery of its production and transfer of control to a customer. Upon delivery of production, the Company has the right to receive consideration from its customers in amounts that correspond with the value of the production transferred. The Company’s oil sales contracts are short-term in nature with a contract term of one year or less. For those contracts, the Company utilized the practical expedient in ASC 606, which provides an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s natural gas and NGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606 which states the Company 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 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. Contract Balances The Company recognizes sales of oil, natural gas, and NGLs at a point in time when it satisfies a performance obligation and at that point the Company has an unconditional right to receive payment. Accordingly, these contracts do not give rise to contract assets or contract liabilities under ASC 606. The Company had accounts receivable related to revenue from contracts with customers of approximately $62.1 million as of September 30, 2018, which represent this unconditional right to receive payment. Prior Period Performance Obligations To record revenues for oil, natural gas and NGLs, the Company estimates the amount of production delivered at the end of each month and the prices expected to be received for those sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer. For the nine months ended September 30, 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material. |
Basis of Presentation and Sig_3
Basis of Presentation and Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Major Customers that Exceeded 10% of Total Oil, Natural Gas and NGL Revenues | For the years ended December 31, 2017, 2016, and 2015, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues: Year Ended 2017 2016 2015 Sunoco Inc. 40 % 55 % 61 % EnLink Oklahoma Gas Processing, LP 39 % 31 % * Cimarex Energy Company * * 14 % * Revenue from customer was less than 10% in this year |
Acquisitions (Tables)
Acquisitions (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Business Combinations [Abstract] | ||
Schedule of Assumptions to Determine Fair value of the Oil and Natural Gas | The following assumptions were used to determine the fair value of the oil and natural gas properties: Discount rate 9.50 % Reserve risk factor (1) 35%-100 % Oil price three years NYMEX WTI forward curve Natural gas price three years NYMEX Henry Hub forward curve NGL price 39% of oil price Price escalation (2) 2.00 % (1) Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%. (2) Prices were escalated at the end of the forward curve | The following assumptions were used to determine the fair value of the oil and natural gas properties: Discount rate 9.50% Reserve risk factor (1) 35%-100% Oil price three years NYMEX WTI forward curve Natural gas price three years NYMEX Henry Hub forward curve NGL price 39% of oil price Price escalation (2) 2.00% (1) Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%. (2) Prices were escalated at the end of the forward curve |
Summary of Purchase Price and Allocation of Fair value of Assets Acquired And Liabilities Assumed | The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands): Consideration given Equity units $ 1,281,743 Allocation of purchase price Inventory $ 205 Proved oil and natural gas properties 214,647 Unproved oil and natural gas properties 1,086,600 Total assets acquired 1,301,452 Asset retirement obligations (7,547 ) Revenue suspense (12,162 ) Total fair value of net assets acquired $ 1,281,743 | The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands): Consideration given Equity units $ 1,281,743 Allocation of purchase price Inventory 205 Proved oil and natural gas properties 214,647 Unproved oil and natural gas properties 1,086,600 Total assets acquired 1,301,452 Asset retirement obligations (7,547 ) Revenue suspense (12,162 ) Total fair value of net assets acquired $ 1,281,743 The acquisition was accounted for using the acquisition method under ASC 805, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of April 14, 2016. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumes (in thousands): Other 2016 Acquisitions Consideration given Total cash consideration $ 8,854 Allocation of purchase price Proved oil and natural gas properties 1,128 Unproved oil and natural gas properties 7,774 Total oil and natural gas properties acquired 8,902 Asset retirement obligations (48 ) Total fair value of net assets acquired $ 8,854 |
Schedule of Supplemental Proforma Results of Operations | The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition. Nine Months Ended (in thousands) Revenue $ 156,593 Net income $ 55,253 | The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition. (Unaudited) Year Ended December 31, 2017 2016 2015 (in thousands) Revenue $ 215,588 $ 90,238 $ 28,139 Net income $ 44,269 $ 26,378 $ 6,299 |
Supplemental Information on O_2
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Unaudited) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities | The Company’s oil and natural gas properties are in the continental United States. The oil and natural gas properties include the following: September 30, December 31, (in thousands) Oil and natural gas properties Proved $ 1,276,950 $ 750,492 Unproved 1,152,942 1,126,459 Less: accumulated depreciation, depletion, amortization and impairment (183,557 ) (78,307 ) Oil and natural gas properties, net $ 2,246,335 $ 1,798,644 | The oil and natural gas properties includes the following: December 31, 2017 2016 (in thousands) Oil and natural gas properties Proved $ 750,492 $ 184,376 Unproved 1,126,459 141,004 Less: accumulated depreciation, depletion, amortization and impairment (78,307 ) (27,002 ) Oil and natural gas properties, net $ 1,798,644 $ 298,378 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities | Costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities are summarized as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Acquisition costs of properties: Proved properties $ 214,647 $ 1,079 $ 2,291 Unproved properties 1,018,978 93,705 42,266 Exploratory 8,538 — — Development costs 390,991 152,284 24,446 Costs incurred $ 1,633,154 $ 247,068 $ 69,003 | |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | The following table sets forth proved reserves during the periods indicated: Oil (mbbl) Natural Gas (mmcf) NGLs (mbbl) Total (Mboe) Proved reserves at December 31, 2014 81 1,798 38 419 Purchase of reserves 45 608 14 160 Extensions and discoveries 279 6,504 632 1,995 Revisions of previous estimates 79 41 42 128 Production (97 ) (434 ) (48 ) (217 ) Proved reserves at December 31, 2015 387 8,517 678 2,484 Purchase of reserves 22 333 33 111 Extensions and discoveries 2,632 33,218 2,956 11,124 Revisions of previous estimates 598 4,145 398 1,687 Production (740 ) (6,382 ) (546 ) (2,350 ) Proved reserves at December 31, 2016 2,900 39,831 3,519 13,057 Purchase of reserves 9,843 163,638 16,870 53,986 Extensions and discoveries 30,554 486,510 61,599 173,238 Revisions of previous estimates (3,583 ) 20,844 (260 ) (369 ) Production (2,294 ) (24,953 ) (2,150 ) (8,603 ) Proved reserves at December 31, 2017 37,420 685,869 79,578 231,309 The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped (“PUD”) oil, natural gas and NGL reserves of the Company as of December 31, 2017, 2016, and 2015: December 31, 2017 2016 2015 Proved Developed Reserves Oil (mbbl) 12,352 2,900 387 Natural gas (mmcf) 259,193 39,831 8,517 NGL (mbbl) 24,034 3,519 678 Total (mboe) 79,585 13,057 2,484 Proved Undeveloped Reserves Oil (mbbl) 25,068 — — Natural gas (mmcf) 426,676 — — NGL (mbbl) 55,544 — — Total (mboe) 151,724 — — Total Proved Reserves Oil (mbbl) 37,420 2,900 387 Natural gas (mmcf) 685,869 39,831 8,517 NGL (mbbl) 79,578 3,519 678 Total (mboe) 231,309 13,057 2,484 | |
Results of Operations for Oil and Gas Producing Activities | The following table sets forth the Company’s results of operations for oil, natural gas and NGL producing activities for the years ended December 31, 2017, 2016 and 2015: For the Years Ended December 31, 2017 2016 2015 (in thousands) Oil, natural gas, and NGL sales $ 166,385 $ 54,965 $ 5,685 Production expenses 16,872 5,090 549 Gathering, transportation and processing 18,602 5,920 273 Production taxes 3,685 1,087 190 Exploration expenses 28,154 — — Depreciation, depletion and amortization 36,979 24,909 2,060 Accretion of asset retirement obligations 364 87 31 Impairment 4,475 5,258 121 Results of operations $ 57,254 $ 12,614 $ 2,461 | |
Summary of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | The following summary sets forth the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and NGL reserves. For the Years Ended December 31, 2017 2016 2015 (in thousands) Future cash inflows $ 5,270,465 $ 271,428 $ 47,310 Future production costs (1,664,724 ) (102,817 ) (21,289 ) Future development costs (745,769 ) — — Future income tax expense (1) — — — Future net cash flows 2,859,972 168,611 26,021 Discount to present value at 10% annual rate (1,664,303 ) (50,339 ) (7,111 ) Standardized measure of discounted future net cash flows $ 1,195,669 $ 118,272 $ 18,910 (1) The Company is a limited liability company treated as a disregarded entity for income tax purposes. | |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows | The following table sets forth the changes in the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and NGL reserves: For the Years Ended December 31, 2017 2016 2015 (in thousands) Standardized measure, beginning of year $ 118,272 $ 18,910 $ 6,500 Sales of oil, natural gas and NGLs produced, net of production costs (124,526 ) (42,868 ) (4,673 ) Net changes in prices and production costs 36,233 18,256 (2,614 ) Extensions and discoveries, net of production and development costs 877,846 104,581 15,235 Changes in estimated future development costs (17,970 ) — — Development costs incurred during the period that reduce future costs 148,505 — — Revisions of previous quantity estimates (5,676 ) 15,573 985 Purchases of reserves 279,026 462 1,428 Accretion of discount 11,827 1,891 650 Changes in production rates and other (127,868 ) 1,467 1,399 Standardized measure, end of year $ 1,195,669 $ 118,272 $ 18,910 | |
Oil, Gas and NGL | ||
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities | Capitalized costs related to the Company’s oil, natural gas and NGL producing activities are summarized as follows: December 31, 2017 2016 (in thousands) Oil and natural gas properties Proved $ 750,492 $ 184,376 Unproved 1,126,459 141,004 Less: accumulated depreciation, depletion, amortization and impairment (78,307 ) (27,002 ) Oil and natural gas properties, net $ 1,798,644 $ 298,378 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Schedule of Reconciliation of Asset Retirement Obligations | The following is a reconciliation of the changes in the Company’s asset retirement obligation (“ARO”) for the nine months ended September 30, 2018 (in thousands): Asset retirement obligation, December 31, 2017 $10,769 Liabilities incurred or acquired 1,815 Revisions in estimated cash flows 318 Liabilities settled (111 ) Accretion expense 620 Asset retirement obligation, September 30, 2018 13,411 Less: current portion of obligations 535 Asset retirement obligation – long term $12,876 | The following is a reconciliation of the changes in the Company’s ARO for the years ended December 31, 2017 and 2016: Year Ended December 31, 2017 2016 (in thousands) Asset retirement obligation, beginning balance $ 2,245 $ 1,161 Liabilities incurred or acquired 8,118 1,054 Revisions in estimated cash flows 42 (16 ) Liabilities settled — (41 ) Accretion expense 364 87 Asset retirement obligation, ending balance 10,769 2,245 Less: current portion of obligations — 3 $ 10,769 $ 2,242 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Debt Disclosure [Abstract] | ||
Summary of Principal Maturities if the Company's Borrowings | Principal maturities of the Company’s borrowings, consistent of amounts outstanding under the 2017 Credit Facility, at December 31, 2017 are as follows (in thousands): 2018 $ — 2019 — 2020 — 2021 — 2022 85,339 $ 85,339 | |
Schedule of Applicable Margin for LIBOR Rate Loans Depending on the Utilization Level | The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement): Utilization Level Utilization LIBOR Applicable Commitment Level I <25% 2.00 % 1.00 % 0.375 % Level II >25% but <50% 2.25 % 1.25 % 0.375 % Level III >50% but <75% 2.50 % 1.50 % 0.500 % Level IV >75% but <90% 2.75 % 1.75 % 0.500 % Level V >90% 3.00 % 2.00 % 0.500 % | The pricing grid below shows the applicable margin for LIBOR rate loans depending on the Utilization Level (as defined in the credit agreement) as of the date of this filing: Utilization Level Utilization LIBOR Margin Applicable Margin Commitment Fee Level I < 25% 2.25% 1.25% 0.500% Level II ³ 2.50% 1.50% 0.500% Level III ³ 2.75% 1.75% 0.500% Level IV ³ 3.00% 2.00% 0.500% Level V ³ 3.25% 2.25% 0.500% |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Schedule of Company's Open Commodity Contracts | The following table reflects the Company’s open commodity contracts at September 30, 2018: 2018 2019 2020 Total Oil fixed price swaps Volume (Bbl) 1,233,180 5,540,670 1,599,500 8,373,350 Weighted-average price $ 57.09 $ 59.86 $ 63.14 $ 60.08 Natural gas fixed price swaps Volume (MMBtu) 8,004,000 29,200,000 12,325,000 49,529,000 Weighted-average price $ 2.94 $ 2.86 $ 2.63 $ 2.81 Natural gas basis swaps Volume (MMBtu) 4,600,000 21,900,000 3,640,000 30,140,000 Weighted-average price $ 0.54 $ 0.58 $ 0.62 $ 0.58 | The following table represents the Company’s open commodity contracts at December 31, 2017: Total Oil fixed price swaps 2018 Volume (bbl) 2,374,000 Weighted-average price per bbl $ 54.47 2019 Volume (bbl) 1,140,250 Weighted-average price per bbl $ 54.09 Natural gas fixed price swaps 2018 Volume (mmbtu) 16,440,000 Weighted-average price per mmbtu $ 3.00 2019 Volume (mmbtu) 10,950,000 Weighted-average price per mmbtu $ 2.97 Natural gas basis swaps 2018 Volume (mmbtu) 16,440,000 Weighted-average price per mmbtu $ 0.55 2019 Volume (mmbtu) 10,950,000 Weighted-average price per mmbtu $ 0.55 |
Schedule of Net Gains and Loss on Derivative Contracts | The following table presents the Company’s (loss) gain on derivative contracts and net cash (paid) received upon settlement of its derivative contracts for the nine months ended September 30, 2018 and 2017: Nine Months Ended 2018 2017 (in thousands) (Loss) gain on derivative contracts $ (100,920 ) $ 2,385 Net cash (paid) received upon settlement of derivative contracts $ (27,462 ) $ 2,385 Net cash received upon settlement of derivative contracts prior to contractual maturity $ 377 $ 2,255 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | ||
Summary of Classifications of the Company's Derivative Assets and Liabilities | The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of September 30, 2018 and December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands): September 30, 2018 Level 1 Level 2 Level 3 Gross Fair Netting Carrying Assets Current commodity derivatives $ — $ 4,282 $ — $ 4,282 $ (4,079 ) $ 203 Noncurrent commodity derivatives — 908 — 908 (908 ) — Total assets $ — $ 5,190 $ — $ 5,190 $ (4,987 ) $ 203 Liabilities Current commodity derivatives $ — $ (68,340 ) $ — $ (68,340 ) $ 4,079 $ (64,261 ) Noncurrent commodity derivatives — (19,809 ) — (19,809 ) 908 (18,901 ) Total liabilities $ — $ (88,149 ) $ — $ (88,149 ) $ 4,987 $ (83,162 ) December 31, 2017 Level 1 Level 2 Level 3 Gross Fair Netting Carrying Assets Current commodity derivatives $ — $ 2,856 $ — $ 2,856 $ (2,704 ) $ 152 Noncurrent commodity derivatives — 2,182 — 2,182 (1,186 ) 996 Total assets $ — $ 5,038 $ — $ 5,038 $ (3,890 ) $ 1,148 Liabilities Current commodity derivatives $ — $ (11,983 ) $ — $ (11,983 ) $ 2,704 $ (9,279 ) Noncurrent commodity derivatives — (2,557 ) — (2,557 ) 1,186 (1,371 ) Total liabilities $ — $ (14,540 ) $ — $ (14,540 ) $ 3,890 $ (10,650 ) | The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands): December 31, 2017 Level 1 Level 2 Level 3 Gross Fair Netting Carrying Assets Current commodity derivatives $ — $ 2,856 $ — $ 2,856 $ (2,704 ) $ 152 Long-term commodity derivatives — 2,182 — 2,182 (1,186 ) 996 Total assets $ — $ 5,038 $ — $ 5,038 $ (3,890 ) $ 1,148 Liabilities Current commodity derivatives $ — $ (11,983 ) $ — $ (11,983 ) $ 2,704 $ (9,279 ) Long-term commodity derivatives — (2,557 ) — (2,557 ) 1,186 (1,371 ) Total liabilities $ — $ (14,540 ) $ — $ (14,540 ) $ 3,890 $ (10,650 ) |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Summary of Unit activity | The Company’s unit activity for the years ended December 31, 2017, 2016, and 2015 is as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Issued and outstanding units, beginning of the year (1) 1,500,000 813,021 165,771 Issuance of units to Citizen Members (1) — 686,979 647,250 Units issued in exchange for contribution of oil and natural gas properties 1,500,000 — — Issued and outstanding units, end of the year 3,000,000 1,500,000 813,021 (1) Reflects exchange of Citizen units for Roan units on retroactive basis |
Equity Compensation (Tables)
Equity Compensation (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||
Summary of Information Related to PSUs | The following table summarizes information related to the total number of PSUs awarded as of September 30, 2018: Number of Weighted Total Fair PSUs outstanding at December 31, 2017 16,350,000 $ 1.41 $ 23,054 PSUs granted 6,825,000 $ 1.88 $ 12,810 PSUs vested — $ — $ — Conversion (1) (22,016,250 ) $ — $ — PSUs outstanding at September 30, 2018 1,158,750 $ 30.95 $ 35,864 (1) PSUs were converted on a basis of 0.05 to 1.0. There was no change to the deemed fair value of the awards based on assessment of modification. | The following table summarizes information related to the Company’s PSU awards: Number of Units Weighted Average Fair Value Total Fair Value ($ in Units outstanding at December 31, 2016 — $ — $ — Units granted 16,350,000 $ 1.41 $ 23,054 Units vested — $ — $ — Units outstanding at December 31, 2017 16,350,000 $ 1.41 $ 23,054 |
Schedule of Assumptions Used to Determine Grand Date Fair Value and Associated Compensation Expense for PSU Awards Granted | The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSUs granted during the following periods: Six Months Ended Three Months Ended Company enterprise value (in billions) $ 4.56 $ 4.19 Equity volatility 34.0 % 36.0 % Weighted average risk-free interest rate 1.96 % 2.54 % | The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSU awards granted in December 2017: Company enterprise value $ 3.76 billion Equity volatility 35.00 % Weighted average risk-free interest rate 1.94 % |
Revenue from Contracts with C_2
Revenue from Contracts with Customers (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles | The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standard, ASC Topic 605, Revenue Recognition Nine Months Ended September 30, 2018 Under ASC Under ASC Increase/ (in thousands) Revenues Oil sales $ 197,356 $ 197,431 $ (75 ) Natural gas sales $ 48,956 $ 60,919 $ (11,963 ) Natural gas liquid sales $ 65,377 $ 83,735 $ (18,358 ) Operating expenses Gathering, transportation and processing $ — $ 30,396 $ (30,396 ) Net loss $ (288,916 ) $ (288,916 ) $ — |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Deferred Tax Liabilities | The Company’s deferred tax liabilities as of September 30, 2018 include the following (in thousands): Deferred income tax assets (liabilities): Oil and natural gas properties $ (322,911 ) Derivative contracts 22,530 Other 719 Deferred tax liabilities, net $ (299,662 ) |
Business and Organization - Add
Business and Organization - Additional information (Detail) | Aug. 31, 2017 |
Citizen | |
Schedule of Equity Method Investments [Line Items] | |
Ownership percentage | 50.00% |
Linn | |
Schedule of Equity Method Investments [Line Items] | |
Ownership percentage | 50.00% |
Basis of Presentation and Sig_4
Basis of Presentation and Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | ||||||
Bad debt expense | $ 0 | $ 0 | $ 0 | |||
Reserve for bad debt | 0 | $ 0 | ||||
Provision for income tax | $ 299,662 | $ 299,662 | $ 0 | $ 0 |
Basis of Presentation and Sig_5
Basis of Presentation and Significant Accounting Policies - Major Customers that Exceeded 10% of Total Oil, Natural Gas and NGL Revenues (Detail) - Customer Concentration Risk - Sales Revenue, Net | 12 Months Ended | |||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||||
Sunoco Inc. | ||||||
Concentration risk percentage | 40.00% | 55.00% | 61.00% | |||
EnLink Oklahoma Gas Processing, LP | ||||||
Concentration risk percentage | 39.00% | 31.00% | [1] | |||
Cimarex Energy Company | ||||||
Concentration risk percentage | [1] | [1] | 14.00% | |||
[1] | Revenue from customer was less than 10% in this year |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Additional Information (Detail) $ in Thousands | Apr. 14, 2016USD ($)a | Mar. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($)a | Dec. 31, 2015USD ($) | Aug. 31, 2017 |
Business Acquisition [Line Items] | ||||||||
Revenues | $ 210,769 | $ 101,020 | $ 159,588 | $ 54,965 | $ 5,685 | |||
Total operating income | $ 15,724 | $ 29,278 | $ 19,905 | $ 7,033 | $ 387 | |||
Area acquired in leasehold property | a | 5,791 | 23,400 | 62,461 | |||||
Cash consideration for interest acquired in leasehold property | $ 8,900 | $ 49,700 | $ 137,600 | |||||
Effective date for acquisition | Feb. 1, 2016 | |||||||
Accounts Payable and Accrued Liabilities | ||||||||
Business Acquisition [Line Items] | ||||||||
Cost incurred for acquisition of acreage | $ 63,000 | |||||||
Linn Energy Holdings | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage | 50.00% | |||||||
Equity units issued in acquisition | $ 1,300,000 | |||||||
Roan LLC | Linn Energy Holdings | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage | 50.00% | |||||||
Cash consideration for interest acquired in leasehold property | $ 22,900 | |||||||
Linn Acquisition | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage | 50.00% | |||||||
Equity units issued in acquisition | $ 1,300,000 | |||||||
Revenues | 34,100 | |||||||
Total operating income | $ 26,600 |
Acquisitions and Divestitures_2
Acquisitions and Divestitures - Summary of Purchase Price and Allocation of Fair value of Assets Acquired And Liabilities Assumed (Detail) - USD ($) $ in Thousands | Aug. 31, 2017 | Apr. 14, 2016 | Dec. 31, 2017 | Dec. 31, 2016 |
Consideration given | ||||
Total cash consideration | $ 8,900 | $ 49,700 | $ 137,600 | |
Linn Acquisition | ||||
Consideration given | ||||
Equity units | $ 1,281,743 | |||
Allocation of purchase price | ||||
Inventory | 205 | |||
Total assets acquired | 1,301,452 | |||
Asset retirement obligations | (7,547) | |||
Revenue suspense | (12,162) | |||
Total fair value of net assets acquired | 1,281,743 | |||
Linn Acquisition | Proved oil and natural gas properties | ||||
Allocation of purchase price | ||||
Properties | 214,647 | |||
Linn Acquisition | Unproved oil and natural gas properties | ||||
Allocation of purchase price | ||||
Properties | $ 1,086,600 | |||
Other 2016 acquisitions | ||||
Consideration given | ||||
Total cash consideration | 8,854 | |||
Allocation of purchase price | ||||
Total assets acquired | 8,902 | |||
Asset retirement obligations | (48) | |||
Total fair value of net assets acquired | 8,854 | |||
Other 2016 acquisitions | Proved oil and natural gas properties | ||||
Allocation of purchase price | ||||
Properties | 1,128 | |||
Other 2016 acquisitions | Unproved oil and natural gas properties | ||||
Allocation of purchase price | ||||
Properties | $ 7,774 |
Acquisitions and Divestitures_3
Acquisitions and Divestitures - Schedule of Supplemental Proforma Results of Operations (Detail) - Linn Acquisition - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Business Acquisition, Pro Forma Information [Line Items] | ||||
Revenue | $ 156,593 | $ 215,588 | $ 90,238 | $ 28,139 |
Net income | $ 55,253 | $ 44,269 | $ 26,378 | $ 6,299 |
Oil and Natural Gas Properties
Oil and Natural Gas Properties - Schedule of Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Oil and Gas Property [Abstract] | |||
Proved | $ 1,276,950 | $ 750,492 | $ 184,376 |
Unproved | 1,152,942 | 1,126,459 | 141,004 |
Less: accumulated depreciation, depletion, amortization and impairment | (183,557) | (78,307) | (27,002) |
Oil and natural gas properties, net | $ 2,246,335 | $ 1,798,644 | $ 298,378 |
Oil and Natural Gas Propertie_2
Oil and Natural Gas Properties - Additional Information (Detail) - USD ($) | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||
Exploratory well costs | $ 0 | $ 0 | |||
Exploratory dry hole costs | 1,300,000 | 0 | $ 0 | ||
Abandonment and impairment expense | $ 4,500,000 | 4,500,000 | 5,300,000 | 0 | |
Impaired expense | $ 0 | $ 0 | $ 0 | $ 0 | |
Depletion expense on capitalized oil and natural gas properties | 82,400,000 | 22,000,000 | |||
Amortization expense | $ 25,600,000 | $ 0 |
Asset Retirement Obligations -
Asset Retirement Obligations - Schedule of Reconciliation of Asset Retirement Obligations (Detail) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Asset retirement obligation, beginning balance | $ 10,769 | $ 2,245 | $ 1,161 | |
Liabilities incurred or acquired | 1,815 | 8,118 | 1,054 | |
Revisions in estimated cash flows | 318 | 42 | (16) | |
Liabilities settled | (111) | (41) | ||
Accretion expense | 620 | 364 | 87 | $ 31 |
Asset retirement obligation, ending balance | 13,411 | 10,769 | 2,245 | $ 1,161 |
Less: current portion of obligations | 535 | 3 | ||
Asset retirement obligation - long term | $ 12,876 | $ 10,769 | $ 2,242 |
Asset Retirement Obligations _2
Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Changes in Asset Retirement Obligations [Line Items] | |||
Liabilities incurred or acquired | $ 1,815 | $ 8,118 | $ 1,054 |
Linn Acquisition | |||
Reconciliation of Changes in Asset Retirement Obligations [Line Items] | |||
Liabilities incurred or acquired | $ 7,500 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) | Aug. 31, 2017USD ($) | Jul. 31, 2017USD ($) | Apr. 19, 2017USD ($) | Aug. 31, 2017USD ($) | Sep. 30, 2016 | Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($) | Nov. 30, 2017USD ($) | Sep. 30, 2017USD ($) | Sep. 05, 2017USD ($) | Dec. 31, 2016USD ($) | Oct. 20, 2016USD ($) | Sep. 01, 2016USD ($) |
Line of Credit Facility [Line Items] | |||||||||||||
Line of credit facility, covenants terms | The Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company's internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). | The Company is limited from hedging in excess of 85% of its future proved production for the next eight quarters per its most recent reserve report. If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report. | |||||||||||
Citizen 2017 Credit Facility | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Line of credit facility, maximum borrowing capacity | $ 500,000,000 | $ 500,000,000 | |||||||||||
Line of credit facility, expiration period | 2 years | 2 years | |||||||||||
Line of credit facility, current borrowing capacity | $ 82,500,000 | $ 82,500,000 | |||||||||||
Outstanding borrowing, amount repaid | $ 20,300,000 | $ 20,300,000 | |||||||||||
2017 Credit Facility | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Line of credit facility, maximum borrowing capacity | $ 750,000,000 | $ 750,000,000 | |||||||||||
Line of credit facility, outstanding borrowings | $ 394,600,000 | $ 85,300,000 | |||||||||||
Commitment Fee | 0.50% | ||||||||||||
Line of credit facility,Interest rate | 4.03% | ||||||||||||
Line of credit facility, current borrowing capacity | $ 675,000,000 | $ 275,000,000 | $ 200,000,000 | $ 200,000,000 | |||||||||
Line of credit facility, maturity date | Sep. 5, 2022 | Sep. 5, 2022 | |||||||||||
Percentage of projected production hedged | 80.00% | 85.00% | |||||||||||
Debt to EBITDAX Ratio | 4 | 4 | |||||||||||
Current assets to current liabilities | 1 | 1 | |||||||||||
Borrowings outstanding threshold percentage | 50.00% | ||||||||||||
Minimum future production hedge percentage | 50.00% | ||||||||||||
2017 Credit Facility | Level I | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Commitment Fee | 0.375% | ||||||||||||
2017 Credit Facility | Level II | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Commitment Fee | 0.375% | ||||||||||||
2017 Credit Facility | LIBOR Margin | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Reduction of applicable margin rate | 0.25% | ||||||||||||
2017 Credit Facility | Applicable Margin | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Reduction of applicable margin rate | 0.25% | ||||||||||||
2017 Credit Facility | Letter of credit | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Line of credit facility, outstanding borrowings | $ 0 | ||||||||||||
Amended 2017 Credit Facility | Maximum | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Line of credit facility, maximum additional borrowing capacity | $ 500,000,000 | ||||||||||||
2016 Credit Facility | |||||||||||||
Line of Credit Facility [Line Items] | |||||||||||||
Line of credit facility, maximum borrowing capacity | $ 35,000,000 | $ 20,000,000 | |||||||||||
Line of credit facility, outstanding borrowings | $ 20,000,000 | ||||||||||||
Commitment Fee | 0.25% | ||||||||||||
Line of credit facility,Interest rate | 2.37% |
Long-Term Debt - Summary of Pri
Long-Term Debt - Summary of Principal Maturities of Borrowings (Detail) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Disclosure [Abstract] | |||
2,018 | $ 0 | ||
2,019 | 0 | ||
2,020 | 0 | ||
2,021 | 0 | ||
2,022 | 85,339 | ||
Long-term debt, total | $ 394,639 | $ 85,339 | $ 20,000 |
Long-Term Debt - Schedule of Ap
Long-Term Debt - Schedule of Applicable Margin for LIBOR Rate Loans Depending on the Utilization Level (Detail) - 2017 Credit Facility | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Line of Credit Facility [Line Items] | ||
Commitment Fee | 0.50% | |
Level I | ||
Line of Credit Facility [Line Items] | ||
Commitment Fee | 0.375% | 0.50% |
Level II | ||
Line of Credit Facility [Line Items] | ||
Commitment Fee | 0.375% | 0.50% |
Level III | ||
Line of Credit Facility [Line Items] | ||
Commitment Fee | 0.50% | 0.50% |
Level IV | ||
Line of Credit Facility [Line Items] | ||
Commitment Fee | 0.50% | 0.50% |
Level V | ||
Line of Credit Facility [Line Items] | ||
Commitment Fee | 0.50% | 0.50% |
LIBOR Margin | Level I | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 2.00% | 2.25% |
LIBOR Margin | Level II | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 2.25% | 2.50% |
LIBOR Margin | Level III | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 2.50% | 2.75% |
LIBOR Margin | Level IV | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 2.75% | 3.00% |
LIBOR Margin | Level V | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 3.00% | 3.25% |
Applicable Margin | Level I | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 1.00% | 1.25% |
Applicable Margin | Level II | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 1.25% | 1.50% |
Applicable Margin | Level III | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 1.50% | 1.75% |
Applicable Margin | Level IV | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 1.75% | 2.00% |
Applicable Margin | Level V | ||
Line of Credit Facility [Line Items] | ||
Line of credit Margin | 2.00% | 2.25% |
Derivative Instrument - Schedul
Derivative Instrument - Schedule of Company's Open Commodity Contracts (Detail) - Swaps | 9 Months Ended | |
Sep. 30, 2018BTU$ / BTU$ / MBblsbbl | Dec. 31, 2017bblMMBTU$ / bbl$ / MMBTU | |
Crude oil commodity contracts | ||
Derivative Instruments [Line Items] | ||
Volume | bbl | 8,373,350 | |
Weighted-average price per bbl/mmbtu | $ / MBbls | 60.08 | |
Crude oil commodity contracts | 2018 | ||
Derivative Instruments [Line Items] | ||
Volume | bbl | 2,374,000 | |
Volume | bbl | 1,233,180 | |
Weighted-average price per bbl/mmbtu | 57.09 | 54.47 |
Crude oil commodity contracts | 2019 | ||
Derivative Instruments [Line Items] | ||
Volume | bbl | 1,140,250 | |
Volume | bbl | 5,540,670 | |
Weighted-average price per bbl/mmbtu | 59.86 | 54.09 |
Crude oil commodity contracts | 2020 | ||
Derivative Instruments [Line Items] | ||
Volume | bbl | 1,599,500 | |
Weighted-average price per bbl/mmbtu | $ / MBbls | 63.14 | |
Natural Gas Commodity Contracts | ||
Derivative Instruments [Line Items] | ||
Volume | 49,529,000 | |
Weighted-average price per bbl/mmbtu | $ / BTU | 2.81 | |
Natural Gas Commodity Contracts | 2018 | ||
Derivative Instruments [Line Items] | ||
Volume | MMBTU | 16,440,000 | |
Volume | 8,004,000 | |
Weighted-average price per bbl/mmbtu | 2.94 | 3 |
Natural Gas Commodity Contracts | 2019 | ||
Derivative Instruments [Line Items] | ||
Volume | MMBTU | 10,950,000 | |
Volume | 29,200,000 | |
Weighted-average price per bbl/mmbtu | 2.86 | 2.97 |
Natural Gas Commodity Contracts | 2020 | ||
Derivative Instruments [Line Items] | ||
Volume | 12,325,000 | |
Weighted-average price per bbl/mmbtu | $ / BTU | 2.63 | |
Natural Gas Basis Commodity Contracts | ||
Derivative Instruments [Line Items] | ||
Volume | 30,140,000 | |
Weighted-average price per bbl/mmbtu | $ / BTU | 0.58 | |
Natural Gas Basis Commodity Contracts | 2018 | ||
Derivative Instruments [Line Items] | ||
Volume | MMBTU | 16,440,000 | |
Volume | 4,600,000 | |
Weighted-average price per bbl/mmbtu | 0.54 | 0.55 |
Natural Gas Basis Commodity Contracts | 2019 | ||
Derivative Instruments [Line Items] | ||
Volume | MMBTU | 10,950,000 | |
Volume | 21,900,000 | |
Weighted-average price per bbl/mmbtu | 0.58 | 0.55 |
Natural Gas Basis Commodity Contracts | 2020 | ||
Derivative Instruments [Line Items] | ||
Volume | 3,640,000 | |
Weighted-average price per bbl/mmbtu | $ / BTU | 0.62 |
Derivative Instrument - Additio
Derivative Instrument - Additional Information (Detail) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||
Net gain (loss) on settled derivatives | $ 2,700 | ||||
Net gain (loss) on derivatives | $ (100,920) | $ 2,385 | $ (6,797) | $ 0 | $ 0 |
Equity - Additional Information
Equity - Additional Information (Detail) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Mar. 31, 2018shares | Aug. 31, 2017Classshares | Sep. 30, 2017 | Dec. 31, 2017USD ($)Classshares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($)shares | Sep. 30, 2018shares | Feb. 29, 2016Class | Dec. 31, 2014shares | [1] | |||
Capital Unit [Line Items] | ||||||||||||
Units authorized | 10,000,000,000 | |||||||||||
Units issued | 3,000,000,000 | |||||||||||
Units outstanding | 3,000,000,000 | 1,500,000,000 | [1] | 813,021,000 | [1] | 165,771,000 | ||||||
Number of membership interests outstanding | Class | 2 | 1 | 2 | |||||||||
Units issued (shares) | 1,500,000,000 | |||||||||||
Contribution amount | $ | $ 95,557 | $ 169,008 | $ 82,775 | |||||||||
Deemed distribution | $ | $ 85,600 | |||||||||||
Common shares issued (shares) | 152,539,532 | |||||||||||
Class A Unit | ||||||||||||
Capital Unit [Line Items] | ||||||||||||
Internal rate of return threshold of prior to distributions | 9.00% | 9.00% | ||||||||||
Linn Energy Holdings | Roan LLC | ||||||||||||
Capital Unit [Line Items] | ||||||||||||
Ownership percentage | 50.00% | |||||||||||
Linn Energy Holdings | Membership units | Roan LLC | ||||||||||||
Capital Unit [Line Items] | ||||||||||||
Units issued (shares) | 19,200,000 | 1,500,000,000 | ||||||||||
Citizen | Roan LLC | ||||||||||||
Capital Unit [Line Items] | ||||||||||||
Ownership percentage | 50.00% | |||||||||||
Citizen | Membership units | Roan LLC | ||||||||||||
Capital Unit [Line Items] | ||||||||||||
Units issued (shares) | 19,200,000 | 1,500,000,000 | ||||||||||
Citizen | Class A Units | ||||||||||||
Capital Unit [Line Items] | ||||||||||||
Number of unit issued and outstanding | 1,398 | |||||||||||
Members of Roan LLC | Common Class A | ||||||||||||
Capital Unit [Line Items] | ||||||||||||
Common shares issued (shares) | 152,500,000 | |||||||||||
[1] | Reflects exchange of Citizen units for Roan units on retroactive basis |
Equity - Summary of Unit Activi
Equity - Summary of Unit Activity (Detail) - shares shares in Thousands | 12 Months Ended | |||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||||
Equity [Abstract] | ||||||
Issued and outstanding units, beginning balance | [1] | 1,500,000 | 813,021 | 165,771 | ||
Issuance of units to Citizen Members | [1] | 686,979 | 647,250 | |||
Units issued in exchange for contribution of oil and natural gas properties | 1,500,000 | |||||
Issued and outstanding units, end balance | 3,000,000 | 1,500,000 | [1] | 813,021 | [1] | |
[1] | Reflects exchange of Citizen units for Roan units on retroactive basis |
Equity Compensation - Additiona
Equity Compensation - Additional Information (Detail) - USD ($) $ in Thousands | Dec. 31, 2020 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expense | $ 8,060 | $ 0 | $ 379 | |
PSU | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of units reserved for awards | 105,000,000 | |||
Grant in period | 6,825,000 | 16,350,000 | ||
Performance share description | Each vested PSU is exchangeable for one Unit of the Company. | |||
Compensation expense | $ 8,100 | $ 400 | ||
Unrecognized expense | $ 27,400 | $ 22,700 | ||
Weighted average remaining period | 2 years 3 months | 3 years | ||
PSU | Scenario, Forecast | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Consecutive trading days | 30 days | |||
PSU | Scenario, Forecast | Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Percentage of award | 0.00% | |||
PSU | Scenario, Forecast | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Percentage of award | 200.00% |
Equity Compensation - Summary o
Equity Compensation - Summary of Information Related to PSUs (Detail) - PSU $ / shares in Units, $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)$ / sharesshares | |
Weighted Average Fair Value | ||
Beginning balance | $ / shares | $ 1.41 | |
Units granted | $ / shares | 1.88 | $ 1.41 |
Conversion | $ / shares | 0 | |
Units vested | $ / shares | 0 | 0 |
Ending balance | $ / shares | $ 30.95 | $ 1.41 |
Total Fair Value ($ in thousands) | ||
Units outstanding beginning balance | $ | $ 23,054 | |
PSUs granted | $ | 12,810 | $ 23,054 |
PSUs vested | $ | 0 | 0 |
Conversion | $ | 0 | |
Units outstanding ending balance | $ | $ 35,864 | $ 23,054 |
Conversion ratio | 0.05 | |
Number of units beginning balance | shares | 16,350,000 | |
Number of units granted | shares | 6,825,000 | 16,350,000 |
Number of units vested | shares | 0 | 0 |
Number of units conversion | shares | (22,016,250) | |
Number of units ending balance | shares | 1,158,750 | 16,350,000 |
Equity Compensation - Schedule
Equity Compensation - Schedule of Assumptions Used to Determine the Grant Date Fair Value and Associated Compensation Expense (Detail) - PSU - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Company enterprise value | $ 4,190 | $ 4,560 | $ 3,760 |
Equity volatility | 36.00% | 34.00% | 35.00% |
Weighted average risk-free interest rate | 2.54% | 1.96% | 1.94% |
Transactions with Affiliates -
Transactions with Affiliates - Additional Information (Detail) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | ||||
Accounts payable and accrued liabilities - Affiliates | $ 7,748 | $ 183,820 | ||
Initial term | 5 years | |||
Lease expense | $ 400 | |||
Total commitment, remaining term | 8,300 | |||
Linn Energy Holdings and Citizen Energy LLC | ||||
Related Party Transaction [Line Items] | ||||
Accounts payable and accrued liabilities - Affiliates | 63,000 | |||
MSAs | ||||
Related Party Transaction [Line Items] | ||||
Charges related to services | $ 10,000 | 10,000 | ||
MSAs | Citizen | ||||
Related Party Transaction [Line Items] | ||||
Accounts payable and accrued liabilities - Affiliates | 46,500 | |||
MSAs | Linn Energy Holdings | ||||
Related Party Transaction [Line Items] | ||||
Accounts payable and accrued liabilities - Affiliates | 55,500 | |||
MSAs | Linn Energy Holdings and Citizen Energy LLC | Revenue Suspense | ||||
Related Party Transaction [Line Items] | ||||
Accounts payable and accrued liabilities - Affiliates | 19,000 | |||
Affiliates | Oil and Gas | ||||
Related Party Transaction [Line Items] | ||||
Accounts Receivable - Oil, natural gas, and natural gas liquids sales - Affiliates | 4,700 | |||
Affiliates | Natural Gas and NGL [Member] | ||||
Related Party Transaction [Line Items] | ||||
Revenue from Contract with Customer, Including Assessed Tax | 8,000 | |||
Atlas LLC | ||||
Related Party Transaction [Line Items] | ||||
Charges related to services | 2,300 | $ 2,000 | $ 300 | |
Accounts payable and accrued liabilities - Affiliates | $ 0 | $ 0 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) $ in Millions | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($)Mcf$ / Mcf | |
Commitment And Contingencies [Line Items] | ||
Volume delivery commitment | Mcf | 18,250,000 | |
Delivery commitment period | 2021-11 | |
Volume delivered | Mcf | 3,037,500 | |
Delivery commitment term | In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees of $0.625 per mcf. | |
Deficiency fees per unit | $ / Mcf | 0.625 | |
Deficiency fees | $ | $ 8.6 | |
Drilling Rig Commitments | ||
Commitment And Contingencies [Line Items] | ||
Drilling Commitment | $ | $ 5.1 |
Subsequent Events - Additional
Subsequent Events - Additional Information (Detail) $ in Millions | Apr. 14, 2016USD ($) | Nov. 13, 2018$ / BTU$ / bblMcfbbl | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($)$ / MMBTU | Dec. 31, 2016USD ($) | Sep. 30, 2018$ / BTU |
Subsequent Event [Line Items] | ||||||
Cash consideration for interest acquired in leasehold property | $ 8.9 | $ 49.7 | $ 137.6 | |||
Roan LLC | Linn Energy Holdings | ||||||
Subsequent Event [Line Items] | ||||||
Cash consideration for interest acquired in leasehold property | $ 22.9 | |||||
Natural Gas Commodity Contracts | Swaps | ||||||
Subsequent Event [Line Items] | ||||||
Weighted average price (usd per bbl) | $ / BTU | 2.81 | |||||
Natural Gas Commodity Contracts | 2019 | Swaps | ||||||
Subsequent Event [Line Items] | ||||||
Weighted average price (usd per bbl) | 2.97 | 2.86 | ||||
Subsequent Event | Roan LLC | Linn Energy Holdings | ||||||
Subsequent Event [Line Items] | ||||||
Cash consideration for interest acquired in leasehold property | 22.9 | |||||
Subsequent Event | Roan LLC | Linn Energy Holdings and Citizen Energy LLC | ||||||
Subsequent Event [Line Items] | ||||||
Value of equity units issued | $ 40 | |||||
Subsequent Event | NGL price | October 2018 to December 2019 | Swaps | ||||||
Subsequent Event [Line Items] | ||||||
Fixed price swap per day | bbl | 2,500 | |||||
Subsequent Event | Natural Gas Liquids Commodity Contracts Member | October 2018 to December 2019 | Swaps | ||||||
Subsequent Event [Line Items] | ||||||
Weighted average price (usd per bbl) | $ / bbl | 34.03 | |||||
Subsequent Event | Natural Gas Commodity Contracts | 2019 | Swaps | ||||||
Subsequent Event [Line Items] | ||||||
Fixed price swap per day | Mcf | 20,000 | |||||
Weighted average price (usd per bbl) | $ / BTU | 2.93 |
Supplemental Information on O_3
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Acquisition costs of properties: | |||
Proved properties | $ 214,647 | $ 1,079 | $ 2,291 |
Unproved properties | 1,018,978 | 93,705 | 42,266 |
Exploratory | 8,538 | ||
Development costs | 390,991 | 152,284 | 24,446 |
Costs incurred | $ 1,633,154 | $ 247,068 | $ 69,003 |
Supplemental Information on O_4
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Oil and natural gas properties | ||
Proved | $ 750,492 | $ 184,376 |
Unproved | 1,126,459 | 141,004 |
Less: accumulated depreciation, depletion, amortization and impairment | (78,307) | (27,002) |
Oil and natural gas properties, net | $ 1,798,644 | $ 298,378 |
Supplemental Information on O_5
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail) | 12 Months Ended | ||
Dec. 31, 2017MBoeMMcfMBbls | Dec. 31, 2016MBoeMMcfMBbls | Dec. 31, 2015MBoeMMcfMBbls | |
Reserve Quantities [Line Items] | |||
Balance, beginning | MBoe | 13,057 | 2,484 | 419 |
Purchase of reserves | MBoe | 53,986 | 111 | 160 |
Extensions and discoveries | MBoe | 173,238 | 11,124 | 1,995 |
Revisions of previous estimates | MBoe | (369) | 1,687 | 128 |
Production | MBoe | (8,603) | (2,350) | (217) |
Balance, ending | MBoe | 231,309 | 13,057 | 2,484 |
Oil price | |||
Reserve Quantities [Line Items] | |||
Balance, beginning | 2,900 | 387 | 81 |
Purchase of reserves | 9,843 | 22 | 45 |
Extensions and discoveries | 30,554 | 2,632 | 279 |
Revisions of previous estimates | (3,583) | 598 | 79 |
Production | (2,294) | (740) | (97) |
Balance, ending | 37,420 | 2,900 | 387 |
Natural gas price | |||
Reserve Quantities [Line Items] | |||
Balance, beginning | MMcf | 39,831 | 8,517 | 1,798 |
Purchase of reserves | MMcf | 163,638 | 333 | 608 |
Extensions and discoveries | MMcf | 486,510 | 33,218 | 6,504 |
Revisions of previous estimates | MMcf | 20,844 | 4,145 | 41 |
Production | MMcf | (24,953) | (6,382) | (434) |
Balance, ending | MMcf | 685,869 | 39,831 | 8,517 |
NGL price | |||
Reserve Quantities [Line Items] | |||
Balance, beginning | 3,519 | 678 | 38 |
Purchase of reserves | 16,870 | 33 | 14 |
Extensions and discoveries | 61,599 | 2,956 | 632 |
Revisions of previous estimates | (260) | 398 | 42 |
Production | (2,150) | (546) | (48) |
Balance, ending | 79,578 | 3,519 | 678 |
Supplemental Information On O_6
Supplemental Information On Oil, Natural Gas, And NGL Producing Activities - Additional Information (Detail) | 12 Months Ended | ||||
Dec. 31, 2017aMBoeWell$ / bbl$ / MMBTU | Dec. 31, 2016aMBoeWell$ / bbl$ / MMBTU | Dec. 31, 2015MBoeWell$ / bbl$ / MMBTU | Apr. 14, 2016a | Dec. 31, 2014MBoe | |
Reserve Quantities [Line Items] | |||||
Total Proved Reserves | 231,309 | 13,057 | 2,484 | 419 | |
Number of wells | Well | 93 | 55 | 38 | ||
Extensions and discoveries | 173,238 | 11,124 | 1,995 | ||
Unproved leashold acquired, net | a | 23,400 | 62,461 | 5,791 | ||
Purchase of reserves | 53,986 | 111 | 160 | ||
Revision of previous estiamtes | (369) | 1,687 | 128 | ||
Oil price | |||||
Reserve Quantities [Line Items] | |||||
Prices used in computing the Company's reserves | $ / bbl | 51.34 | 42.64 | 50.16 | ||
Natural gas price | |||||
Reserve Quantities [Line Items] | |||||
Prices used in computing the Company's reserves | $ / MMBTU | 2.98 | 2.48 | 2.59 | ||
NGL price | |||||
Reserve Quantities [Line Items] | |||||
Prices used in computing the Company's reserves | $ / bbl | 19 | 15.26 | 17.53 | ||
Increase in Pricing | |||||
Reserve Quantities [Line Items] | |||||
Revision of previous estiamtes | 3,277 | ||||
Performance | |||||
Reserve Quantities [Line Items] | |||||
Revision of previous estiamtes | (3,646) | ||||
Linn Acquisition | |||||
Reserve Quantities [Line Items] | |||||
Purchase of reserves | 53,986 |
Supplemental Information on O_7
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Schedule of Estimated Quantities of Proved Developed and Proved Undeveloped ("PUD") Oil, Natural Gas and NGL Reserves of the Company (Detail) | Dec. 31, 2017MBoeMMcfMBbls | Dec. 31, 2016MBoeMMcfMBbls | Dec. 31, 2015MBoeMMcfMBbls | Dec. 31, 2014MBoeMMcfMBbls |
Reserve Quantities [Line Items] | ||||
Total Proved Developed Reserves | MBoe | 79,585 | 13,057 | 2,484 | |
Total Proved Undeveloped Reserves | MBoe | 151,724 | |||
Total Proved Reserves | MBoe | 231,309 | 13,057 | 2,484 | 419 |
Oil price | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed Reserves | 12,352 | 2,900 | 387 | |
Proved Undeveloped Reserves | 25,068 | |||
Proved Reserves | 37,420 | 2,900 | 387 | 81 |
Natural gas price | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed Reserves | MMcf | 259,193 | 39,831 | 8,517 | |
Proved Undeveloped Reserves | MMcf | 426,676 | |||
Proved Reserves | MMcf | 685,869 | 39,831 | 8,517 | 1,798 |
NGL price | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed Reserves | 24,034 | 3,519 | 678 | |
Proved Undeveloped Reserves | 55,544 | |||
Proved Reserves | 79,578 | 3,519 | 678 | 38 |
Supplemental Information on O_8
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Results of Operations for Oil and Gas Producing Activities (Detail) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Results of Operations, Income before Income Taxes [Abstract] | |||||
Oil, natural gas, and NGL sales | $ 166,385 | $ 54,965 | $ 5,685 | ||
Production expenses | $ 30,111 | $ 10,450 | 16,872 | 5,090 | 549 |
Gathering, transportation and processing | $ 0 | $ 11,360 | 18,602 | 5,920 | 273 |
Production taxes | 3,685 | 1,087 | 190 | ||
Exploration expenses | 28,154 | ||||
Depreciation, depletion and amortization | 36,979 | 24,909 | 2,060 | ||
Accretion of asset retirement obligations | 364 | 87 | 31 | ||
Impairment | 4,475 | 5,258 | 121 | ||
Results of operations | $ 57,254 | $ 12,614 | $ 2,461 |
Supplemental Information on O_9
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Summary of Company's Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract] | |||||
Future cash inflows | $ 5,270,465 | $ 271,428 | $ 47,310 | ||
Future production costs | (1,664,724) | (102,817) | (21,289) | ||
Future development costs | (745,769) | ||||
Future income tax expense | [1] | 0 | 0 | 0 | |
Future net cash flows | 2,859,972 | 168,611 | 26,021 | ||
Discount to present value at 10% annual rate | (1,664,303) | (50,339) | (7,111) | ||
Standardized measure of discounted future net cash flows | $ 1,195,669 | $ 118,272 | $ 18,910 | $ 6,500 | |
[1] | The Company is a limited liability company treated as a disregarded entity for income tax purposes. |
Supplemental Information on _10
Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Summary of Company's Standardized Measure of Discounted Future Net Cash Flows - Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract] | |||
Standardized measure, beginning of year | $ 118,272 | $ 18,910 | $ 6,500 |
Sales of oil, natural gas and NGLs produced, net of production costs | (124,526) | (42,868) | (4,673) |
Net changes in prices and production costs | 36,233 | 18,256 | (2,614) |
Extensions and discoveries, net of production and development costs | 877,846 | 104,581 | 15,235 |
Changes in estimated future development costs | (17,970) | ||
Development costs incurred during the period that reduce future costs | 148,505 | ||
Revisions of previous quantity estimates | (5,676) | 15,573 | 985 |
Purchases of reserves | 279,026 | 462 | 1,428 |
Accretion of discount | 11,827 | 1,891 | 650 |
Changes in production rates and other | (127,868) | 1,467 | 1,399 |
Standardized measure, end of year | $ 1,195,669 | $ 118,272 | $ 18,910 |
Revenue from Contracts with C_3
Revenue from Contracts with Customers - Summary of New Accounting Pronouncements and Changes in Accounting Principles (Detail) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Operating expenses | ||||||
Gathering, transportation and processing | $ 0 | $ 11,360 | $ 18,602 | $ 5,920 | $ 273 | |
Net loss | (288,916) | [1] | 28,837 | 18,457 | 6,947 | 391 |
Under ASC 605 | ||||||
Operating expenses | ||||||
Gathering, transportation and processing | 30,396 | |||||
Net loss | (288,916) | |||||
Oil sales | ||||||
Revenues | ||||||
Revenues | 197,356 | $ 45,702 | $ 76,876 | $ 30,565 | $ 3,972 | |
Oil sales | Under ASC 605 | ||||||
Revenues | ||||||
Revenues | 197,431 | |||||
Natural gas sales | ||||||
Revenues | ||||||
Revenues | 48,956 | |||||
Natural gas sales | Under ASC 605 | ||||||
Revenues | ||||||
Revenues | 60,919 | |||||
Natural gas liquid sales | ||||||
Revenues | ||||||
Revenues | 65,377 | |||||
Natural gas liquid sales | Under ASC 605 | ||||||
Revenues | ||||||
Revenues | 83,735 | |||||
Accounting Standards Update 2014-09 | Increase/ (decrease) | ||||||
Operating expenses | ||||||
Gathering, transportation and processing | (30,396) | |||||
Net loss | 0 | |||||
Accounting Standards Update 2014-09 | Oil sales | Increase/ (decrease) | ||||||
Revenues | ||||||
Revenues | (75) | |||||
Accounting Standards Update 2014-09 | Natural gas sales | Increase/ (decrease) | ||||||
Revenues | ||||||
Revenues | (11,963) | |||||
Accounting Standards Update 2014-09 | Natural gas liquid sales | Increase/ (decrease) | ||||||
Revenues | ||||||
Revenues | $ (18,358) | |||||
[1] | Amounts are allocated to stockholders' equity and members' equity to reflect the Reorganization. See Note 10 - Equity for discussion of the Reorganization. |
Revenue from Contracts with C_4
Revenue from Contracts with Customers - Additional Information (Detail) $ in Millions | Sep. 30, 2018USD ($) |
Revenue from Contract with Customer [Abstract] | |
Contract with customer accounts receivable | $ 62.1 |
Acquisitions and Divestitures_4
Acquisitions and Divestitures - Schedule of Assumptions to Determine Fair value of the Oil and Natural Gas (Detail) | Aug. 31, 2017 | |
Discount Rate | Linn Acquisition | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input | 0.0950 | |
Reserve Risk Factor | Minimum | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input | 0.35 | [1] |
Reserve Risk Factor | Maximum | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input | 1 | [1] |
Price Escalation | Linn Acquisition | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input | 0.0200 | [2] |
Oil price | Oil price | Linn Acquisition | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input description | three years NYMEX WTI forward curve | |
Natural gas price | Linn Acquisition | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input description | three years NYMEX Henry Hub forward curve | |
NGL price | Linn Acquisition | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input description | 39% of oil price | |
Possible Reserves | Reserve Risk Factor | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input | 0.35 | |
Probable Reserve | Reserve Risk Factor | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input | 0.75 | |
Proved Undeveloped Reserves | Reserve Risk Factor | ||
Business Acquisition [Line Items] | ||
Acquisition, measurement input | 0.90 | |
[1] | Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%. | |
[2] | Prices were escalated at the end of the forward curve |
Acquisitions - Schedule of Supp
Acquisitions - Schedule of Supplemental Proforma Results of Operations (Detail) - Linn Acquisition - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Business Acquisition, Pro Forma Information [Line Items] | ||||
Revenue | $ 156,593 | $ 215,588 | $ 90,238 | $ 28,139 |
Net income | $ 55,253 | $ 44,269 | $ 26,378 | $ 6,299 |
Derivative Instrument - Sched_2
Derivative Instrument - Schedule of Net Gains and Loss on Derivative Contracts (Detail) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
(Loss) gain on derivative contracts | $ (100,920) | $ 2,385 | |
Net cash (paid) received upon settlement of derivative contracts | (27,462) | 2,385 | $ 2,705 |
Net cash received upon settlement of derivative contracts prior to contractual maturity | $ 377 | $ 2,255 |
Fair Value Measurements - Summa
Fair Value Measurements - Summary of Classifications of the Company's Derivative Assets and Liabilities (Detail) - USD ($) | Sep. 30, 2018 | Dec. 31, 2017 |
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Transfers between Level 1, Level 2, or Level 3 | $ 0 | |
Fair Value, Measurements, Recurring | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 5,190,000 | $ 5,038,000 |
Netting | (4,987,000) | (3,890,000) |
Total assets, Carrying Value | 203,000 | 1,148,000 |
Derivative Liabilities | (88,149,000) | (14,540,000) |
Netting | 4,987,000 | 3,890,000 |
Total liabilities, Carrying Value | (83,162,000) | (10,650,000) |
Fair Value, Measurements, Recurring | Level 1 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 0 | 0 |
Derivative Liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 2 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 5,190,000 | 5,038,000 |
Derivative Liabilities | (88,149,000) | (14,540,000) |
Fair Value, Measurements, Recurring | Level 3 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 0 | 0 |
Derivative Liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Current commodity derivatives | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 4,282,000 | 2,856,000 |
Netting | (4,079,000) | (2,704,000) |
Total assets, Carrying Value | 203,000 | 152,000 |
Derivative Liabilities | (68,340,000) | (11,983,000) |
Netting | 4,079,000 | 2,704,000 |
Total liabilities, Carrying Value | (64,261,000) | (9,279,000) |
Fair Value, Measurements, Recurring | Current commodity derivatives | Level 1 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 0 | 0 |
Derivative Liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Current commodity derivatives | Level 2 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 4,282,000 | 2,856,000 |
Derivative Liabilities | (68,340,000) | (11,983,000) |
Fair Value, Measurements, Recurring | Current commodity derivatives | Level 3 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 0 | 0 |
Derivative Liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Noncurrent commodity derivatives | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 908,000 | 2,182,000 |
Netting | (908,000) | (1,186,000) |
Total assets, Carrying Value | 0 | 996,000 |
Derivative Liabilities | (19,809,000) | (2,557,000) |
Netting | 908,000 | 1,186,000 |
Total liabilities, Carrying Value | (18,901,000) | (1,371,000) |
Fair Value, Measurements, Recurring | Noncurrent commodity derivatives | Level 1 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 0 | 0 |
Derivative Liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Noncurrent commodity derivatives | Level 2 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 908,000 | 2,182,000 |
Derivative Liabilities | (19,809,000) | (2,557,000) |
Fair Value, Measurements, Recurring | Noncurrent commodity derivatives | Level 3 | ||
'Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets | 0 | 0 |
Derivative Liabilities | $ 0 | $ 0 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Income Taxes Disclosure [Line Items] | ||||
Effective combined U.S. federal and state income tax rate | 25.50% | |||
Income tax expense | $ 299,662 | $ 299,662 | $ 0 | $ 0 |
Income tax receivable | 7,700 | 7,700 | ||
Accounts payable and accrued liabilities - Affiliates | 7,748 | 7,748 | $ 183,820 | |
Riviera | TMA | ||||
Income Taxes Disclosure [Line Items] | ||||
Accounts payable and accrued liabilities - Affiliates | $ 7,700 | $ 7,700 |
Income Taxes Schedule of Deferr
Income Taxes Schedule of Deferred Tax Liabilities (Detail) $ in Thousands | Sep. 30, 2018USD ($) |
Income Tax Disclosure [Abstract] | |
Oil and natural gas properties | $ (322,911) |
Derivative contracts | 22,530 |
Other | 719 |
Deferred tax liabilities, net | $ (299,662) |