Document And Entity Information
Document And Entity Information | 12 Months Ended |
Dec. 31, 2018USD ($)shares | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | Alta Mesa Holdings, LP |
Entity Central Index Key | 0001518403 |
Document Type | 10-K |
Document Period End Date | Dec. 31, 2018 |
Amendment Flag | false |
Document Fiscal Year Focus | 2018 |
Document Fiscal Period Focus | FY |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Non-accelerated Filer |
Entity Small Business | false |
Entity Emerging Growth Company | true |
Entity Ex Transition Period | false |
Entity Emerging Growth Company | false |
Entity Common Stock, Shares Outstanding (in shares) | shares | 0 |
Entity Public Float | $ | $ 0 |
Entity Current Reporting Status | Yes |
Entity Voluntary Filers | No |
Entity Well-known Seasoned Issuer | No |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue | ||||
Operating revenue | $ 414,507 | |||
Gain on sale of assets | 4,751 | |||
Gain on acquisitions of oil and gas properties | 0 | |||
Gain (loss) on derivatives | (10,247) | |||
Total revenue | 409,011 | |||
Operating expenses | ||||
Lease operating | 60,547 | |||
Transportation and marketing | 50,038 | |||
Production taxes | 16,865 | |||
Workovers | 5,563 | |||
Exploration | 34,085 | |||
Depreciation, depletion and amortization | 133,554 | |||
Impairment of assets | 2,033,712 | |||
General and administrative | 114,735 | |||
Total operating expenses | 2,449,099 | |||
Operating income | (2,040,088) | |||
Other income (expense) | ||||
Interest expense | (38,265) | |||
Interest income and other | 1,983 | |||
Loss on debt extinguishment | 0 | |||
Total other income (expense), net | (36,282) | |||
Loss from continuing operations before income taxes | (2,076,370) | |||
Income tax provision (benefit) | 4 | |||
Loss from continuing operations | (2,076,374) | |||
Loss from discontinued operations, net of tax | 0 | |||
Net loss | (2,076,374) | |||
Oil | ||||
Revenue | ||||
Operating revenue | 323,299 | |||
Natural gas | ||||
Revenue | ||||
Operating revenue | 43,407 | |||
Natural gas liquids | ||||
Revenue | ||||
Operating revenue | 43,039 | |||
Other | ||||
Revenue | ||||
Operating revenue | $ 4,762 | |||
Predecessor | ||||
Revenue | ||||
Operating revenue | $ 40,136 | $ 269,386 | $ 142,356 | |
Gain on sale of assets | 840 | 28 | 3 | |
Gain on acquisitions of oil and gas properties | 0 | 1,668 | 0 | |
Gain (loss) on derivatives | 6,663 | 8,287 | (40,460) | |
Total revenue | 47,639 | 279,369 | 101,899 | |
Operating expenses | ||||
Lease operating | 4,408 | 43,953 | 29,567 | |
Transportation and marketing | 3,725 | 29,460 | 11,628 | |
Production taxes | 953 | 5,494 | 2,765 | |
Workovers | 423 | 4,255 | 3,441 | |
Exploration | 7,003 | 13,563 | 17,230 | |
Depreciation, depletion and amortization | 11,670 | 89,115 | 53,755 | |
Impairment of assets | 0 | 1,188 | 382 | |
General and administrative | 21,234 | 55,671 | 40,468 | |
Total operating expenses | 49,416 | 242,699 | 159,236 | |
Operating income | (1,777) | 36,670 | (57,337) | |
Other income (expense) | ||||
Interest expense | (5,511) | (50,585) | (59,675) | |
Interest income and other | 172 | 1,075 | 884 | |
Loss on debt extinguishment | 0 | 0 | (18,151) | |
Total other income (expense), net | (5,339) | (49,510) | (76,942) | |
Loss from continuing operations before income taxes | (7,116) | (12,840) | (134,279) | |
Income tax provision (benefit) | 0 | 6 | 0 | |
Loss from continuing operations | (7,116) | (12,846) | (134,279) | |
Loss from discontinued operations, net of tax | (7,746) | (64,815) | (33,642) | |
Net loss | (14,862) | (77,661) | (167,921) | |
Predecessor | Oil | ||||
Revenue | ||||
Operating revenue | 30,972 | 194,423 | 105,811 | |
Predecessor | Natural gas | ||||
Revenue | ||||
Operating revenue | 4,276 | 37,794 | 20,021 | |
Predecessor | Natural gas liquids | ||||
Revenue | ||||
Operating revenue | 4,000 | 31,445 | 14,174 | |
Predecessor | Other | ||||
Revenue | ||||
Operating revenue | $ 888 | $ 5,724 | $ 2,350 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents | $ 12,984 | |
Restricted cash | 1,001 | |
Accounts receivable, net | 68,370 | |
Other receivables | 6,267 | |
Related party receivables | 24,282 | |
Notes receivable from related party | 0 | |
Prepaid expenses and other current assets | 747 | |
Current assets — discontinued operations | 0 | |
Derivatives | 16,423 | |
Total current assets | 130,074 | |
Property and equipment | ||
Oil and gas properties, successful efforts method, net | 763,337 | |
Other property and equipment, net | 38,147 | |
Total property and equipment, net | 801,484 | |
Other assets | ||
Deferred financing costs | 1,151 | |
Notes receivable from affiliate | 0 | |
Deposits and other long-term assets | 63 | |
Noncurrent assets — discontinued operations | 0 | |
Derivatives | 2,947 | |
Total other assets | 4,161 | |
Total assets | 935,719 | |
Current liabilities | ||
Accounts payable and accrued liabilities | 197,064 | |
Accounts payable — related party | 3,425 | |
Advances from non-operators | 5,193 | |
Advances from related party | 9,822 | |
Asset retirement obligations | 2,079 | |
Current liabilities — discontinued operations | 0 | |
Derivatives | 1,710 | |
Total current liabilities | 219,293 | |
Long-term liabilities | ||
Asset retirement obligations, net of current portion | 9,330 | |
Long-term debt, net | 690,123 | |
Noncurrent liabilities — discontinued operations | 0 | |
Derivatives | 180 | |
Other long-term liabilities | 0 | |
Total long-term liabilities | 699,633 | |
Total liabilities | 918,926 | |
Commitments and contingencies (Note 14) | ||
Partners’ capital | 16,793 | |
Total liabilities and partners’ capital | $ 935,719 | |
Predecessor | ||
Current assets | ||
Cash and cash equivalents | 3,660 | |
Restricted cash | 1,269 | |
Accounts receivable, net | 76,161 | |
Other receivables | 1,388 | |
Related party receivables | 790 | |
Notes receivable from related party | 0 | |
Prepaid expenses and other current assets | 2,932 | |
Current assets — discontinued operations | 5,195 | |
Derivatives | 216 | |
Total current assets | 91,611 | |
Property and equipment | ||
Oil and gas properties, successful efforts method, net | 894,630 | |
Other property and equipment, net | 32,140 | |
Total property and equipment, net | 926,770 | |
Other assets | ||
Deferred financing costs | 1,787 | |
Notes receivable from affiliate | 12,369 | |
Deposits and other long-term assets | 9,067 | |
Noncurrent assets — discontinued operations | 43,785 | |
Derivatives | 8 | |
Total other assets | 67,016 | |
Total assets | 1,085,397 | |
Current liabilities | ||
Accounts payable and accrued liabilities | 170,489 | |
Accounts payable — related party | 5,476 | |
Advances from non-operators | 5,502 | |
Advances from related party | 23,390 | |
Asset retirement obligations | 69 | |
Current liabilities — discontinued operations | 15,419 | |
Derivatives | 19,303 | |
Total current liabilities | 239,648 | |
Long-term liabilities | ||
Asset retirement obligations, net of current portion | 10,400 | |
Long-term debt, net | 607,440 | |
Noncurrent liabilities — discontinued operations | 66,862 | |
Derivatives | 1,114 | |
Other long-term liabilities | 5,488 | |
Total long-term liabilities | 691,304 | |
Total liabilities | 930,952 | |
Partners’ capital | 154,445 | |
Total liabilities and partners’ capital | $ 1,085,397 |
Consolidated Statements Of Chan
Consolidated Statements Of Changes In Partners' Capital $ in Thousands | USD ($) |
BALANCE, BEGINNING (Predecessor) at Dec. 31, 2015 | $ (177,049) |
Contributions | Predecessor | 377,076 |
Net loss | Predecessor | (167,921) |
BALANCE, ENDING (Predecessor) at Dec. 31, 2016 | 32,106 |
Contributions | Predecessor | 200,000 |
Net loss | Predecessor | (77,661) |
BALANCE, ENDING (Predecessor) at Dec. 31, 2017 | 154,445 |
Contributions | Predecessor | 43,482 |
Net loss | Predecessor | (14,862) |
BALANCE, ENDING (Predecessor) at Feb. 08, 2018 | 183,065 |
BALANCE, ENDING at Feb. 08, 2018 | 1,535,891 |
Contributions | 560,344 |
Distribution of non-STACK oil and gas assets, net of associated liabilities | (32,535) |
Issuance of additional AMH purchase consideration | 9,467 |
Equity-based compensation expense | 20,000 |
Net loss | (2,076,374) |
BALANCE, ENDING at Dec. 31, 2018 | $ 16,793 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities: | ||||
Net loss | $ (2,076,374) | |||
Adjustments to reconcile net loss to cash from operating activities: | ||||
Depreciation, depletion and amortization | 133,554 | |||
Provision for uncollectible related party receivables | 22,438 | |||
Impairments | 2,033,712 | |||
Amortization of deferred financing costs | 221 | |||
Amortization of debt (premium) discount | (4,512) | |||
Equity-based compensation expense | 20,000 | |||
Exploratory dry hole expense | 1,954 | |||
Expired leases | 24,101 | |||
(Gain) loss on derivatives | 10,247 | |||
Cash settlements of derivatives | (38,961) | |||
Premium paid on derivatives | 0 | |||
Interest converted into debt | 0 | |||
(Gain) loss on sale of property and equipment | 12,454 | |||
(Gain) loss on sale of property and equipment | 388 | |||
Gain on acquisitions of oil and gas properties | 0 | |||
Impact on cash from changes in: | ||||
Accounts receivable | 10,936 | |||
Other receivables | (4,205) | |||
Receivables from affiliate and related party | (14,320) | |||
Prepaid expenses and other non-current assets | 10,881 | |||
Advances from related party | (37,684) | |||
Settlement of asset retirement obligations | (1,610) | |||
Accounts payable to related party | 2,032 | |||
Accounts payable, accrued liabilities, and other liabilities | (11,772) | |||
Cash from operating activities | 93,480 | |||
Cash flows from investing activities: | ||||
Capital expenditures | (700,953) | |||
Acquisitions, net of cash acquired | (31,959) | |||
Proceeds from sale of assets | 89,166 | |||
Notes receivable due from affiliate | 0 | |||
Cash from investing activities | (643,746) | |||
Cash flows from financing activities: | ||||
Proceeds from long-term debt borrowings | 241,000 | |||
Repayments of long-term debt | (214,065) | |||
Deferred financing costs paid | (1,373) | |||
Capital distributions | (32,000) | |||
Capital contributions | 560,344 | |||
Cash from financing activities | 553,906 | |||
Net Increase (Decrease) In Cash, Cash Equivalents and Restricted Cash | 3,640 | |||
Cash, Cash Equivalents and Restricted Cash, Beginning of Period | 10,345 | |||
Cash, Cash Equivalents and Restricted Cash, End of Period | $ 10,345 | 13,985 | ||
Predecessor | ||||
Cash flows from operating activities: | ||||
Net loss | (14,862) | $ (77,661) | $ (167,921) | |
Adjustments to reconcile net loss to cash from operating activities: | ||||
Depreciation, depletion and amortization | 12,554 | 113,634 | 95,075 | |
Provision for uncollectible related party receivables | 0 | 0 | 0 | |
Impairments | 5,560 | 30,317 | 16,306 | |
Amortization of deferred financing costs | 171 | 2,732 | 3,905 | |
Amortization of debt (premium) discount | 0 | 0 | 468 | |
Equity-based compensation expense | 0 | 0 | 0 | |
Exploratory dry hole expense | 0 | 2,500 | 419 | |
Expired leases | 4,575 | 9,125 | 11,158 | |
(Gain) loss on derivatives | (6,663) | (8,287) | 40,460 | |
Cash settlements of derivatives | (2,296) | 4,117 | 88,689 | |
Premium paid on derivatives | 0 | (520) | 18,151 | |
Interest converted into debt | 103 | 1,209 | 1,209 | |
(Gain) loss on sale of property and equipment | (85) | (867) | (774) | |
(Gain) loss on sale of property and equipment | 1,923 | 22,179 | (3,542) | |
Gain on acquisitions of oil and gas properties | 0 | (3,294) | 0 | |
Impact on cash from changes in: | ||||
Accounts receivable | (21,184) | (43,530) | (10,500) | |
Other receivables | (662) | 6,519 | 10,465 | |
Receivables from affiliate and related party | (117) | 218 | 45 | |
Prepaid expenses and other non-current assets | (591) | (6,203) | (819) | |
Advances from related party | 24,116 | (19,138) | 42,528 | |
Settlement of asset retirement obligations | (63) | (6,409) | (2,125) | |
Accounts payable to related party | 0 | (2,170) | 0 | |
Accounts payable, accrued liabilities, and other liabilities | 23,857 | 34,857 | (11,493) | |
Cash from operating activities | 26,336 | 59,328 | 131,704 | |
Cash flows from investing activities: | ||||
Capital expenditures | (36,695) | (313,961) | (214,061) | |
Acquisitions, net of cash acquired | (1,218) | (55,605) | (11,527) | |
Proceeds from sale of assets | 0 | 25,205 | 1,290 | |
Notes receivable due from affiliate | 0 | (1,515) | 0 | |
Cash from investing activities | (37,913) | (345,876) | (224,298) | |
Cash flows from financing activities: | ||||
Proceeds from long-term debt borrowings | 60,000 | 373,065 | 722,557 | |
Repayments of long-term debt | (43,000) | (296,622) | (921,034) | |
Deferred financing costs paid | 0 | (398) | (13,747) | |
Capital distributions | (68) | 0 | ||
Capital contributions | 0 | 207,875 | 303,462 | |
Cash from financing activities | 16,932 | 283,920 | 91,238 | |
Net Increase (Decrease) In Cash, Cash Equivalents and Restricted Cash | 5,355 | (2,628) | (1,356) | |
Cash, Cash Equivalents and Restricted Cash, Beginning of Period | 4,990 | $ 10,345 | 7,618 | 8,974 |
Cash, Cash Equivalents and Restricted Cash, End of Period | $ 10,345 | $ 4,990 | $ 7,618 |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of Business | DESCRIPTION OF BUSINESS Alta Mesa Holdings, LP (“Alta Mesa” or “the Company”) is an independent exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”). Our operations prior to February 9, 2018, also included other oil and gas interests in Texas, Louisiana, Idaho and Florida. In connection with the closing of the Business Combination described below, in which we were acquired by our parent company, Alta Mesa Resources, Inc. (“AMR”), on February 9, 2018, we distributed our non-STACK oil and gas assets and liabilities to High Mesa Holdings, LP (the “AM Contributor”) and completed our transition from a multi-play asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Accounting and Presentation These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We had no items of other comprehensive income during any period presented. Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation, but had no impact on net income (loss) or partners’ capital. As a result of the Business Combination, AMR was treated as the accounting acquirer and we were the accounting acquiree. Our identifiable assets acquired and liabilities assumed by AMR were recorded at their estimated fair values which caused push down effects to us on the acquisition date. As a result, our financial statements and certain footnote presentations separate our presentation into two distinct periods, the period before the consummation of the transaction (“Predecessor Period”) and the period after that date (“Successor Period”), to indicate the application of the different basis of accounting between the periods presented. The period January 1, 2018 to February 8, 2018 is referred to as the 2018 Predecessor Period. As noted above, we distributed our remaining non-STACK oil and gas assets and liabilities to the AM Contributor just prior to the closing of the Business Combination. We have determined that the remaining non-STACK oil and gas assets and liabilities as well as our Weeks Island field sold during the 4th quarter of 2017 are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its subsidiaries, and eliminate all intercompany transactions and balances. The Company’s interests in oil and gas upstream ventures and partnerships are proportionately consolidated, in accordance with GAAP. Use of Estimates Preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported revenue and expenses during the reporting period. Estimates of reserves and their value are used to determine depletion and to conduct impairment analysis of oil and gas properties and can significantly affect future estimated cash flows utilized to assess goodwill and intangible assets for impairment. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of development expenditures. Other estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, derivatives, accounting for business combinations, share-based compensation and contingencies. We base certain of our estimates on historical experience and various other assumptions that we believe to be reasonable. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates. Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company regularly maintains cash balances that exceed federally insured amounts but we have experienced no losses associated with these amounts. As of December 31, 2018 and 2017 , we did not have any assets classified as cash equivalents. Restricted Cash Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2018 and 2017 , our restricted cash represents cash received for production where the final division of ownership is in dispute or there is unclaimed property for pooling orders in Oklahoma. Accounts Receivable Our receivables arise primarily from (i) the sale of our production and (ii) joint interest owners’ portion of operating costs for properties in which we are the operator. The purchasers of our production are concentrated in the oil and gas industry and therefore they are similarly affected by prevailing industry conditions. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties we operate and market the production. We routinely assess the recoverability of our receivables to determine their collectibility. We establish a valuation allowance to reduce receivables to their estimated collectible amounts, based upon several factors including, our historical experience, the length of time a receivable has been outstanding, communication with customers and the current and projected financial condition of specific customers. Property and Equipment Our oil and gas property is accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized. Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts to obtain a mineral interest or right in a property, including related broker and other fees. These costs are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties, or when leases expire, at which time the costs are expensed as exploration costs. Unproved properties are not subject to depletion. Proved Oil and Gas Properties — We capitalize costs incurred to drill, complete and equip proved reserves. Proved property costs include all costs incurred to drill and equip successful exploratory wells, development wells (regardless of success), development-type stratigraphic test wells and service wells, plus costs transferred from unproved properties. Accounting policies for other assets include: Other Property and Equipment — Other property and equipment, such as land, vehicles, office furniture and office equipment, are recorded at cost. Maintenance, repairs and minor renewals are expensed as incurred. Other important accounting policies affecting property and equipment include: Depreciation and Depletion — Depletion of proved oil and gas properties is computed using the unit-of-production method based upon produced volumes and estimated proved reserves. Because all of our oil and gas properties are located in a single basin, we apply depletion on a single cost center. We deplete leasehold acquisition costs and the cost to acquire proved properties (generally proved undeveloped costs) based upon total estimated proved reserves. We deplete costs to drill, complete and equip wells plus the related lease costs (generally proved developed costs) over estimated proved developed reserves. Other non-oil and gas property and equipment is depreciated over their estimated useful life, ranging from three to seven years . Impairment — Because proved reserves have not been ascribed to unproved property, in determining whether it is impaired, we consider numerous factors including recent leasing activity, current development plans, recent drilling results in the area, our geologists’ evaluation and the remaining lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated proved and unproved reserves and, combined with a market approach, estimate fair value. Our cash flow estimates for unproved reserves are reduced by additional risk-weighting factors. We then reduce the carrying amount, if higher, to estimated fair value. We review proved oil and gas properties at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows to the carrying value. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value, which we estimate by discounting the projected future cash flows using an appropriate risk-adjusted rate. We evaluate whether the value of all other long-lived assets is impaired when circumstances indicate the carrying value of those assets may not be recoverable. Such circumstances could result from events such as changes in the condition of an asset or a change in our intent to utilize the asset. The determination of recovery is based on undiscounted cash flow projections compared to the carrying value of the assets. If the carrying amount exceeds undiscounted future net cash flows, we adjust the carrying amount of the assets to their estimated fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent comparable sales, estimated replacement cost, an internally-developed, market participant-based discounted cash flow analysis or an analysis from outside professional advisors. Exploration Expense Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, delay rentals, gains or losses on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well yields commercial reserves. If the exploratory well is determined to be unsuccessful, the cost is expensed as exploration expense in the period of that determination. If the exploratory well yields commercial reserves, it is transferred to proved oil and gas properties. Exploratory well costs may continue to be capitalized for several reporting periods if there is ongoing assessment of commerciality. Deferred Financing Costs Deferred financing costs reflect fees paid to lenders and third parties that are directly related to our establishment of our long term debt. The costs associated with the Alta Mesa RBL are reported as non-current assets and are amortized over the term of the facility as additional interest expense. During the Predecessor Periods, costs associated with the issuance of the 2024 Notes were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense. Acquisitions Business combinations are accounted for using the acquisition method of accounting. Accordingly, the results of operations of any acquired businesses are included in our results of operations from the closing date. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition. Asset Retirement Obligations We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The asset retirement cost is recognized as depletion or depreciation over the life of the asset. Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations. Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment. Bond Premium on Senior Unsecured Notes In connection with the Business Combination, we estimated the fair value of our $500.0 million senior unsecured notes at $533.6 million . The excess above the face value was recognized as a bond premium, which is being amortized as a reduction in interest expense over the remaining term of the notes. Derivatives We present our derivatives as assets or liabilities at estimated fair value. Changes in fair value of our derivatives, along with realized gains or losses from settlements, are recognized as “Gain (loss) on derivatives” in the statements of operations. Settlements of derivatives are classified as operating cash flows. Where master netting agreements are in place, we net the value of our derivative assets and liabilities with the same counterparty. Revenue Recognition Predecessor - Oil, natural gas, and NGL revenue were recognized when production was sold to a purchaser at a fixed or determinable price, when delivery had occurred and title had transferred, and collectibility of the revenue was reasonably assured. During the Predecessor Periods, we followed the sales method of accounting for revenue. Under this method of accounting, revenue was recognized based on volumes sold. There were no material gas imbalances during the periods presented. Successor - In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance under GAAP. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply ASC 606 using either the full retrospective approach or a modified retrospective approach. Effective December 31, 2018, we ceased to be an emerging growth company and adopted ASC 606 for the Successor Period, using a modified retrospective approach. There was no impact on the timing of recognition of revenue or of our classification of amounts between revenue and operating expenses upon adoption of ASC 606 . Our revenue from contracts with customers includes the sale of crude oil, natural gas, and NGLs. These sales are recognized as revenue when production is sold to a customer in fulfillment of performance obligations under the terms of the underlying contracts. Performance obligations primarily comprise delivery of our production at a delivery point, as negotiated within each contract. Each unit of oil, natural gas, and NGL is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied once control of the product has been transferred to the customer. We consider a variety of facts and circumstances in assessing the point control is transferred, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, our right to payment, and transfer of legal title. Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price or at purchaser posted prices for the producing area. For oil contracts, we record sales and related expenses on a gross basis upon satisfaction of our performance obligations. Our natural gas production is primarily sold to purchasers at prevailing market prices. We evaluate the contract terms of our gas processing arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis based on the assessment of control and, when applicable, principal versus agent guidance under ASC 606. During the Successor Period, we determined that we controlled the products during processing (i.e., control transfers at the tailgate of the processing plant) or until the processor’s sale to the end customers in downstream markets (i.e., the processor is our agent and we are the principal selling party). Accordingly, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the customer and the gathering and processing services are rendered, similar to the accounting treatment required under previous revenue accounting guidance. All facts and circumstances are considered and judgment is often required in making this determination. Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables. Our receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates, as well as for unbilled costs for wells subject to Oklahoma’s forced pooling process in which mineral owners have the option to participate in the drilling of pooled wells. Depending on the mineral owner’s decision, these costs will be billed to them or added to our oil and gas properties. Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts. We have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors and have reflected this disaggregation of revenue for all periods presented. We do not have material unsatisfied performance obligations for contracts as all contracts have either an original expected length of one year or less or the entire future consideration is variable and allocated entirely to a wholly unsatisfied performance obligation. Equity-Based Compensation Our parent company, AMR, grants various types of stock-based awards, including stock options, restricted stock and performance-based restricted stock units to certain of our employees. The fair value of stock option awards is determined using the Black-Scholes option pricing model, which includes various assumptions. Expected volatilities utilized in the option pricing model are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. Dividend yield is based on our expectations of dividend payments during the expected term of the options granted and risk-free interest rates are based on U.S. Treasury rates in effect at the grant date. Service-based restricted stock awards are valued using the market price of AMR’s Class A Common Stock on the grant date. Performance-based restricted stock awards are valued using the market price of AMR’s Class A Common Stock at the later of grant date and when all performance-based criteria are determined. We recognize the estimated fair value of stock option and restricted stock awards as compensation expense on a straight-line basis over the applicable vesting period, which generally is three years, except in the case of awards made to our directors, which vest immediately upon issuance. Awards of performance-based restricted stock units that contain tranches with multi-year performance targets are recognized over the vesting period for which performance criteria for each tranche have been determined. All awards to employees typically require continued employment to vest. Forfeitures of unvested awards are recognized when they occur and result in the reversal of previously recognized expense. Income Taxes We have elected under the Internal Revenue Code of 1986, as amended, to be treated as an individual partnership for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are not taxed at the partnership level. Accordingly, no tax provision for federal income taxes is included in these financial statements. Fair Value Hierarchy Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date within our principal market. There are three levels of the fair value hierarchy: • Level 1 — Fair value is based on quoted prices in active markets for identical assets or liabilities. • Level 2 — Fair value is determined using significant observable inputs, generally either quoted prices in active markets for similar assets or liabilities, or quoted prices in markets that are not active. • Level 3 — Fair value is determined using one or more significant inputs that are unobservable in active markets at the measurement date. Such inputs are often used in pricing models, discounted cash flow calculations, or similar techniques. We utilize fair value measurements to account for certain items, determine certain account balances and provide disclosures. Fair value measurements are also utilized in assessing the impairment of long-lived assets. We consider the book values of our cash, accounts and notes receivable and current liabilities to approximate fair value due to their short-term nature. We also consider the carrying value of our long-term debt under the Alta Mesa RBL to not be materially different from fair value due to short-term variable market rates of interest applicable to our outstanding borrowings. Going Concern We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration the following factors: • During 2018, we incurred a net loss of $2.0 billion , due mainly to impairment of our proved and unproved oil and gas properties. Also, at December 31, 2018, our current liabilities exceeded our current assets by approximately $68.5 million . • Market prices for crude oil declined significantly during the fourth quarter of 2018, closing in the mid- $40 range at the end of 2018. This negatively impacted future estimated prices for oil in 2019 and beyond, which lowers our expected future economic results from our assets. • Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties. • Our drilling costs increased in 2018 as compared to 2017 as a result of increased hydraulic fracturing intensity, installation of dewatering pumps, and the increasing number of stages completed in a lateral. While initially generating positive results, the benefit of these advanced completion techniques began to abate over time indicating limited long-term effect over the course of each well’s life. Our capital expenditures during the Successor Period were considerably higher than during 2017 and 2016. • On April 1, 2019, our borrowing base was reduced to $370.0 million under the Alta Mesa RBL. During April 2019, we drew $70.0 million to consume all of the remaining capacity under the Alta RBL. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient borrowing capacity may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. • We anticipate having difficulty meeting our existing leverage covenants during the next 12 months without relief from our lenders. • We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in June 2019. The 2024 Notes trade substantially below par value. • The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, we were notified by NASDAQ that we are not in compliance with the minimum bid price requirement. Continued trading at these levels may put further pressure on the value of our parent’s common stock and limit our ability to raise additional capital in the equity markets. The above factors raise substantial doubt about our ability to continue as a going concern. To address this, we have: • held discussions with the Alta Mesa RBL lenders about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement, however, we currently expect that such relief would only be available in connection with a reduction in our borrowing capacity which could further hamper our liquidity; • considered seeking new sources of financing at levels consistent with our current and recent secured debt capacity of $370.0 million to $400.0 million , however, such efforts have not reached a stage allowing us to formally seek terms; and • had preliminary discussions with existing capital providers about making additional investments in us but such discussions have not reached a stage of being considered likely or probable of success at this time. In light of the above, we believe substantial unresolved doubt exists regarding our ability to continue as a going concern for the next 12 months. In response, we have continued reporting our long-term debt as noncurrent, since a conclusion regarding going concern has no effect on debt compliance. Recently Issued Accounting Standards Applicable to Us Adopted During the 1st quarter of 2018, we adopted Accounting Standards Update (“ASU”) No. 2017-04, Intangibles - Goodwill and Other, Simplifying the Test for Goodwill Impairment. This new guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Accordingly, any identified impairment of goodwill will be recognized as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. We adopted ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) on December 31, 2018, which clarified how certain transactions are classified in the statement of cash flows. The adoption of this guidance had no material effect. We adopted ASU 2014-09, Revenue from Contacts with Customers , and related amendments, codified as Accounting Standards Codification (“ASC”) 606, on December 31, 2018, retroactive to the beginning of our Successor Period. There was no impact on the timing of recognition of revenue or of our classification of amounts between revenue and operating expenses upon adoption of ASC 606 , however, enhanced disclosure of our revenue recognition policies was required. Not Yet Adopted Leasing Standards In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. We have used a modified retrospective transition approach for existing leases with terms in excess of 12 months entered into prior to January 1, 2019, the date of our adoption. In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. ASU 2018-01 and subsequent applicable ASUs also provide several other optional practical expedients in transition. We elected the “package of practical expedients”, which permits us to forgo reassessment of our prior conclusions about lease identification, lease classification and initial direct costs for leases entered into prior to the effective date, January 1, 2019. We also elected the land easement relief which permits us to forgo reassessment of existing or expired land easements not previously accounted for under ASC 840. Additionally, we elected the practical expedient to not provide comparative reporting periods and therefore financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. By accounting policy, we will not separate non-lease components from lease components. We did not elect the use-of-hindsight practical expedient. We are continuing to assess and finalize all of the effects of adoption, but currently believe the most significant effects relate to (1) recognition of new right-of-use assets and lease liabilities on our balance sheet for our office and equipment operating leases totaling approximately $20.0 million each, effective as of January 1, 2019; and (2) providing significant new disclosures about our leasing activities in our future filings. We are also finalizing the implementation of third-party lease accounting software and completing the design and implementation of our processes and internal controls regarding this new standard. Other Standards In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations. In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We don’t expect the adopt |
Impairment of Assets
Impairment of Assets | 12 Months Ended |
Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Impairment of Assets | IMPAIRMENT OF ASSETS Successor Predecessor (in thousands) February 9, 2018 January 1, 2018 Year Ended Year Ended Impairment of unproved properties $ 742,065 $ — $ — $ 16 Impairment of proved properties 1,291,647 — 1,188 366 Total impairment of assets $ 2,033,712 $ — $ 1,188 $ 382 In late fourth quarter of 2018, the combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations resulted in impairment charges of $2.0 billion to our proved and unproved oil and gas properties. |
Receivables
Receivables | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Receivables | RECEIVABLES Successor Predecessor (in thousands) December 31, 2018 December 31, 2017 Production sales $ 31,532 $ 26,916 Joint interest billings 18,147 13,821 Pooling interest (1) 18,786 35,839 Allowance for doubtful accounts (95 ) (415 ) Total accounts receivable, net $ 68,370 $ 76,161 _________________ (1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents unbilled costs for wells where the option remains pending. Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties. Activity in our allowances for doubtful accounts for trade and related party receivables were as follows: Successor Predecessor (in thousands) February 9, 2018 January 1, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Trade receivables: Balance at beginning of period $ 415 $ 415 $ 490 $ 1,030 Charged to expense 25 — (69 ) 243 Deductions (345 ) — (6 ) (783 ) Balance at end of period $ 95 $ 415 $ 415 $ 490 Related party receivables: Balance at beginning of period $ — $ — $ — $ — Charged to expense (1) 22,438 — — — Deductions — — — — Balance at end of period $ 22,438 $ — $ — $ — _________________ (1) At December 31, 2018, receivables, including notes receivable, from HMI were approximately $23.4 million . Upon receiving payment of approximately $1.0 million dollars in 2019, the balance was reduced to $22.4 million . Because HMI disputes it obligations under the promissory notes with us, we established an allowance for doubtful accounts totaling $22.4 million which is included in general and administrative expense in 2018. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | SUPPLEMENTAL CASH FLOW INFORMATION Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Supplemental cash flow information: Cash paid for interest $ 47,862 $ 1,145 $ 47,773 $ 74,694 Cash paid for state income taxes, net of refunds 4 — — 285 Non-cash investing and financing activities: Increase in asset retirement obligations 5,665 — 4,363 2,719 Asset retirement obligations assumed on purchased properties — — 702 — Increase in accruals or payables for capital expenditures 5,389 4,896 71,995 12,375 Increase in accounts payable to related party for capital expenditures 4,082 — 7,646 — Increase in withholding tax accruals for share-based compensation 535 — — — Distribution of non-STACK assets, net of liabilities — 43,482 — — Contribution of interests in oil and gas properties — — — 65,740 Contribution receivable — — — 7,875 The following table summarizes cash, cash equivalents and restricted cash in the statements of cash flows: Successor Predecessor (in thousands) December 31, 2018 February 8, 2018 December 31, 2017 December 31, 2016 Cash and cash equivalents $ 12,984 $ 9,070 $ 3,660 $ 7,102 Restricted cash 1,001 1,275 1,269 433 Cash from discontinued operations — — 61 83 Total cash, cash equivalents and restricted cash $ 13,985 $ 10,345 $ 4,990 $ 7,618 |
Significant Acquisitions and Di
Significant Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Significant Acquisitions and Divestitures | SIGNIFICANT ACQUISITIONS AND DIVESTITURES 2018 Activity On February 9, 2018 (the “Closing Date”), AMR consummated the transactions contemplated by (i) the Contribution Agreement (“AM Contribution Agreement”), dated August 16, 2017, with us, the AM Contributor, High Mesa Holdings GP, LLC, the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor, (ii) the Contribution Agreement (the “KFM Contribution Agreement”), dated August 16, 2017, with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, and, solely for certain provisions therein, the equity owners of the KFM Contributor; and (iii) the Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”), dated August 17, 2017, with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor” and together with the AM Contributor and the KFM Contributor, the “Contributors”). Pursuant to the Contribution Agreements, SRII Opco, LP, a newly formed subsidiary of AMR (“SRII Opco”) acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in KFM (the “KFM Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions”. We are deemed to be a variable interest entity (“VIE”) and SRII Opco is our primary beneficiary since it controls our general partner, AMH GP, and has the power to direct our activities impacting our performance, as well as holding all of our equity at risk. Accordingly, our results of operations have been consolidated into SRII Opco. Similarly, AMR is the primary beneficiary of SRII Opco and controls SRII Opco, GP, LLC (“SRII Opco GP”), the general partner of SRII Opco. As a result, AMR controls and consolidates SRII Opco, and by extension, us. KFM is considered a related party affiliate. We do not control or have significant influence over KFM as such control resides with SRII Opco’s general partner, SRII Opco GP. As AMR is the primary beneficiary of SRII Opco and controls SRII Opco GP, KFM’s financial results are also included in the consolidated financial statements of our ultimate parent, AMR. Pursuant to the Transactions, AMR contributed $ 554.0 million in net cash to us at the closing of the Business Combination. We used a portion of the amount to repay all outstanding balances under a predecessor senior secured revolving credit facility (the “Alta Mesa Predecessor Credit Facility”). The Business Combination has been accounted for using the acquisition method resulting in our assets acquired and liabilities assumed being recognized at their fair values as of the acquisition date by AMR, which were then pushed down to us. Purchase Price (in thousands) February 9, 2018 (As initially reported) Measurement Period Adjustment (1) February 9, 2018 (As adjusted) Purchase Consideration: (2) SRII Opco Common Units issued (3) $ 1,251,782 $ 9,467 $ 1,261,249 Estimated fair value of contingent earn-out purchase consideration (4) 284,109 — 284,109 Total purchase price consideration $ 1,535,891 $ 9,467 $ 1,545,358 _________________ (1) The measurement period adjustment relates to the issuance of 1,197,934 of additional SRII Opco Common Units, valued at approximately $7.90 per unit, to the AM Contributor based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 (Successor). (2) The purchase price consideration was for 100% of the limited partner interests in us and 100% of the economic interests and 90% of the voting interests in AMH GP. (3) At closing, the Riverstone Contributor received consideration of 20,000,000 SRII Opco Common Units and the AM Contributor received consideration of 138,402,398 SRII Opco Common Units. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity. (4) For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of AMR Class C Common Stock) if the 20-day VWAP of the Class A Common Stock of AMR equals or exceeds the specified prices pursuant to the AM Contribution Agreement. Pursuant to ASC 805 and ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), we have determined that the fair value of the earn-out consideration was approximately $284.1 million , which was classified as equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to AMR (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life. Purchase Price Allocation for Alta Mesa (in thousands) February 9, 2018 (As initially reported) Measurement Period Adjustment (1) February 9, 2018 (As adjusted) Estimated Fair Value of Assets Acquired (2) Cash, cash equivalents and restricted cash $ 10,345 $ — $ 10,345 Accounts receivable 101,745 — 101,745 Other receivables 1,222 840 2,062 Receivables due from related party 907 — 907 Prepaid expenses and other 1,405 — 1,405 Derivatives 352 — 352 Property and equipment: (3) Oil and gas properties, successful efforts 2,314,858 (4,879 ) 2,309,979 Other property and equipment, net 43,318 — 43,318 Notes receivable due from related party 12,454 — 12,454 Deposits and other long-term assets 10,286 — 10,286 Total fair value of assets acquired 2,496,892 (4,039 ) 2,492,853 Estimated Fair Value of Liabilities Assumed (2) Accounts payable and accrued liabilities 210,867 (13,506 ) 197,361 Accounts payable — affiliate 5,476 — 5,476 Advances from non-operators 6,803 — 6,803 Advances from related party 47,506 — 47,506 Asset retirement obligations (3) 5,998 — 5,998 Derivatives 11,585 — 11,585 Long-term debt (4) 667,700 — 667,700 Other long-term liabilities 5,066 — 5,066 Total fair value of liabilities assumed 961,001 (13,506 ) 947,495 Total consideration and fair value $ 1,535,891 $ 9,467 $ 1,545,358 _________________ (1) The measurement period adjustments were recognized in the reporting period in which the adjustments were determined. The measurement period adjustments relate to a change in the purchase consideration based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 and certain adjustments to beginning balances. (2) The assets acquired and liabilities assumed relate to Alta Mesa’s STACK assets. (3) The estimated fair value of oil and gas properties and asset retirement obligations were determined using valuation techniques that convert future cash flows to a single discounted amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). Significant inputs include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discount rates, and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation. Actual results may vary from these estimates. (4) Represents the approximate fair value as of the acquisition date of (i) Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million , based on Level 1 inputs, and (ii) outstanding borrowings under the Alta Mesa Predecessor Credit Facility of approximately $134.1 million as of the acquisition date. Acquisition of acreage In October 2018, we completed a transaction to acquire certain unproved oil and gas properties from Fenter Energy, LLC for $22.3 million , net of customary post-closing purchase price adjustments. The acquisition was funded utilizing borrowings under the Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association (the “Alta Mesa RBL”). 2017 Activity In December 2017, we sold our assets located in the Weeks Island field to Texas Petroleum Investment for approximately $22.5 million . In September 2017, we acquired certain proved oil and gas properties from Brown & Borelli (the “B&B Acquisition”) for $8.2 million , using cash on hand. The fair value of the net assets acquired was approximately $9.9 million . Accordingly, a bargain purchase gain of $1.7 million was recognized at the time of the acquisition. The gain primarily resulted from growth in reserves and value between signing and closing of the transaction. In July 2017, we acquired oil and gas properties in Oklahoma from an unaffiliated third party for $45.6 million , funded utilizing borrowings under Alta Mesa’ Predecessor credit facility. 2016 Activity During 2016, we acquired approximately $10.6 million of oil and gas properties in Oklahoma which were primarily related to unevaluated leasehold. On December 31, 2016, HMI, a related party, purchased from BCE-STACK Development LLC (“BCE”) and contributed interests in 24 producing wells (the “Contributed Wells”) to us. We recorded HMI’s equity contribution at the fair value of the wells contributed of approximately $65.7 million , plus contributed cash of $11.3 million , of which $7.9 million was collected subsequent to December 31, 2016. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property And Equipment | PROPERTY AND EQUIPMENT Successor Predecessor (in thousands) December 31, 2018 December 31, 2017 Oil and gas properties Unproved properties $ 816,282 $ 84,590 Accumulated impairment of unproved properties (742,065 ) — Unproved properties, net 74,217 84,590 Proved oil and gas properties 2,110,346 1,061,105 Accumulated depreciation, depletion, amortization and impairment (1,421,226 ) (251,065 ) Proved oil and gas properties, net 689,120 810,040 Total oil and gas properties, net 763,337 894,630 Other property and equipment Land 5,059 2,912 Fresh water wells 27,366 — Produced water disposal system 3,608 30,990 Office furniture, equipment and vehicles 2,840 20,008 Accumulated depreciation (726 ) (21,770 ) Other property and equipment, net 38,147 32,140 Total property and equipment, net $ 801,484 $ 926,770 Depreciation and Depletion Expense Successor Predecessor (in thousands) February 9, 2018 January 1, 2018 Year Ended Year Ended Oil and gas properties depletion $ 130,439 $ 11,021 $ 83,537 $ 49,481 Other property and equipment depreciation 2,375 609 5,240 4,004 Total depreciation and depletion expense $ 132,814 $ 11,630 $ 88,777 $ 53,485 Sale of Produced Water Assets In November 2018, we sold our produced water assets, consisting of over 200 miles of produced water gathering pipelines and related facilities, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher Midstream, LLC (“KFM”), a related party and an entity under common control by our parent, AMR, for $98.0 million, including approximately $90.0 million in cash transferred during 2018. The remaining balance owed of approximately $8.0 million is included in related party receivables. No gain or loss was recognized as a result of these transactions. In conjunction with the sale, we entered into a new fifteen -year produced water disposal agreement with KFM. Under that agreement, we recognized expense of $4.7 million during November and December of 2018. |
Discontinued Operations (Predec
Discontinued Operations (Predecessor) | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations (Predecessor) | DISCONTINUED OPERATIONS (Predecessor) We distributed our remaining non-STACK oil and gas assets and liabilities to the AM Contributor just prior to the closing of the Business Combination. We have determined that the remaining non-STACK oil and gas assets and liabilities as well as our Weeks Island field sold during the 4th quarter of 2017 are discontinued operations during the Predecessor Periods and have segregated their financial information from ours in the financial statements. Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bore simple interest at 10% . The Founder Notes were part of the non-STACK distribution. The balance of the Founder Notes at the time of conversion was approximately $28.3 million , including accrued interest. Interest on the Founder Notes was $0.1 million, $1.2 million and $ 1.2 million for the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, respectively. Predecessor (in thousands) January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Revenue: Oil $ 1,617 $ 47,218 $ 57,866 Natural gas 1,023 10,090 10,932 Natural gas liquids 236 2,359 1,489 Other 16 316 213 Operating revenue 2,892 59,983 70,500 Loss on sale of assets (1,923 ) (22,207 ) 3,539 Gain on acquisition of oil and gas properties — 1,626 — Total revenue 969 39,402 74,039 Operating expenses: Lease operating 1,770 27,763 29,474 Transportation and marketing 83 1,354 1,698 Production taxes 167 6,730 7,985 Workover 127 2,088 1,273 Exploration — 11,431 7,547 Depreciation, depletion and amortization 884 24,519 41,320 Impairments of assets 5,560 29,129 15,924 General and administrative 21 82 1,290 Total operating expenses 8,612 103,096 106,511 Other income (expense) Interest expense (103 ) (1,209 ) (1,209 ) Interest income and other — 88 10 Total other income (expense) (103 ) (1,121 ) (1,199 ) Income tax provision (benefit) — — (29 ) Loss from discontinued operations, net of state income taxes $ (7,746 ) $ (64,815 ) $ (33,642 ) Predecessor (in thousands) December 31, Assets associated with discontinued operations: Current assets Cash $ 61 Accounts receivable 4,980 Other receivables 154 Total current assets 5,195 Noncurrent assets Investments 9,000 Oil and gas properties, net 33,618 Other long-term assets 1,167 Total noncurrent assets 43,785 Total assets associated with discontinued operations $ 48,980 Liabilities associated with discontinued operations: Current liabilities Accounts payable and accrued liabilities $ 7,882 Asset retirement obligations 7,537 Total current liabilities 15,419 Noncurrent liabilities Asset retirement obligations, net of current portion 37,049 Founder Notes 28,166 Other long-term liabilities 1,647 Total noncurrent liabilities 66,862 Total liabilities associated with discontinued operations $ 82,281 Predecessor (in thousands) January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Total operating cash flows of discontinued operations $ 2,974 $ 21,138 $ 31,255 Total investing cash flows of discontinued operations (601 ) 6,891 (14,378 ) |
Fair Value Disclosures
Fair Value Disclosures | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Disclosures | FAIR VALUE MEASUREMENTS Recurring measurements We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and gas derivatives. Inputs to these models include observable inputs from the NYMEX for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and gas prices. We have classified the inputs used to determine fair values of all our oil, gas and natural gas liquids derivative contracts as Level 2. Non-recurring measurements In connection with the Business Combination, we recorded the fair value of our $500.0 million unsecured senior notes (“the 2024 Notes”) at $ 533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $312.5 million at December 31, 2018, based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. Oil and gas properties are subject to impairment testing and potential impairment based largely on future estimated cash flows determined using Level 3 inputs. Successor Predecessor December 31, 2018 December 31, 2017 (in thousands) Original Carrying Value Estimated Fair Value Impairment Original Carrying Value Estimated Fair Value Impairment Unproved oil and gas properties $ 816,282 $ 74,217 $ 742,065 $ — $ — $ — Proved oil and gas properties 1,895,670 604,023 1,291,647 3,350 2,162 1,188 Total $ 2,711,952 $ 678,240 $ 2,033,712 $ 3,350 $ 2,162 $ 1,188 We estimate the fair value of additions to asset retirement obligations associated with new or acquired properties. Such estimations of fair value are based on present value techniques that utilize company-specific information for inputs such as the cost and timing of plugging and abandonment of wells and facilities. These inputs are classified as Level 3. |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | NOTE 10 — DERIVATIVES We have entered into derivatives to reduce our exposure to price risk for oil and gas. Substantially all of our derivatives are executed by lenders under the Alta Mesa RBL, and are collateralized by the security interests thereunder. The derivatives settle monthly. No derivatives have been entered into for trading or speculative purposes, however none have been designated as hedges under GAAP. From time to time, we may enter into interest rate swap agreements to mitigate the risk of changes in interest rates, but as of December 31, 2018, we have none. The following summarizes the fair value and classification of our derivatives: December 31, 2018 (Successor) Balance sheet location Gross fair value of assets Gross liabilities offset against assets in the Balance Sheet Net fair value of assets presented in the Balance Sheet (in thousands) Derivatives, current assets $ 22,512 $ (6,089 ) $ 16,423 Derivatives, long-term assets 7,910 (4,963 ) 2,947 Total $ 30,422 $ (11,052 ) $ 19,370 Balance sheet location Gross fair value of liabilities Gross assets offset against liabilities in the Balance Sheet Net fair value of liabilities presented in the Balance Sheet (in thousands) Derivatives, current liabilities $ 7,799 $ (6,089 ) $ 1,710 Derivatives, long-term liabilities 5,143 (4,963 ) 180 Total $ 12,942 $ (11,052 ) $ 1,890 December 31, 2017 (Predecessor) Balance sheet location Gross fair value of assets Gross liabilities offset against assets in the Balance Sheet Net fair value of assets presented in the Balance Sheet (in thousands) Derivatives, current assets $ 1,406 $ (1,190 ) $ 216 Derivatives, long-term assets 3,010 (3,002 ) 8 Total $ 4,416 $ (4,192 ) $ 224 Balance sheet location Gross fair value of liabilities Gross assets offset against liabilities in the Balance Sheet Net fair value of liabilities presented in the Balance Sheet (in thousands) Derivatives, current liabilities $ 20,493 $ (1,190 ) $ 19,303 Derivatives, long-term liabilities 4,116 (3,002 ) 1,114 Total $ 24,609 $ (4,192 ) $ 20,417 The following table summarizes the effect of our derivatives in the statements of operations (in thousands): Successor Predecessor February 9, 2018 January 1, 2018 Derivatives not Through Through Year Ended Year Ended designated as hedges December 31, 2018 February 8, 2018 December 31, 2017 December 31, 2016 Gain (loss) on derivatives - Oil commodity contracts $ (3,559 ) $ 4,796 $ 1,450 $ (36,572 ) Natural gas commodity contracts (6,688 ) 1,867 7,288 (2,410 ) Natural gas liquids commodity contracts — — (451 ) (1,478 ) Total gain (loss) on derivatives $ (10,247 ) $ 6,663 $ 8,287 $ (40,460 ) Other receivables at December 31, 2018 and 2017 include $1.3 million and $1.4 million , respectively, of derivative positions covering the month of December scheduled to be settled in January of the succeeding year. We periodically monitor the creditworthiness of our counterparties. Although our counterparties provide no collateral, the agreements with each counterparty allow us to set-off unpaid amounts against the outstanding balance under the Alta Mesa RBL. We had the following call and put derivatives at December 31, 2018 : OIL Volume Weighted Range Settlement Period and Type of Contract in bbls Average High Low 2019 Price Swap Contracts 182,500 $ 63.03 $ 63.03 $ 63.03 Collar Contracts Short Call Options 2,701,000 66.31 75.20 56.50 Long Put Options 2,883,500 53.80 62.00 50.00 Short Put Options 2,883,500 42.72 52.00 37.50 2020 Collar Contracts Short Call Options 585,600 64.32 73.80 59.55 Long Put Options 1,537,200 55.54 62.50 50.00 Short Put Options 1,537,200 44.64 50.00 37.50 GAS Volume in Weighted Range Settlement Period and Type of Contract MMBtu Average High Low 2019 Price Swap Contracts 10,905,000 $ 2.69 $ 3.09 $ 2.64 Collar Contracts Short Call Options 4,000,000 3.31 3.75 3.17 Long Put Options 3,550,000 2.81 2.90 2.70 Short Put Options 2,425,000 2.27 2.40 2.20 2020 Collar Contracts Short Call Options 2,275,000 3.19 3.20 3.17 Long Put Options 9,150,000 2.57 2.70 2.50 Short Put Options 9,150,000 2.07 2.20 2.00 2021 Collar Contracts Long Put Options 2,250,000 2.65 2.65 2.65 Short Put Options 2,250,000 2.15 2.15 2.15 In those instances where contracts are identical as to time period, counterparty, volume and strike price, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either the NYMEX index or may reflect a mix of positions settling on various combinations of these benchmarks. We had the following basis swaps at December 31, 2018 : Total Gas Volumes in MMBtu over Remaining Term (1) Reference Price 1 (1) Reference Price 2 (1) Period Weighted Average Spread ($ per MMBtu) 460,000 OneOK NYMEX Henry Hub Jul '19 — Dec '19 $ (0.93 ) 17,950,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '19 — Dec '19 (0.68 ) 910,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '20 — Mar '20 (0.49 ) 2,365,000 San Juan NYMEX Henry Hub Jan '19 — Oct '19 (0.78 ) ________________ (1) Represents short swaps that fix the basis differentials between OneOK, T ex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS Predecessor (in thousands) 2018 2017 Balance, as of January 1 (Predecessor) $ 10,469 $ 8,400 Liabilities settled (63 ) Revisions to estimates 63 Accretion expense 39 Balance, as of February (Predecessor) $ 10,508 Balance, beginning of year (Successor) (1) $ 5,998 — Liabilities assumed — 604 Liabilities incurred 2,536 1,583 Liabilities settled (1,610 ) (119 ) Liabilities transferred via sale (383 ) — Revisions to estimates 4,130 (337 ) Accretion expense 738 338 Balance, as of December 31 11,409 10,469 Less: Current portion 2,079 69 Long-term portion $ 9,330 $ 10,400 _________________ (1) Represents the same wells under the Predecessor Period valued at a higher interest rate of 10.2% compared to interest rates ranging between 4.4% and 8.8% . |
Long Term Debt, Net
Long Term Debt, Net | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long Term Debt, Net And Notes Payable To Founder | NOTE 12 — LONG TERM DEBT, NET Successor Predecessor (in thousands) December 31, 2018 December 31, 2017 Alta Mesa RBL $ 161,000 $ — Alta Mesa Predecessor Credit Facility — 117,065 2024 Notes 500,000 500,000 Unamortized premium on 2024 notes 29,123 — Unamortized deferred financing costs — (9,625 ) Total long-term debt, net $ 690,123 $ 607,440 Alta Mesa RBL In connection with the Business Combination, we entered into the Alta Mesa RBL which features a face amount of $ 1.0 billion and had an initial $ 350.0 million borrowing base. In April 2018, the borrowing base was increased to $ 400.0 million, which was reaffirmed by the lenders during the fourth quarter of 2018. Drawing on the Alta Mesa RBL requires us to be in compliance with the covenants on a current and pro forma basis. As of December 31, 2018 , in addition to $161.0 million of borrowings outstanding, we also had $ 21.9 million of outstanding letters of credit, leaving a total borrowing capacity of $ 217.1 million available for future use at that time. On April 1, 2019, the borrowing base was reduced to $370.0 million upon completion of the regularly scheduled semiannual redetermination. The facility matures in February 2023 and is subject to semiannual redeterminations. We may borrow in Eurodollars or at a reference rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a margin ranging from 2.00% to 3.00% . Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s prime rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00% , plus a margin ranging from 1.00% to 2.00% . The amounts outstanding are secured by first priority liens on substantially all of our upstream oil and gas properties and all of the equity of our material guarantor subsidiaries. Additionally, SRII Opco and Alta Mesa GP have pledged their respective partner interests in us as security. Restrictive covenants may limit our ability to incur additional indebtedness, sell assets, guarantee or make loans to others, make investments, enter into mergers, make certain payments and distributions in excess of specific amounts, enter into or be party to hedge agreements, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Alta Mesa RBL has two covenants that are tested quarterly according to the definitions and provisions thereunder: • a ratio of our current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and • a ratio of our consolidated debt to our consolidated EBITDAX of not greater than 4.0 to 1.0 . Through December 31, 2018 we were able to annualize cumulative Successor Period results in measuring EBITDAX. We are currently in default under the Alta Mesa RBL for our failure to provide certain information by May 15, 2019 for the fiscal quarter ended March 31, 2019. The default can be cured by providing the information by June 14, 2019. Predecessor Credit Facility As of December 31, 2017 , we had $117.1 million of borrowings outstanding, which were paid in full at the time of the Business Combination. 2024 Notes Our 2024 Notes have a face value of $500.0 million and bear interest at 7.875% per annum. The 2024 Notes were issued at par during the 4th quarter of 2016 in a private placement but were exchanged for substantially identical registered senior notes in November 2017. The 2024 Notes mature in December 2024 with interest payable semi-annually on June 15 and December 15 . Before December 2019, we may redeem up to 35% of the 2024 Notes using proceeds from equity offerings at a redemption price of 107.875% of principal under specified conditions. Before December 2019, we otherwise may redeem the 2024 Notes at their principal amount plus an applicable make-whole premium. On and after December 15, 2019, we may redeem the 2024 Notes, in whole or in part, at the following redemption prices plus accrued and unpaid interest, if any, to the date of redemption: After December 15 2019 2020 2021 2022 Redemption price as a percentage of principal amount 105.906 % 103.938 % 101.969 % 100 % The 2024 Notes are guaranteed by each of our subsidiaries and rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future subordinated indebtedness; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Alta Mesa RBL; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the 2024 Notes. The 2024 Notes contain certain covenants limiting our ability to prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on our assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business. Upon certain changes of control, the terms of the notes may require us to redeem them at 101% of the principal amount. The Business Combination did not constitute a change in control for the 2024 Notes. If an event of default occurs, all outstanding amounts may become due and payable. Bond Premium The fair value of the 2024 Notes as of the Business Combination was $ 533.6 million yielding a bond premium of $ 33.6 million Amortization of the premium reduced our interest expense by $ 4.5 million during the Successor Period. Maturities of Long-Term Debt (Successor) Fiscal Year (in thousands) 2019 $ — 2020 — 2021 — 2022 — 2023 161,000 Thereafter 500,000 $ 661,000 Deferred Financing Costs As of December 31, 2017 , we had $ 11.4 million of deferred financing costs related to both the 2024 Notes and the Predecessor Credit Facility. Pursuant to the Business Combination, the unamortized deferred financing costs were adjusted to a fair value of zero . During the Successor Period, we incurred additional deferred financing costs related to the Alta Mesa RBL of $ 1.4 million. For the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, the amortization of deferred financing costs was $0.2 million , $0.2 million , $2.7 million , and $3.9 million , respectively. |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Payables and Accruals [Abstract] | |
Accounts Payable And Accrued Liabilities | ACCOUNTS PAYABLE AND ACCRUED LIABILITIES Successor Predecessor (in thousands) December 31, December 31, Accounts payable $ 20,200 $ 68,578 Accruals for capital expenditures 101,214 48,771 Revenue and royalties payable 46,870 29,514 Accruals for operating expenses 16,355 14,632 Accrued interest 1,784 2,587 Derivative settlements 109 2,106 Other 10,532 4,301 Total accrued liabilities 176,864 101,911 Accounts payable and accrued liabilities $ 197,064 $ 170,489 |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments And Contingencies | COMMITMENTS AND CONTINGENCIES Commitments Office and Equipment Leases We lease office space and certain field equipment under long-term operating lease agreements. For the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 , and 2016 , total net lease payments, was approximately $7.8 million , $0.1 million , $7.8 million , and $3.6 million , respectively. At December 31, 2018 , we have the remaining future minimum lease payments : Fiscal Year In thousands 2019 $ 2,819 2020 2,851 2021 2,911 2022 3,107 2023 3,038 Thereafter 12,219 $ 26,945 Gas Processing Reservation Commitment We entered into an agreement with KFM to reimburse half of the expenses associated with any shortfall in committed volumes not physically delivered. The amounts below represent the total maximum cash payment required if KFM does not deliver to a third party for processing. This commitment extends through 2021 with the following commitments at December 31, 2018 : Fiscal Year In thousands 2019 $ 1,551 2020 1,556 2021 1,551 $ 4,658 During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million . Firm Natural Gas Transportation Commitments We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of our natural gas that extend through 2028 with the following commitments at December 31, 2018 : Fiscal Year In thousands 2019 $ 12,236 2020 12,236 2021 12,236 2022 12,236 2023 12,236 Thereafter 25,023 $ 86,203 Contingencies Environmental claims Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa’s subsidiaries have, or historically had, operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from its oil and gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our consolidated financial statements at December 31, 2018. Title/lease disputes Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made. Litigation On January 30, 2019, AMR, James T. Hackett, AMR’s interim Chief Executive Officer and Chairman of the Board, certain of AMR’s former and current directors, Thomas J. Walker, AMR’s former Chief Financial Officer, and Riverstone Investment Group LLC were named as defendants in a putative securities class action filed in the United States District Court for the Southern District of New York (“SDNY Complaint”). The plaintiff, Plumbers and Pipefitters National Pension Fund, alleges that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination and, therefore, violated Section 14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 14-9 promulgated thereunder. In addition, the plaintiff alleges that Riverstone and the individual defendants violated Section 20(a) of the Exchange Act. The plaintiff is seeking compensatory and/or rescissory damages against the defendants. On March 14 and 19, 2019, two additional putative securities class action complaints were filed in the U.S. District Court for the Southern District of Texas (“SDTX Complaints”) against the same defendants named in the SDNY Complaint, and Harlan H. Chappelle and Michael A. McCabe, AMR’s former President and Chief Executive Officer and Chief Financial Officer, respectively. These complaints are the same claims asserted in the initial complaint, but also add claims under Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder against AMR and certain of its current and former officers on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017, and February 25, 2019. The new claims are based upon alleged misstatements contained in AMR’s proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants. The outcome of the above securities class action complaints is uncertain, and while we believe that AMR has valid defenses to the plaintiff’s claims and intend to defend the lawsuits vigorously, no assurance can be given as to the outcome of the lawsuits. We are not a party to these suits but an adverse outcome could potentially impact our business. On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. In August 2017, Biloxi Marsh Lands (“Biloxi”) filed suit in the 34th District Court for the Parish of St. Bernard, Louisiana, against Meridian Resource & Exploration LLC (a subsidiary of HMI), us, and other defendants. Biloxi alleges negligent construction, installation, maintenance, use and operation of a pipeline. In lieu of litigating corporate structure allegations and to reduce potential litigation expenses, we stipulated with respect to Biloxi that we would be bound by and assume liability and responsibility for any unpaid debts, obligations or final judgments that may be entered against Meridian in favor of Biloxi in this matter. However, these allegations relate to non-STACK oil and gas assets that we distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by us or Meridian as a result of these allegations are the responsibility of HMI. There is no guarantee that HMI will pay any settlement amounts or judgments rendered against us or Meridian. In addition, our ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI. SEC Investigation The SEC is conducting a formal investigation into, among other things, the facts involved in the material weakness in our internal controls over financial reporting and the impairment charge disclosed previously and in this annual report. We are cooperating with this investigation. At this point we are unable to predict the timing or outcome of this investigation. If the SEC determines that violations of the federal securities laws have occurred, the agency has a broad range of civil penalties and other remedies available, some of which, if imposed on us, could be material to our business, financial condition or results of operations. Other contingencies We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated; however, in our opinion, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. Performance appreciation rights Our Predecessor had a plan that was intended to provide incentive compensation to key employees and consultants. We canceled all remaining amounts due under the plan at the time of the Business Combination, but recognized and paid $10.9 million as strategic costs in G&A during the Successor Period. |
Significant Concentrations
Significant Concentrations | 12 Months Ended |
Dec. 31, 2018 | |
Significant Concentrations [Abstract] | |
Significant Concentrations | SIGNIFICANT CONCENTRATIONS We have an agreement with ARM pursuant to which they market our oil, gas and NGLs. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. ARM collects payments from purchasers, deducts their fee and remits the balance to us. In addition, ARM markets our firm transportation on the ONEOK Gas Transportation, L.L.C. system and the Panhandle Eastern Pipeline Company, LP system for a management fee. The AM Contributor owns 10% of ARM. During the Successor Period, we paid ARM $ 1.4 million for our share of the marketing fees. Receivables from ARM for sales on our behalf were $38.4 million and $22.4 million as of December 31, 2018 and 2017 , respectively. During the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016, sales managed by ARM on our behalf were $ 309.7 million, $28.8 million, $ 199.2 million and $ 114.8 million, respectively. Additionally, ARM provides us with strategic advice, execution and reporting services with respect to our derivatives activities. Fees paid to ARM for these services were $0.8 million, $0.1 million, $0.8 million and $1.9 million during the Successor Period, 2018 Predecessor Period, 2017 and 2016, respectively. We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers are readily available. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS AMR sponsors a 401(k) savings plan, whereby our employees can elect to make contributions pursuant to a salary reduction agreement. We make matching contributions equal to 100% of the first 5% of an employee’s contributions. Employee contributions are immediately vested whereas company matching contributions vest 50% after two years and become fully vested at the end of three years. Matching contributions to the plan were approximately $ 1.0 million, $0.3 million , $1.2 million , and $1.1 million for the Successor Period, the 2018 Predecessor Period, 2017 and 2016 , respectively. |
Significant Risks And Uncertain
Significant Risks And Uncertainties | 12 Months Ended |
Dec. 31, 2018 | |
Risks and Uncertainties [Abstract] | |
Significant Risks And Uncertainties | SIGNIFICANT RISKS AND UNCERTAINTIES Our business makes us vulnerable to changes in wellhead prices of oil and gas. Historically, world-wide oil and gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, spot and future estimated commodity prices declined sharply during the fourth quarter of 2018. Prices for oil and gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and gas, as well as market uncertainty, economic conditions and a variety of additional factors. The duration and magnitude of changes in oil and gas prices cannot be predicted. Sustained low oil or gas prices may require us to further write down the value of our oil and gas properties and/or revise our development plans, which may cause certain undeveloped well locations to be less valuable. This could cause a reduction in the borrowing base under our credit facilities to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into derivatives. |
Partners' Capital
Partners' Capital | 12 Months Ended |
Dec. 31, 2018 | |
Partners' Capital [Abstract] | |
Partners' Capital | PARTNERS’ CAPITAL Partnership Management and Control Our amended and restated partnership agreement provides for interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by Alta Mesa GP referred to as “GP Units”. Alta Mesa GP owns all the GP Units and SRII Opco owns all the LP Units. Since we are a limited partnership, our operations and activities are managed by the board of directors of Alta Mesa GP. The limited liability company agreement of Alta Mesa GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic rights in Alta Mesa GP and (ii) Class B Units which hold 100% of the voting interests in Alta Mesa GP. SRII Opco is the sole owner of Alta Mesa GP’s Class A Units and owns 90% of the Class B Units. Our former President and Chief Executive Officer and our former Chief Operating Officer—Upstream, along with certain affiliates of Bayou City, and HPS Investment Partners, LLC (“HPS”), own an aggregate 10% of the Class B Units. AMH GP’s board of directors are selected by the Class B members. Notwithstanding the foregoing, voting control of AMH GP is vested in SRII Opco pursuant to a voting agreement. |
Equity-Based Compensation (Succ
Equity-Based Compensation (Successor) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-Based Compensation (Successor) | EQUITY-BASED COMPENSATION (Successor) Certain of our employees are eligible to participate in the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”). A total of 50,000,000 shares of AMR’s Class A Common Stock are reserved for issuance under the LTIP. The LTIP provides for the grant of stock awards, including incentive stock options (“ISOs”), nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other awards in AMR’s Class A Common Stock. Prior to the Business Combination, we had no equity-based compensation programs. During the Successor Period, the Company recognized stock-based compensation expense of $20.0 million in general and administrative expense including accelerated vesting for separated executives related to the LTIP. Stock options Stock options expire seven years from the grant date and generally vest in one-third increments each year, based on continued employment. Employees have 90 days after termination to exercise vested stock options, unless extended by an employment agreement. Successor Stock Options Weighted Average Exercise Price Weighted Average Grant-Date Fair Value Weighted Average Remaining Term (Years) Aggregate Intrinsic Value (in thousands) Outstanding as of February 9, 2018 — $ — $ — — $ — Granted 4,840,799 8.90 4.37 — — Exercised — — — — — Forfeited or expired (134,956 ) 9.37 4.55 — — Outstanding as of December 31, 2018 4,705,843 8.89 4.36 5.2 — Vested at December 31, 2018 or expected to vest in future 4,705,843 8.89 4.36 5.2 — Exercisable as of December 31, 2018 1,509,434 $ 9.54 $ 4.62 3.0 $ — The following assumptions were used to determine the fair value of the 2018 option grants: Successor February 9, 2018 Expected term (in years) 4.5 Expected stock volatility 64.6 % Dividend yield — Risk-free interest rate 2.5 % Unrecognized compensation cost related to non-vested stock options at December 31, 2018 was $9.8 million , which we expect to recognize over a weighted average remaining period of 2.2 years. Restricted stock Restricted stock granted to employees generally vests in one-third increments each year based on continued employment. Prior to vesting, unvested restricted stock may not be traded. The following table provides information about restricted stock awards granted during the Successor Period: Successor Restricted Stock Awards Weighted Average Grant Date Fair Value per share Outstanding as of February 9, 2018 — $ — Granted 1,720,949 7.61 Vested (1) (286,214 ) 8.38 Forfeited or expired (59,980 ) 8.80 Outstanding as of December 31, 2018 1,374,755 $ 7.39 _________________ (1) To satisfy minimum tax withholding, 94,576 shares were withheld. Unrecognized compensation cost related to unvested restricted shares at December 31, 2018 was $ 7.3 million, which we expect to recognize over a weighted average remaining period of 2.2 years. Restricted stock units Employees were also granted performance-based restricted stock units (“PSUs”) under the LTIP. PSUs granted in 2018 generally vest over three years at 20% during the first year, 30% during the second year and 50% during the third year. The number of PSUs vesting each year will be based on the achievement of annual company-specified performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that vest can range from 0% to 200% of the target grant applicable to each vesting period. We only recognize expense for PSUs when the specified performance thresholds for future periods have been established. For PSUs granted during the Successor Period only the performance goals and objectives for 2018 had been established as of December 31, 2018 . Those 2018 performance goals were not attained, and the 2018 award tranche was forfeited, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted. No amounts will be recognized for the 2019 and 2020 performance periods until the specific targets have been established and probability of attainment can be measured. The following summary provides information about the target number of PSUs granted during the Successor Period: Successor Restricted Stock Units Weighted Average Grant - Date Fair Value per unit Outstanding as of February 9, 2018 — $ — Granted 2,049,105 3.99 Vested (1) (1,559,749 ) 2.53 Forfeited or expired (489,356 ) (8.61 ) Outstanding as of December 31, 2018 — — $ — _________________ (1) To satisfy minimum tax withholding, 388,655 shares were withheld. As of December 31, 2018 , there was no unrecognized compensation cost related to unvested PSUs. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | NOTE 20 — RELATED PARTY TRANSACTIONS On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM. The Gas Gathering and Processing Agreement was subsequently amended in February 2017, effective December 2016 and again in June 2018, effective April 2018. The more recent amendment to the Gas Gathering and Processing Agreement impacts our ability to make elections with respect to the NGL portion of our production volumes but has no other effect on our consolidated financial statements. In November 2018, we sold our produced water assets, consisting of over 200 miles of produced water gathering pipelines and related facilities, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher, a related party and an entity under common control by our parent, AMR, for $98.0 million, including approximately $90.0 million in cash transferred during 2018. The remaining balance owed of approximately $8.0 million is included in related party receivables. In conjunction with the sale, we entered into a new fifteen -year produced water disposal agreement with KFM. Under that agreement, we recognized expense of $4.7 million during November and December of 2018. On September 21, 2016, we entered into an agreement with Kingfisher that beginning January 1, 2017 through January 31, 2022, we shall reimburse Kingfisher for 50% of any shortfall fee paid by Kingfisher to Superior Pipeline Company, LLC, a third party gas processor. During the period February 9, 2018 through December 31, 2018, cash payments required under our commitments totaled approximately $0.1 million . David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David -Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $ 166,000 , $ 28,000 , $186,000 and $146,000 for the Successor Period, the 2018 Predecessor Period and the years ended December 31, 2017 and 2016 , respectively. Following termination of the contract, Brigid Murrell continued to provide services to the Company as an individual contractor and was paid $8,523 for services rendered in that capacity through December 31, 2018 . These amounts are recorded in general and administrative expenses. David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of approximately $1,157,774 , $28,874 , $250,000 , and $425,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively. These amounts are included in general and administrative expense. David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of approximately $297,134 , $67,322 , $150,000 , and $180,000 for the Successor Period, the 2018 Predecessor Period, and the years ended December 31, 2017 and 2016, respectively. These amounts are included in general and administrative expense. Bayou City Agreement In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of our STACK acreage. The JDA establishes a development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells. Pursuant to the terms and provisions of the JDA, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $ 3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for carrying the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return on each individual tranche. Following the completion of each joint well, Alta Mesa and BCE will each bear its respective proportionate working interest share of all subsequent costs and expenses related to such joint well. Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the 2018 Predecessor Period , BCE advanced us approximately $39.5 million to drill wells under the JDA. As of December 31, 2018 , 61 joint wells have been drilled or spudded. As of December 31, 2018 and 2017 , $9.8 million and $ 23.4 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our consolidated balance sheets. At December 31, 2018 , there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. High Mesa In September 2017, we entered into a $ 1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured in February 2019. At December 31, 2018 and 2017 , amounts due under the promissory note totaled $ 1.7 million and $ 1.5 million, respectively. HMS defaulted under the terms of that promissory note when it was not paid when due on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owing under the note immediately due and payable. We also have an $ 8.5 million promissory note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. As of December 31, 2018 and 2017 , the note receivable amounted to $ 11.7 million and $ 10.8 million, respectively. HMI disputes its obligations under the $ 1.5 million note and $ 8.5 million note referenced above as payable to us. We oppose HMI’s claims and believe HMI’s obligation under the notes to be our valid assets and that the full amount is payable to us. We intend to pursue all available remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. As a result of the potential conflict of interest of certain directors of AMR who are also controlling holders and directors of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, 2018 , we established an allowance for doubtful accounts for the promissory notes totaling $13.4 million , the expense for which is included in general and administrative expense in 2018. Interest income on the promissory notes amounted to approximately $ 0.9 million, $ 0.1 million, $ 0.9 million, and $ 0.8 million for the Successor Period, the 2018 Predecessor Period , and the years ended December 31, 2017 and 2016, respectively, all recorded as paid-in-kind and added to the balance due thereunder. In connection with the Business Combination, we distributed our non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Under the High Mesa Agreement, during the 180 -day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180 -day periods (each a “Renewal Term”), unless terminated by either party upon at least 90 -days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $ 10,000 , (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services. Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the High Mesa Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from Alta Mesa to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the High Mesa Agreement, and pursuant to the High Mesa Agreement as “Receivables due from related party” in the balance sheets. As of December 31, 2018 (Successor) and December 31, 2017 (Predecessor), we had receivables of approximately $ 10 million and $ 0.8 million for costs and expenses incurred on HMI’s behalf. Subsequent to year-end, we billed HMI $0.9 million for incremental MSA costs incurred and have received approximately $1.0 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result, we have recognized an allowance for uncollectible accounts of $9.0 million to fully provide for the unremitted balance and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities. |
Subsidiary Guarantors
Subsidiary Guarantors | 12 Months Ended |
Dec. 31, 2018 | |
Guarantees [Abstract] | |
Subsidiary Guarantors | SUBSIDIARY GUARANTORS All of our wholly owned subsidiaries are guarantors under the terms of our 2024 Notes and the RBL. The guarantees are full and unconditional (except for customary release provisions) and are joint and several. Our consolidated financial statements reflect the financial position of these subsidiary guarantors. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS We implemented a reduction in force in 2019 that will cause us to incur approximately $4.7 million of expense in the first quarter and approximately $1.2 million of expense in the second quarter. This action also resulted in a partial termination of AMR’s 401(k) savings plan, which will accelerate vesting for those employees that were impacted by the reduction in force to the extent they were not already vested in our matching contributions. |
Supplemental Quarterly Informat
Supplemental Quarterly Information | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Supplemental Quarterly Information | SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited) Predecessor Successor 2018 (in thousands) January 1, 2018 Through February 8, 2018 February 9, 2018 Through March 31, 2018 June 30 Sept 30 Dec 31 Total revenue $ 47,639 $ 34,090 $ 66,459 $ 122,873 $ 185,589 Income (loss) from continuing operations (1)(2)(3) (7,116 ) (34,571 ) (22,477 ) 17,844 (2,037,170 ) Income (loss) from discontinued operations (7,746 ) — — — — Net income (loss) (1)(2)(3) (14,862 ) (34,571 ) (22,477 ) 17,844 (2,037,170 ) _________________ (1) Includes $2.0 billion of impairment expense during the quarter ended December 31, 2018. (2) Includes $6.7 million and $52.8 million of gains on derivatives during the 2018 Predecessor Period and the quarter ended December 31, 2018, respectively. Includes $22.6 million , $29.2 million and $11.2 million of losses on derivatives during the period from February 9, 2018 through March 31, 2018, and during the quarters ended June 30, 2018 and September 30, 2018, respectively. (3) Includes $6.0 million gain primarily from the sale of seismic data during the period from February 9, 2018 through March 31, 2018. Predecessor 2017 (in thousands) March 31 June 30 Sept 30 Dec 31 Total revenue (1)(2) $ 95,079 $ 79,800 $ 57,923 $ 46,567 Income (loss) from continuing operations (1)(2)(3) 29,430 15,620 (22,163 ) (35,733 ) Loss from discontinued operations (4) (4,515 ) (30,934 ) (2,041 ) (27,325 ) Net income (loss) 24,915 (15,314 ) (24,204 ) (63,058 ) _________________ (1) Includes $30.2 million and $18.3 million of gains on derivatives during quarters ended March 31, 2017 and June 30, 2017, respectively, and $10.5 million and $29.7 million of losses on derivatives during the quarters ended September 30, 2017 and December 31, 2017, respectively. (2) Includes $5.3 million gain on acquisition of oil and gas properties during the quarter ended September 30, 2017, which was reduced by $3.6 million during the quarter ended December 31, 2017. (3) Includes $1.2 million of impairment expense during the quarter ended March 31, 2017. (4) The quarter ended December 31, 2017 includes a loss on the sale of assets of $22.2 million, primarily associated with the sale of Weeks Island. |
Supplemental Oil And Natural Ga
Supplemental Oil And Natural Gas Disclosures | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Oil and Natural Gas Disclosures [Abstract] | |
Supplemental Oil And Natural Gas Disclosures | NOTE 24 — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) During January 2019, we finalized our development plan for the next five years and received an audit report from our outside engineers that agreed with our recognition of PUDs for the majority of that future development. During April 2019, in finalizing our financial reporting for 2018, we determined that we may fail to satisfy the leverage covenant under the Alta Mesa RBL during 2019. Accordingly, we were unable to conclude that we would have continuing access to that capital source in the event of a failure of the leverage covenant. Thus, we concluded that we did not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our future drilling locations and did not recognize any proved undeveloped locations in our final December 31, 2018 reserve report. Should our ability to fund the required development costs improve in the future, we expect to recognize all or a portion of those resources as proved. The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235. The information presented during the Predecessor Periods includes amounts related to discontinued operations. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Under our gathering contract with KFM, we have options regarding how we accept or reject ethane volumes. Our reserve disclosures that follow assume that we recover (rather than reject) ethane volumes, which generally has the effect of increasing the reserves, with no corresponding increase to value or future cash flow. Reserve estimates incorporate assumptions regarding future prices and costs at the date estimates are made. Actual future prices and costs may be materially higher or lower. Actual future net revenue will also be affected by factors such as actual production, supply and demand for oil and gas, curtailments or increases in consumption by gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. Oil and gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States. Estimated Quantities of Proved Reserves The following table sets forth our net proved reserves as of the Successor Period, the 2018 Predecessor Period, the years ended December 31, 2017 and 2016 , and the changes therein during the periods then ended. Proved oil and gas reserves are the estimated quantities of crude oil, gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the dates the estimates were made). Oil (Mbbls) Gas (MMcf) NGL’s (Mbbls) Boe (Mbbls) Total Proved Reserves: Balance at December 31, 2015 (Predecessor) 34,142 155,423 18,437 78,483 Production (4,001 ) (13,959 ) (956 ) (7,284 ) Purchases in place (1) 1,508 6,754 613 3,247 Discoveries and extensions 29,903 154,653 14,000 69,679 Sales of reserves in place (73 ) (966 ) (10 ) (244 ) Revisions of previous quantity estimates and other (3,680 ) 14,100 (3,794 ) (5,124 ) Balance at December 31, 2016 (Predecessor) 57,799 316,005 28,290 138,757 Production (4,850 ) (18,218 ) (1,387 ) (9,274 ) Purchases in place 725 4,860 401 1,936 Discoveries and extensions 20,135 108,676 9,640 47,888 Sales of reserves in place (3,622 ) (1,280 ) — (3,836 ) Revisions of previous quantity estimates and other 3,331 23,476 (57 ) 7,187 Balance at December 31, 2017 (Predecessor) 73,518 433,519 36,887 182,658 Production (521 ) (1,984 ) (161 ) (1,012 ) Purchases in place — — — — Discoveries and extensions — — — — Sales of reserves in place (2) (1,667 ) (24,239 ) (771 ) (6,478 ) Revisions of previous quantity estimates and other 375 3,506 289 1,248 Balance at February 8, 2018 (Predecessor) 71,705 410,802 36,244 176,416 Production (5,053 ) (16,913 ) (2,268 ) (10,140 ) Purchases in place (3) 2,658 13,331 1,751 6,631 Discoveries and extensions (3) 30,026 155,306 19,646 75,557 Sales of reserves in place — — — — Revisions of previous quantity estimates and other (3)(4) (74,064 ) (418,378 ) (35,581 ) (179,375 ) Balance at December 31, 2018 (Successor) 25,272 144,148 19,792 69,089 Proved Developed Reserves: Balance at December 31, 2015 14,942 71,752 6,958 33,859 Balance at December 31, 2016 16,832 93,361 7,977 40,371 Balance at December 31, 2017 20,347 150,183 12,180 57,557 Balance at February 8, 2018 19,345 126,231 11,348 51,731 Balance at December 31, 2018 25,272 144,148 19,792 69,089 Proved Undeveloped Reserves: Balance at December 31, 2015 19,200 83,671 11,479 44,624 Balance at December 31, 2016 40,967 222,644 20,313 98,386 Balance at December 31, 2017 53,171 283,336 24,707 125,101 Balance at February 8, 2018 52,360 284,571 24,896 124,685 Balance at December 31, 2018 — — — — _________________ (1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from HMI. (2) Sales of reserves in place during the 2018 Predecessor Period represent amounts related to our non-STACK properties that were distributed to the AM contributor and are classified as discontinued operations in our consolidated financial statements. (3) Effective as of December 31, 2018 , due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves, we have removed all of our PUDs from our total estimated proved reserves. Discoveries and extensions and purchases in place during the 2018 Successor Period include approximately 47,092 MBoe in PUDs, and this amount is also included with our negative revisions and is consequently removed from our total proved reserves at December 31, 2018 . (4) In addition to removing PUDs, we lowered our estimate of proved reserves at December 31, 2018 by approximately 101,516 MBoe, largely due to results of the 2018 drilling program demonstrating lower estimated recovery per 640 -acre section. Partially offsetting this was an increase in recoverable reserves of approximately 11,196 MBoe, due mainly to higher average commodity prices in 2018 as compared to 2017. Results of Operations for Oil and Gas Producing Activities Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Operating revenue $ 414,507 $ 40,136 $ 269,386 $ 142,356 Production expense (1) 247,748 30,743 138,833 87,869 Depreciation, depletion and amortization 133,554 11,670 89,115 53,755 Exploration expense 34,085 7,003 13,563 17,230 Impairment expense 2,033,712 — 1,188 382 Income tax expense (benefit) 4 — 6 — Results of operations $ (2,034,596 ) $ (9,280 ) $ 26,681 $ (16,880 ) ________________ (1) Production expense consists of direct lease operating expense, transportation and marketing expense, production taxes, workover expense and general and administrative expense. Capitalized Costs Relating to Oil and Gas Producing Activities December 31, (in thousands) Successor 2018 Predecessor 2017 (1) Capitalized costs: Proved properties $ 2,110,346 $ 1,545,963 Unproved properties 816,282 116,787 Total 2,926,628 1,662,750 Accumulated depreciation, depletion, amortization and impairment (2,163,291 ) (711,275 ) Net capitalized costs $ 763,337 $ 951,475 _________________ (1) Includes amounts related to non-STACK assets distributed in the 2018 Predecessor Period and reflected as discontinued operations. Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities Acquisition costs in the table below include costs incurred to purchase, lease or otherwise acquire property. Exploration expenses include additions to exploratory wells and other exploration expenses, such as geological and geophysical costs. Development costs include drilling and completion costs plus additions to production facilities and equipment. Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Costs incurred during the period: (1) Property acquisition Unproved (2) $ 54,587 $ 4,240 $ 88,378 $ 66,788 Proved (3) 16,300 327 11,704 68,478 Exploration 32,130 3,678 26,836 28,480 Development (4) 664,138 37,672 351,570 165,796 $ 767,155 45,917 $ 478,488 $ 329,542 _________________ (1) Costs incurred in all Predecessor Periods include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination. Costs incurred in 2017 include amounts related to the Weeks Island field and other assets, all of which are classified as discontinued operations. (2) Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million and $45.6 million for the 2018 Successor Period and the year ended December 31, 2017, respectively. (3) Property acquisition costs for proved properties in 2016 include the transfer of Contributed Wells by our former Class B partner to us of $65.7 million . (4) Includes asset retirement additions (revisions) of $5.6 million , $4.4 million , and $1.9 million for the Successor Period, and years ended December 31, 2017 and 2016 , respectively. For the 2018 Predecessor Period, there were no material asset retirement additions (revisions). Standardized Measure of Discounted Future Net Cash Flows The following information utilizes reserve and production data prepared by us. Future cash inflows were calculated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month, for the Successor Period, the 2018 Predecessor Period, and for the years ended December 31, 2017 and 2016 . Well costs, operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. The following table sets forth the components of the standardized measure of discounted future net cash flows: Successor Predecessor (in thousands, except per unit data) December 31, 2018 February 8, 2018 December 31, 2017 December 31, 2016 Future cash inflows $ 2,446,888 $ 5,798,886 $ 5,799,753 $ 3,547,130 Future production costs (1,214,479 ) (2,556,361 ) (2,617,476 ) (1,811,683 ) Future development costs (23,183 ) (965,780 ) (1,035,481 ) (709,738 ) Future income taxes — — — — Future net cash flows (1) 1,209,226 2,276,745 2,146,796 1,025,709 Discount to present value at 10 percent per annum (396,375 ) (1,096,859 ) (1,040,874 ) (467,101 ) Standardized measure of discounted future net cash flows $ 812,851 $ 1,179,886 $ 1,105,922 $ 558,608 Base price for crude oil, per barrel, in the above computation $ 65.56 $ 52.89 $ 51.34 $ 42.75 Base price for natural gas, per MMBtu, in the above computation $ 3.10 $ 2.99 $ 2.98 $ 2.49 Realized price for NGLs, per barrel, in the above computation $ 22.44 $ 27.48 $ 26.06 $ 15.18 Changes in Standardized Measure of Discounted Future Net Cash Flows Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Balance at beginning of period $ 1,179,886 $ 1,105,922 $ 558,608 $ 629,596 Sales and transfers of oil and gas produced, net of production costs (278,091 ) (30,391 ) (202,232 ) (124,610 ) Net changes in prices and production costs 38,963 71,334 354,900 (324,638 ) Revisions of previous quantity estimates (1) (1,120,097 ) 10,887 (12,106 ) (35,972 ) Purchases of reserves in-place 24,376 — 11,483 40,611 Sales of reserves in-place (2) — (4,807 ) (20,423 ) 2,345 Current year discoveries and extensions, less related costs 684,700 — 513,012 356,631 Changes in estimated future development costs (39,069 ) 491 (5,869 ) 849 Development costs incurred during the period 160,583 — 26,317 8,363 Accretion of discount 117,989 110,592 55,861 62,960 Net change in income taxes — — — — Change in production rate (timing) and other 43,611 (84,142 ) (173,629 ) (57,527 ) Net change (367,035 ) 73,964 547,314 (70,988 ) Balance at end of period $ 812,851 $ 1,179,886 $ 1,105,922 $ 558,608 _________________ (1) Our revisions include approximately $250.0 million of proved undeveloped reserves that were removed at December 31, 2018 due to our subsequent determination of substantial doubt about our ability to continue as a going-concern and the impact on our ability to fund the costs associated with developing those reserves. (2) The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties, and in 2017 the sale of Weeks Island Field and other assets, all of which are reflected as discontinued operations in the Company’s consolidated financial statements. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements include the accounts of the Company and its subsidiaries, and eliminate all intercompany transactions and balances. The Company’s interests in oil and gas upstream ventures and partnerships are proportionately consolidated, in accordance with GAAP. |
Use of Estimates | Use of Estimates Preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported revenue and expenses during the reporting period. Estimates of reserves and their value are used to determine depletion and to conduct impairment analysis of oil and gas properties and can significantly affect future estimated cash flows utilized to assess goodwill and intangible assets for impairment. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of development expenditures. Other estimates are utilized to determine amounts reported under GAAP related to collectibility of receivables, asset retirement obligations, derivatives, accounting for business combinations, share-based compensation and contingencies. We base certain of our estimates on historical experience and various other assumptions that we believe to be reasonable. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates. |
Cash and Cash Equivalents | Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company regularly maintains cash balances that exceed federally insured amounts but we have experienced no losses associated with these amounts. |
Restricted Cash | Restricted Cash Cash balances that are legally, contractually or otherwise restricted as to withdrawal or usage are considered restricted cash. As of December 31, 2018 and 2017 , our restricted cash represents cash received for production where the final division of ownership is in dispute or there is unclaimed property for pooling orders in Oklahoma. |
Accounts Receivable | Accounts Receivable Our receivables arise primarily from (i) the sale of our production and (ii) joint interest owners’ portion of operating costs for properties in which we are the operator. The purchasers of our production are concentrated in the oil and gas industry and therefore they are similarly affected by prevailing industry conditions. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties we operate and market the production. We routinely assess the recoverability of our receivables to determine their collectibility. We establish a valuation allowance to reduce receivables to their estimated collectible amounts, based upon several factors including, our historical experience, the length of time a receivable has been outstanding, communication with customers and the current and projected financial condition of specific customers. |
Property and Equipment | Property and Equipment Our oil and gas property is accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized. Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts to obtain a mineral interest or right in a property, including related broker and other fees. These costs are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties, or when leases expire, at which time the costs are expensed as exploration costs. Unproved properties are not subject to depletion. Proved Oil and Gas Properties — We capitalize costs incurred to drill, complete and equip proved reserves. Proved property costs include all costs incurred to drill and equip successful exploratory wells, development wells (regardless of success), development-type stratigraphic test wells and service wells, plus costs transferred from unproved properties. Accounting policies for other assets include: Other Property and Equipment — Other property and equipment, such as land, vehicles, office furniture and office equipment, are recorded at cost. Maintenance, repairs and minor renewals are expensed as incurred. Other important accounting policies affecting property and equipment include: Depreciation and Depletion — Depletion of proved oil and gas properties is computed using the unit-of-production method based upon produced volumes and estimated proved reserves. Because all of our oil and gas properties are located in a single basin, we apply depletion on a single cost center. We deplete leasehold acquisition costs and the cost to acquire proved properties (generally proved undeveloped costs) based upon total estimated proved reserves. We deplete costs to drill, complete and equip wells plus the related lease costs (generally proved developed costs) over estimated proved developed reserves. Other non-oil and gas property and equipment is depreciated over their estimated useful life, ranging from three to seven years . Impairment — Because proved reserves have not been ascribed to unproved property, in determining whether it is impaired, we consider numerous factors including recent leasing activity, current development plans, recent drilling results in the area, our geologists’ evaluation and the remaining lease term for the property. If a potential impairment exists, we develop a cash flow model based on estimated proved and unproved reserves and, combined with a market approach, estimate fair value. Our cash flow estimates for unproved reserves are reduced by additional risk-weighting factors. We then reduce the carrying amount, if higher, to estimated fair value. We review proved oil and gas properties at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows to the carrying value. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value, which we estimate by discounting the projected future cash flows using an appropriate risk-adjusted rate. We evaluate whether the value of all other long-lived assets is impaired when circumstances indicate the carrying value of those assets may not be recoverable. Such circumstances could result from events such as changes in the condition of an asset or a change in our intent to utilize the asset. The determination of recovery is based on undiscounted cash flow projections compared to the carrying value of the assets. If the carrying amount exceeds undiscounted future net cash flows, we adjust the carrying amount of the assets to their estimated fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent comparable sales, estimated replacement cost, an internally-developed, market participant-based discounted cash flow analysis or an analysis from outside professional advisors. Exploration Expense Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, delay rentals, gains or losses on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well yields commercial reserves. If the exploratory well is determined to be unsuccessful, the cost is expensed as exploration expense in the period of that determination. If the exploratory well yields commercial reserves, it is transferred to proved oil and gas properties. Exploratory well costs may continue to be capitalized for several reporting periods if there is ongoing assessment of commerciality. |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs reflect fees paid to lenders and third parties that are directly related to our establishment of our long term debt. The costs associated with the Alta Mesa RBL are reported as non-current assets and are amortized over the term of the facility as additional interest expense. During the Predecessor Periods, costs associated with the issuance of the 2024 Notes were deferred as a reduction in the value of the outstanding debt and amortized as additional interest expense. |
Acquisitions | Acquisitions Business combinations are accounted for using the acquisition method of accounting. Accordingly, the results of operations of any acquired businesses are included in our results of operations from the closing date. The total cost of each acquisition is allocated to tangible and intangible assets acquired and liabilities assumed based on their estimated fair values at the time of the acquisition. |
Asset Retirement Obligations | Asset Retirement Obligations We recognize liabilities for the anticipated future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets by increasing the carrying amount of the related long-lived asset at the time it is legally incurred. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The asset retirement cost is recognized as depletion or depreciation over the life of the asset. Accretion expense represents the increase to the discounted liability toward its expected settlement value and is included in “Depreciation, depletion and amortization” in the statements of operations. Asset retirement obligations are subject to revision primarily for changes related to the estimated timing and cost of abandonment. |
Bond Premium on Senior Unsecured Notes | Bond Premium on Senior Unsecured Notes In connection with the Business Combination, we estimated the fair value of our $500.0 million senior unsecured notes at $533.6 million . The excess above the face value was recognized as a bond premium, which is being amortized as a reduction in interest expense over the remaining term of the notes. |
Derivatives | Derivatives We present our derivatives as assets or liabilities at estimated fair value. Changes in fair value of our derivatives, along with realized gains or losses from settlements, are recognized as “Gain (loss) on derivatives” in the statements of operations. Settlements of derivatives are classified as operating cash flows. Where master netting agreements are in place, we net the value of our derivative assets and liabilities with the same counterparty. |
Revenue Recognition | Revenue Recognition Predecessor - Oil, natural gas, and NGL revenue were recognized when production was sold to a purchaser at a fixed or determinable price, when delivery had occurred and title had transferred, and collectibility of the revenue was reasonably assured. During the Predecessor Periods, we followed the sales method of accounting for revenue. Under this method of accounting, revenue was recognized based on volumes sold. There were no material gas imbalances during the periods presented. Successor - In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance under GAAP. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply ASC 606 using either the full retrospective approach or a modified retrospective approach. Effective December 31, 2018, we ceased to be an emerging growth company and adopted ASC 606 for the Successor Period, using a modified retrospective approach. There was no impact on the timing of recognition of revenue or of our classification of amounts between revenue and operating expenses upon adoption of ASC 606 . Our revenue from contracts with customers includes the sale of crude oil, natural gas, and NGLs. These sales are recognized as revenue when production is sold to a customer in fulfillment of performance obligations under the terms of the underlying contracts. Performance obligations primarily comprise delivery of our production at a delivery point, as negotiated within each contract. Each unit of oil, natural gas, and NGL is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied once control of the product has been transferred to the customer. We consider a variety of facts and circumstances in assessing the point control is transferred, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, our right to payment, and transfer of legal title. Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price or at purchaser posted prices for the producing area. For oil contracts, we record sales and related expenses on a gross basis upon satisfaction of our performance obligations. Our natural gas production is primarily sold to purchasers at prevailing market prices. We evaluate the contract terms of our gas processing arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis based on the assessment of control and, when applicable, principal versus agent guidance under ASC 606. During the Successor Period, we determined that we controlled the products during processing (i.e., control transfers at the tailgate of the processing plant) or until the processor’s sale to the end customers in downstream markets (i.e., the processor is our agent and we are the principal selling party). Accordingly, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the customer and the gathering and processing services are rendered, similar to the accounting treatment required under previous revenue accounting guidance. All facts and circumstances are considered and judgment is often required in making this determination. Customers are invoiced once our performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30-60 days. There are no significant judgments that affect the amount or timing of revenue from contracts with customers. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities, apart from production receivables. Our receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates, as well as for unbilled costs for wells subject to Oklahoma’s forced pooling process in which mineral owners have the option to participate in the drilling of pooled wells. Depending on the mineral owner’s decision, these costs will be billed to them or added to our oil and gas properties. Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts. We have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors and have reflected this disaggregation of revenue for all periods presented. We do not have material unsatisfied performance obligations for contracts as all contracts have either an original expected length of one year or less or the entire future consideration is variable and allocated entirely to a wholly unsatisfied performance obligation. |
Equity-Based Compensation | Equity-Based Compensation Our parent company, AMR, grants various types of stock-based awards, including stock options, restricted stock and performance-based restricted stock units to certain of our employees. The fair value of stock option awards is determined using the Black-Scholes option pricing model, which includes various assumptions. Expected volatilities utilized in the option pricing model are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. Dividend yield is based on our expectations of dividend payments during the expected term of the options granted and risk-free interest rates are based on U.S. Treasury rates in effect at the grant date. Service-based restricted stock awards are valued using the market price of AMR’s Class A Common Stock on the grant date. Performance-based restricted stock awards are valued using the market price of AMR’s Class A Common Stock at the later of grant date and when all performance-based criteria are determined. We recognize the estimated fair value of stock option and restricted stock awards as compensation expense on a straight-line basis over the applicable vesting period, which generally is three years, except in the case of awards made to our directors, which vest immediately upon issuance. Awards of performance-based restricted stock units that contain tranches with multi-year performance targets are recognized over the vesting period for which performance criteria for each tranche have been determined. All awards to employees typically require continued employment to vest. Forfeitures of unvested awards are recognized when they occur and result in the reversal of previously recognized expense. |
Income Taxes | Income Taxes We have elected under the Internal Revenue Code of 1986, as amended, to be treated as an individual partnership for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are not taxed at the partnership level. Accordingly, no tax provision for federal income taxes is included in these financial statements. |
Fair Value Hierarchy | Fair Value Hierarchy Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date within our principal market. There are three levels of the fair value hierarchy: • Level 1 — Fair value is based on quoted prices in active markets for identical assets or liabilities. • Level 2 — Fair value is determined using significant observable inputs, generally either quoted prices in active markets for similar assets or liabilities, or quoted prices in markets that are not active. • Level 3 — Fair value is determined using one or more significant inputs that are unobservable in active markets at the measurement date. Such inputs are often used in pricing models, discounted cash flow calculations, or similar techniques. We utilize fair value measurements to account for certain items, determine certain account balances and provide disclosures. Fair value measurements are also utilized in assessing the impairment of long-lived assets. We consider the book values of our cash, accounts and notes receivable and current liabilities to approximate fair value due to their short-term nature. We also consider the carrying value of our long-term debt under the Alta Mesa RBL to not be materially different from fair value due to short-term variable market rates of interest applicable to our outstanding borrowings. |
Going Concern | Going Concern |
Recenlty Issued and Applicable Accounting Standards | Adopted During the 1st quarter of 2018, we adopted Accounting Standards Update (“ASU”) No. 2017-04, Intangibles - Goodwill and Other, Simplifying the Test for Goodwill Impairment. This new guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Accordingly, any identified impairment of goodwill will be recognized as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. We adopted ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) on December 31, 2018, which clarified how certain transactions are classified in the statement of cash flows. The adoption of this guidance had no material effect. We adopted ASU 2014-09, Revenue from Contacts with Customers , and related amendments, codified as Accounting Standards Codification (“ASC”) 606, on December 31, 2018, retroactive to the beginning of our Successor Period. There was no impact on the timing of recognition of revenue or of our classification of amounts between revenue and operating expenses upon adoption of ASC 606 , however, enhanced disclosure of our revenue recognition policies was required. Not Yet Adopted Leasing Standards In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. We have used a modified retrospective transition approach for existing leases with terms in excess of 12 months entered into prior to January 1, 2019, the date of our adoption. In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. ASU 2018-01 and subsequent applicable ASUs also provide several other optional practical expedients in transition. We elected the “package of practical expedients”, which permits us to forgo reassessment of our prior conclusions about lease identification, lease classification and initial direct costs for leases entered into prior to the effective date, January 1, 2019. We also elected the land easement relief which permits us to forgo reassessment of existing or expired land easements not previously accounted for under ASC 840. Additionally, we elected the practical expedient to not provide comparative reporting periods and therefore financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. By accounting policy, we will not separate non-lease components from lease components. We did not elect the use-of-hindsight practical expedient. We are continuing to assess and finalize all of the effects of adoption, but currently believe the most significant effects relate to (1) recognition of new right-of-use assets and lease liabilities on our balance sheet for our office and equipment operating leases totaling approximately $20.0 million each, effective as of January 1, 2019; and (2) providing significant new disclosures about our leasing activities in our future filings. We are also finalizing the implementation of third-party lease accounting software and completing the design and implementation of our processes and internal controls regarding this new standard. Other Standards In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations. In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We don’t expect the adoption of this standard to impact our financial position or results of operations. |
Impairment of Assets (Tables)
Impairment of Assets (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Impairment of Assets | Successor Predecessor (in thousands) February 9, 2018 January 1, 2018 Year Ended Year Ended Impairment of unproved properties $ 742,065 $ — $ — $ 16 Impairment of proved properties 1,291,647 — 1,188 366 Total impairment of assets $ 2,033,712 $ — $ 1,188 $ 382 |
Receivables (Tables)
Receivables (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Schedule of Accounts Receivable | Successor Predecessor (in thousands) December 31, 2018 December 31, 2017 Production sales $ 31,532 $ 26,916 Joint interest billings 18,147 13,821 Pooling interest (1) 18,786 35,839 Allowance for doubtful accounts (95 ) (415 ) Total accounts receivable, net $ 68,370 $ 76,161 _________________ (1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents unbilled costs for wells where the option remains pending. Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties. Activity in our allowances for doubtful accounts for trade and related party receivables were as follows: Successor Predecessor (in thousands) February 9, 2018 January 1, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Trade receivables: Balance at beginning of period $ 415 $ 415 $ 490 $ 1,030 Charged to expense 25 — (69 ) 243 Deductions (345 ) — (6 ) (783 ) Balance at end of period $ 95 $ 415 $ 415 $ 490 Related party receivables: Balance at beginning of period $ — $ — $ — $ — Charged to expense (1) 22,438 — — — Deductions — — — — Balance at end of period $ 22,438 $ — $ — $ — _________________ (1) At December 31, 2018, receivables, including notes receivable, from HMI were approximately $23.4 million . Upon receiving payment of approximately $1.0 million dollars in 2019, the balance was reduced to $22.4 million . Because HMI disputes it obligations under the promissory notes with us, we established an allowance for doubtful accounts totaling $22.4 million which is included in general and administrative expense in 2018. |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosures To The Consolidated Statements Of Cash Flows | Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Supplemental cash flow information: Cash paid for interest $ 47,862 $ 1,145 $ 47,773 $ 74,694 Cash paid for state income taxes, net of refunds 4 — — 285 Non-cash investing and financing activities: Increase in asset retirement obligations 5,665 — 4,363 2,719 Asset retirement obligations assumed on purchased properties — — 702 — Increase in accruals or payables for capital expenditures 5,389 4,896 71,995 12,375 Increase in accounts payable to related party for capital expenditures 4,082 — 7,646 — Increase in withholding tax accruals for share-based compensation 535 — — — Distribution of non-STACK assets, net of liabilities — 43,482 — — Contribution of interests in oil and gas properties — — — 65,740 Contribution receivable — — — 7,875 |
Reconciliation Of Cash, Cash Equivalents And Restricted Cash | The following table summarizes cash, cash equivalents and restricted cash in the statements of cash flows: Successor Predecessor (in thousands) December 31, 2018 February 8, 2018 December 31, 2017 December 31, 2016 Cash and cash equivalents $ 12,984 $ 9,070 $ 3,660 $ 7,102 Restricted cash 1,001 1,275 1,269 433 Cash from discontinued operations — — 61 83 Total cash, cash equivalents and restricted cash $ 13,985 $ 10,345 $ 4,990 $ 7,618 |
Reconciliation Of Cash, Cash Equivalents And Restricted Cash | The following table summarizes cash, cash equivalents and restricted cash in the statements of cash flows: Successor Predecessor (in thousands) December 31, 2018 February 8, 2018 December 31, 2017 December 31, 2016 Cash and cash equivalents $ 12,984 $ 9,070 $ 3,660 $ 7,102 Restricted cash 1,001 1,275 1,269 433 Cash from discontinued operations — — 61 83 Total cash, cash equivalents and restricted cash $ 13,985 $ 10,345 $ 4,990 $ 7,618 |
Significant Acquisitions and _2
Significant Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Business Acquisition [Line Items] | |
Purchase consideration | (in thousands) February 9, 2018 (As initially reported) Measurement Period Adjustment (1) February 9, 2018 (As adjusted) Purchase Consideration: (2) SRII Opco Common Units issued (3) $ 1,251,782 $ 9,467 $ 1,261,249 Estimated fair value of contingent earn-out purchase consideration (4) 284,109 — 284,109 Total purchase price consideration $ 1,535,891 $ 9,467 $ 1,545,358 _________________ (1) The measurement period adjustment relates to the issuance of 1,197,934 of additional SRII Opco Common Units, valued at approximately $7.90 per unit, to the AM Contributor based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 (Successor). (2) The purchase price consideration was for 100% of the limited partner interests in us and 100% of the economic interests and 90% of the voting interests in AMH GP. (3) At closing, the Riverstone Contributor received consideration of 20,000,000 SRII Opco Common Units and the AM Contributor received consideration of 138,402,398 SRII Opco Common Units. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity. (4) For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of AMR Class C Common Stock) if the 20-day VWAP of the Class A Common Stock of AMR equals or exceeds the specified prices pursuant to the AM Contribution Agreement. Pursuant to ASC 805 and ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), we have determined that the fair value of the earn-out consideration was approximately $284.1 million , which was classified as equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to AMR (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life. |
Alta Mesa RBL | |
Business Acquisition [Line Items] | |
Allocation of purchase consideration | (in thousands) February 9, 2018 (As initially reported) Measurement Period Adjustment (1) February 9, 2018 (As adjusted) Estimated Fair Value of Assets Acquired (2) Cash, cash equivalents and restricted cash $ 10,345 $ — $ 10,345 Accounts receivable 101,745 — 101,745 Other receivables 1,222 840 2,062 Receivables due from related party 907 — 907 Prepaid expenses and other 1,405 — 1,405 Derivatives 352 — 352 Property and equipment: (3) Oil and gas properties, successful efforts 2,314,858 (4,879 ) 2,309,979 Other property and equipment, net 43,318 — 43,318 Notes receivable due from related party 12,454 — 12,454 Deposits and other long-term assets 10,286 — 10,286 Total fair value of assets acquired 2,496,892 (4,039 ) 2,492,853 Estimated Fair Value of Liabilities Assumed (2) Accounts payable and accrued liabilities 210,867 (13,506 ) 197,361 Accounts payable — affiliate 5,476 — 5,476 Advances from non-operators 6,803 — 6,803 Advances from related party 47,506 — 47,506 Asset retirement obligations (3) 5,998 — 5,998 Derivatives 11,585 — 11,585 Long-term debt (4) 667,700 — 667,700 Other long-term liabilities 5,066 — 5,066 Total fair value of liabilities assumed 961,001 (13,506 ) 947,495 Total consideration and fair value $ 1,535,891 $ 9,467 $ 1,545,358 _________________ (1) The measurement period adjustments were recognized in the reporting period in which the adjustments were determined. The measurement period adjustments relate to a change in the purchase consideration based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 and certain adjustments to beginning balances. (2) The assets acquired and liabilities assumed relate to Alta Mesa’s STACK assets. (3) The estimated fair value of oil and gas properties and asset retirement obligations were determined using valuation techniques that convert future cash flows to a single discounted amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). Significant inputs include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discount rates, and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation. Actual results may vary from these estimates. (4) Represents the approximate fair value as of the acquisition date of (i) Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million , based on Level 1 inputs, and (ii) outstanding borrowings under the Alta Mesa Predecessor Credit Facility of approximately $134.1 million as of the acquisition date. |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Summary of Property and Equipment | Successor Predecessor (in thousands) December 31, 2018 December 31, 2017 Oil and gas properties Unproved properties $ 816,282 $ 84,590 Accumulated impairment of unproved properties (742,065 ) — Unproved properties, net 74,217 84,590 Proved oil and gas properties 2,110,346 1,061,105 Accumulated depreciation, depletion, amortization and impairment (1,421,226 ) (251,065 ) Proved oil and gas properties, net 689,120 810,040 Total oil and gas properties, net 763,337 894,630 Other property and equipment Land 5,059 2,912 Fresh water wells 27,366 — Produced water disposal system 3,608 30,990 Office furniture, equipment and vehicles 2,840 20,008 Accumulated depreciation (726 ) (21,770 ) Other property and equipment, net 38,147 32,140 Total property and equipment, net $ 801,484 $ 926,770 Successor Predecessor (in thousands) February 9, 2018 January 1, 2018 Year Ended Year Ended Oil and gas properties depletion $ 130,439 $ 11,021 $ 83,537 $ 49,481 Other property and equipment depreciation 2,375 609 5,240 4,004 Total depreciation and depletion expense $ 132,814 $ 11,630 $ 88,777 $ 53,485 |
Discontinued Operations (Pred_2
Discontinued Operations (Predecessor) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disposed of by Sale | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Schedule Of Discontinued Operations | Predecessor (in thousands) January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Revenue: Oil $ 1,617 $ 47,218 $ 57,866 Natural gas 1,023 10,090 10,932 Natural gas liquids 236 2,359 1,489 Other 16 316 213 Operating revenue 2,892 59,983 70,500 Loss on sale of assets (1,923 ) (22,207 ) 3,539 Gain on acquisition of oil and gas properties — 1,626 — Total revenue 969 39,402 74,039 Operating expenses: Lease operating 1,770 27,763 29,474 Transportation and marketing 83 1,354 1,698 Production taxes 167 6,730 7,985 Workover 127 2,088 1,273 Exploration — 11,431 7,547 Depreciation, depletion and amortization 884 24,519 41,320 Impairments of assets 5,560 29,129 15,924 General and administrative 21 82 1,290 Total operating expenses 8,612 103,096 106,511 Other income (expense) Interest expense (103 ) (1,209 ) (1,209 ) Interest income and other — 88 10 Total other income (expense) (103 ) (1,121 ) (1,199 ) Income tax provision (benefit) — — (29 ) Loss from discontinued operations, net of state income taxes $ (7,746 ) $ (64,815 ) $ (33,642 ) Predecessor (in thousands) December 31, Assets associated with discontinued operations: Current assets Cash $ 61 Accounts receivable 4,980 Other receivables 154 Total current assets 5,195 Noncurrent assets Investments 9,000 Oil and gas properties, net 33,618 Other long-term assets 1,167 Total noncurrent assets 43,785 Total assets associated with discontinued operations $ 48,980 Liabilities associated with discontinued operations: Current liabilities Accounts payable and accrued liabilities $ 7,882 Asset retirement obligations 7,537 Total current liabilities 15,419 Noncurrent liabilities Asset retirement obligations, net of current portion 37,049 Founder Notes 28,166 Other long-term liabilities 1,647 Total noncurrent liabilities 66,862 Total liabilities associated with discontinued operations $ 82,281 Predecessor (in thousands) January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Total operating cash flows of discontinued operations $ 2,974 $ 21,138 $ 31,255 Total investing cash flows of discontinued operations (601 ) 6,891 (14,378 ) |
Fair Value Disclosures (Tables)
Fair Value Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Nonrecurring Measurements | Oil and gas properties are subject to impairment testing and potential impairment based largely on future estimated cash flows determined using Level 3 inputs. Successor Predecessor December 31, 2018 December 31, 2017 (in thousands) Original Carrying Value Estimated Fair Value Impairment Original Carrying Value Estimated Fair Value Impairment Unproved oil and gas properties $ 816,282 $ 74,217 $ 742,065 $ — $ — $ — Proved oil and gas properties 1,895,670 604,023 1,291,647 3,350 2,162 1,188 Total $ 2,711,952 $ 678,240 $ 2,033,712 $ 3,350 $ 2,162 $ 1,188 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative [Line Items] | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The following summarizes the fair value and classification of our derivatives: December 31, 2018 (Successor) Balance sheet location Gross fair value of assets Gross liabilities offset against assets in the Balance Sheet Net fair value of assets presented in the Balance Sheet (in thousands) Derivatives, current assets $ 22,512 $ (6,089 ) $ 16,423 Derivatives, long-term assets 7,910 (4,963 ) 2,947 Total $ 30,422 $ (11,052 ) $ 19,370 Balance sheet location Gross fair value of liabilities Gross assets offset against liabilities in the Balance Sheet Net fair value of liabilities presented in the Balance Sheet (in thousands) Derivatives, current liabilities $ 7,799 $ (6,089 ) $ 1,710 Derivatives, long-term liabilities 5,143 (4,963 ) 180 Total $ 12,942 $ (11,052 ) $ 1,890 December 31, 2017 (Predecessor) Balance sheet location Gross fair value of assets Gross liabilities offset against assets in the Balance Sheet Net fair value of assets presented in the Balance Sheet (in thousands) Derivatives, current assets $ 1,406 $ (1,190 ) $ 216 Derivatives, long-term assets 3,010 (3,002 ) 8 Total $ 4,416 $ (4,192 ) $ 224 Balance sheet location Gross fair value of liabilities Gross assets offset against liabilities in the Balance Sheet Net fair value of liabilities presented in the Balance Sheet (in thousands) Derivatives, current liabilities $ 20,493 $ (1,190 ) $ 19,303 Derivatives, long-term liabilities 4,116 (3,002 ) 1,114 Total $ 24,609 $ (4,192 ) $ 20,417 |
Effect Of Derivative Instruments In The Consolidated Statements Of Operations | The following table summarizes the effect of our derivatives in the statements of operations (in thousands): Successor Predecessor February 9, 2018 January 1, 2018 Derivatives not Through Through Year Ended Year Ended designated as hedges December 31, 2018 February 8, 2018 December 31, 2017 December 31, 2016 Gain (loss) on derivatives - Oil commodity contracts $ (3,559 ) $ 4,796 $ 1,450 $ (36,572 ) Natural gas commodity contracts (6,688 ) 1,867 7,288 (2,410 ) Natural gas liquids commodity contracts — — (451 ) (1,478 ) Total gain (loss) on derivatives $ (10,247 ) $ 6,663 $ 8,287 $ (40,460 ) |
Oil Derivative Contracts | |
Derivative [Line Items] | |
Open Derivative Contracts | Volume Weighted Range Settlement Period and Type of Contract in bbls Average High Low 2019 Price Swap Contracts 182,500 $ 63.03 $ 63.03 $ 63.03 Collar Contracts Short Call Options 2,701,000 66.31 75.20 56.50 Long Put Options 2,883,500 53.80 62.00 50.00 Short Put Options 2,883,500 42.72 52.00 37.50 2020 Collar Contracts Short Call Options 585,600 64.32 73.80 59.55 Long Put Options 1,537,200 55.54 62.50 50.00 Short Put Options 1,537,200 44.64 50.00 37.50 |
Natural Gas Derivative Contract | |
Derivative [Line Items] | |
Open Derivative Contracts | Volume in Weighted Range Settlement Period and Type of Contract MMBtu Average High Low 2019 Price Swap Contracts 10,905,000 $ 2.69 $ 3.09 $ 2.64 Collar Contracts Short Call Options 4,000,000 3.31 3.75 3.17 Long Put Options 3,550,000 2.81 2.90 2.70 Short Put Options 2,425,000 2.27 2.40 2.20 2020 Collar Contracts Short Call Options 2,275,000 3.19 3.20 3.17 Long Put Options 9,150,000 2.57 2.70 2.50 Short Put Options 9,150,000 2.07 2.20 2.00 2021 Collar Contracts Long Put Options 2,250,000 2.65 2.65 2.65 Short Put Options 2,250,000 2.15 2.15 2.15 |
Basis Swap Derivative Contract [Member] | |
Derivative [Line Items] | |
Natural Gas Basis Swap Contracts | We had the following basis swaps at December 31, 2018 : Total Gas Volumes in MMBtu over Remaining Term (1) Reference Price 1 (1) Reference Price 2 (1) Period Weighted Average Spread ($ per MMBtu) 460,000 OneOK NYMEX Henry Hub Jul '19 — Dec '19 $ (0.93 ) 17,950,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '19 — Dec '19 (0.68 ) 910,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '20 — Mar '20 (0.49 ) 2,365,000 San Juan NYMEX Henry Hub Jan '19 — Oct '19 (0.78 ) ________________ (1) Represents short swaps that fix the basis differentials between OneOK, T ex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Summary Of Changes In Asset Retirement Obligations | Predecessor (in thousands) 2018 2017 Balance, as of January 1 (Predecessor) $ 10,469 $ 8,400 Liabilities settled (63 ) Revisions to estimates 63 Accretion expense 39 Balance, as of February (Predecessor) $ 10,508 Balance, beginning of year (Successor) (1) $ 5,998 — Liabilities assumed — 604 Liabilities incurred 2,536 1,583 Liabilities settled (1,610 ) (119 ) Liabilities transferred via sale (383 ) — Revisions to estimates 4,130 (337 ) Accretion expense 738 338 Balance, as of December 31 11,409 10,469 Less: Current portion 2,079 69 Long-term portion $ 9,330 $ 10,400 _________________ (1) Represents the same wells under the Predecessor Period valued at a higher interest rate of 10.2% compared to interest rates ranging between 4.4% and 8.8% . |
Long Term Debt, Net (Tables)
Long Term Debt, Net (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt, Net And Notes Payable To Founder | Successor Predecessor (in thousands) December 31, 2018 December 31, 2017 Alta Mesa RBL $ 161,000 $ — Alta Mesa Predecessor Credit Facility — 117,065 2024 Notes 500,000 500,000 Unamortized premium on 2024 notes 29,123 — Unamortized deferred financing costs — (9,625 ) Total long-term debt, net $ 690,123 $ 607,440 |
Debt Redemption Prices | On and after December 15, 2019, we may redeem the 2024 Notes, in whole or in part, at the following redemption prices plus accrued and unpaid interest, if any, to the date of redemption: After December 15 2019 2020 2021 2022 Redemption price as a percentage of principal amount 105.906 % 103.938 % 101.969 % 100 % |
Summary Of Future Maturities Of Long-Term Debt | Fiscal Year (in thousands) 2019 $ — 2020 — 2021 — 2022 — 2023 161,000 Thereafter 500,000 $ 661,000 |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Payables and Accruals [Abstract] | |
Detail Of Accounts Payable And Accrued Liabilities | Successor Predecessor (in thousands) December 31, December 31, Accounts payable $ 20,200 $ 68,578 Accruals for capital expenditures 101,214 48,771 Revenue and royalties payable 46,870 29,514 Accruals for operating expenses 16,355 14,632 Accrued interest 1,784 2,587 Derivative settlements 109 2,106 Other 10,532 4,301 Total accrued liabilities 176,864 101,911 Accounts payable and accrued liabilities $ 197,064 $ 170,489 |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Future Base Rentals For Non-Cancelable Leases | At December 31, 2018 , we have the remaining future minimum lease payments : Fiscal Year In thousands 2019 $ 2,819 2020 2,851 2021 2,911 2022 3,107 2023 3,038 Thereafter 12,219 $ 26,945 |
Schedule Of Firm Delivery Contracts | This commitment extends through 2021 with the following commitments at December 31, 2018 : Fiscal Year In thousands 2019 $ 1,551 2020 1,556 2021 1,551 $ 4,658 |
Schedule of Firm Transportation Contracts | We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of our natural gas that extend through 2028 with the following commitments at December 31, 2018 : Fiscal Year In thousands 2019 $ 12,236 2020 12,236 2021 12,236 2022 12,236 2023 12,236 Thereafter 25,023 $ 86,203 |
Equity-Based Compensation (Su_2
Equity-Based Compensation (Successor) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Outstanding Stock Options | Stock options expire seven years from the grant date and generally vest in one-third increments each year, based on continued employment. Employees have 90 days after termination to exercise vested stock options, unless extended by an employment agreement. Successor Stock Options Weighted Average Exercise Price Weighted Average Grant-Date Fair Value Weighted Average Remaining Term (Years) Aggregate Intrinsic Value (in thousands) Outstanding as of February 9, 2018 — $ — $ — — $ — Granted 4,840,799 8.90 4.37 — — Exercised — — — — — Forfeited or expired (134,956 ) 9.37 4.55 — — Outstanding as of December 31, 2018 4,705,843 8.89 4.36 5.2 — Vested at December 31, 2018 or expected to vest in future 4,705,843 8.89 4.36 5.2 — Exercisable as of December 31, 2018 1,509,434 $ 9.54 $ 4.62 3.0 $ — |
Summary of Assumptions Used to Determine the Fair Value of Options | The following assumptions were used to determine the fair value of the 2018 option grants: Successor February 9, 2018 Expected term (in years) 4.5 Expected stock volatility 64.6 % Dividend yield — Risk-free interest rate 2.5 % |
Schedule of Restricted Stock Awards Granted | The following table provides information about restricted stock awards granted during the Successor Period: Successor Restricted Stock Awards Weighted Average Grant Date Fair Value per share Outstanding as of February 9, 2018 — $ — Granted 1,720,949 7.61 Vested (1) (286,214 ) 8.38 Forfeited or expired (59,980 ) 8.80 Outstanding as of December 31, 2018 1,374,755 $ 7.39 _________________ (1) To satisfy minimum tax withholding, 94,576 shares were withheld. |
Summary of PSUs Granted | The following summary provides information about the target number of PSUs granted during the Successor Period: Successor Restricted Stock Units Weighted Average Grant - Date Fair Value per unit Outstanding as of February 9, 2018 — $ — Granted 2,049,105 3.99 Vested (1) (1,559,749 ) 2.53 Forfeited or expired (489,356 ) (8.61 ) Outstanding as of December 31, 2018 — — $ — _________________ (1) To satisfy minimum tax withholding, 388,655 shares were withheld. |
Supplemental Quarterly Inform_2
Supplemental Quarterly Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summary Of Quarterly Results Of Operations | Predecessor Successor 2018 (in thousands) January 1, 2018 Through February 8, 2018 February 9, 2018 Through March 31, 2018 June 30 Sept 30 Dec 31 Total revenue $ 47,639 $ 34,090 $ 66,459 $ 122,873 $ 185,589 Income (loss) from continuing operations (1)(2)(3) (7,116 ) (34,571 ) (22,477 ) 17,844 (2,037,170 ) Income (loss) from discontinued operations (7,746 ) — — — — Net income (loss) (1)(2)(3) (14,862 ) (34,571 ) (22,477 ) 17,844 (2,037,170 ) _________________ (1) Includes $2.0 billion of impairment expense during the quarter ended December 31, 2018. (2) Includes $6.7 million and $52.8 million of gains on derivatives during the 2018 Predecessor Period and the quarter ended December 31, 2018, respectively. Includes $22.6 million , $29.2 million and $11.2 million of losses on derivatives during the period from February 9, 2018 through March 31, 2018, and during the quarters ended June 30, 2018 and September 30, 2018, respectively. (3) Includes $6.0 million gain primarily from the sale of seismic data during the period from February 9, 2018 through March 31, 2018. Predecessor 2017 (in thousands) March 31 June 30 Sept 30 Dec 31 Total revenue (1)(2) $ 95,079 $ 79,800 $ 57,923 $ 46,567 Income (loss) from continuing operations (1)(2)(3) 29,430 15,620 (22,163 ) (35,733 ) Loss from discontinued operations (4) (4,515 ) (30,934 ) (2,041 ) (27,325 ) Net income (loss) 24,915 (15,314 ) (24,204 ) (63,058 ) _________________ (1) Includes $30.2 million and $18.3 million of gains on derivatives during quarters ended March 31, 2017 and June 30, 2017, respectively, and $10.5 million and $29.7 million of losses on derivatives during the quarters ended September 30, 2017 and December 31, 2017, respectively. (2) Includes $5.3 million gain on acquisition of oil and gas properties during the quarter ended September 30, 2017, which was reduced by $3.6 million during the quarter ended December 31, 2017. (3) Includes $1.2 million of impairment expense during the quarter ended March 31, 2017. (4) The quarter ended December 31, 2017 includes a loss on the sale of assets of $22.2 million, primarily associated with the sale of Weeks Island. |
Supplemental Oil And Natural _2
Supplemental Oil And Natural Gas Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Oil and Natural Gas Disclosures [Abstract] | |
Estimated Quantities Of Proved Reserves | Oil (Mbbls) Gas (MMcf) NGL’s (Mbbls) Boe (Mbbls) Total Proved Reserves: Balance at December 31, 2015 (Predecessor) 34,142 155,423 18,437 78,483 Production (4,001 ) (13,959 ) (956 ) (7,284 ) Purchases in place (1) 1,508 6,754 613 3,247 Discoveries and extensions 29,903 154,653 14,000 69,679 Sales of reserves in place (73 ) (966 ) (10 ) (244 ) Revisions of previous quantity estimates and other (3,680 ) 14,100 (3,794 ) (5,124 ) Balance at December 31, 2016 (Predecessor) 57,799 316,005 28,290 138,757 Production (4,850 ) (18,218 ) (1,387 ) (9,274 ) Purchases in place 725 4,860 401 1,936 Discoveries and extensions 20,135 108,676 9,640 47,888 Sales of reserves in place (3,622 ) (1,280 ) — (3,836 ) Revisions of previous quantity estimates and other 3,331 23,476 (57 ) 7,187 Balance at December 31, 2017 (Predecessor) 73,518 433,519 36,887 182,658 Production (521 ) (1,984 ) (161 ) (1,012 ) Purchases in place — — — — Discoveries and extensions — — — — Sales of reserves in place (2) (1,667 ) (24,239 ) (771 ) (6,478 ) Revisions of previous quantity estimates and other 375 3,506 289 1,248 Balance at February 8, 2018 (Predecessor) 71,705 410,802 36,244 176,416 Production (5,053 ) (16,913 ) (2,268 ) (10,140 ) Purchases in place (3) 2,658 13,331 1,751 6,631 Discoveries and extensions (3) 30,026 155,306 19,646 75,557 Sales of reserves in place — — — — Revisions of previous quantity estimates and other (3)(4) (74,064 ) (418,378 ) (35,581 ) (179,375 ) Balance at December 31, 2018 (Successor) 25,272 144,148 19,792 69,089 Proved Developed Reserves: Balance at December 31, 2015 14,942 71,752 6,958 33,859 Balance at December 31, 2016 16,832 93,361 7,977 40,371 Balance at December 31, 2017 20,347 150,183 12,180 57,557 Balance at February 8, 2018 19,345 126,231 11,348 51,731 Balance at December 31, 2018 25,272 144,148 19,792 69,089 Proved Undeveloped Reserves: Balance at December 31, 2015 19,200 83,671 11,479 44,624 Balance at December 31, 2016 40,967 222,644 20,313 98,386 Balance at December 31, 2017 53,171 283,336 24,707 125,101 Balance at February 8, 2018 52,360 284,571 24,896 124,685 Balance at December 31, 2018 — — — — _________________ (1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from HMI. (2) Sales of reserves in place during the 2018 Predecessor Period represent amounts related to our non-STACK properties that were distributed to the AM contributor and are classified as discontinued operations in our consolidated financial statements. (3) Effective as of December 31, 2018 , due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves, we have removed all of our PUDs from our total estimated proved reserves. Discoveries and extensions and purchases in place during the 2018 Successor Period include approximately 47,092 MBoe in PUDs, and this amount is also included with our negative revisions and is consequently removed from our total proved reserves at December 31, 2018 . (4) In addition to removing PUDs, we lowered our estimate of proved reserves at December 31, 2018 by approximately 101,516 MBoe, largely due to results of the 2018 drilling program demonstrating lower estimated recovery per 640 -acre section. Partially offsetting this was an increase in recoverable reserves of approximately 11,196 MBoe, due mainly to higher average commodity prices in 2018 as compared to 2017. |
Results of Operations for Oil and Gas Producing Activities | Results of Operations for Oil and Gas Producing Activities Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Operating revenue $ 414,507 $ 40,136 $ 269,386 $ 142,356 Production expense (1) 247,748 30,743 138,833 87,869 Depreciation, depletion and amortization 133,554 11,670 89,115 53,755 Exploration expense 34,085 7,003 13,563 17,230 Impairment expense 2,033,712 — 1,188 382 Income tax expense (benefit) 4 — 6 — Results of operations $ (2,034,596 ) $ (9,280 ) $ 26,681 $ (16,880 ) ________________ (1) Production expense consists of direct lease operating expense, transportation and marketing expense, production taxes, workover expense and general and administrative expense. |
Capitalized Costs Relating To Oil And Natural Gas Producing Activities | December 31, (in thousands) Successor 2018 Predecessor 2017 (1) Capitalized costs: Proved properties $ 2,110,346 $ 1,545,963 Unproved properties 816,282 116,787 Total 2,926,628 1,662,750 Accumulated depreciation, depletion, amortization and impairment (2,163,291 ) (711,275 ) Net capitalized costs $ 763,337 $ 951,475 _________________ (1) Includes amounts related to non-STACK assets distributed in the 2018 Predecessor Period and reflected as discontinued operations. |
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities | Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Costs incurred during the period: (1) Property acquisition Unproved (2) $ 54,587 $ 4,240 $ 88,378 $ 66,788 Proved (3) 16,300 327 11,704 68,478 Exploration 32,130 3,678 26,836 28,480 Development (4) 664,138 37,672 351,570 165,796 $ 767,155 45,917 $ 478,488 $ 329,542 _________________ (1) Costs incurred in all Predecessor Periods include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination. Costs incurred in 2017 include amounts related to the Weeks Island field and other assets, all of which are classified as discontinued operations. (2) Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million and $45.6 million for the 2018 Successor Period and the year ended December 31, 2017, respectively. (3) Property acquisition costs for proved properties in 2016 include the transfer of Contributed Wells by our former Class B partner to us of $65.7 million . (4) Includes asset retirement additions (revisions) of $5.6 million , $4.4 million , and $1.9 million for the Successor Period, and years ended December 31, 2017 and 2016 , respectively. For the 2018 Predecessor Period, there were no material asset retirement additions (revisions). |
Components Of The Standardized Measure Of Discounted Future Net Cash Flows | The following table sets forth the components of the standardized measure of discounted future net cash flows: Successor Predecessor (in thousands, except per unit data) December 31, 2018 February 8, 2018 December 31, 2017 December 31, 2016 Future cash inflows $ 2,446,888 $ 5,798,886 $ 5,799,753 $ 3,547,130 Future production costs (1,214,479 ) (2,556,361 ) (2,617,476 ) (1,811,683 ) Future development costs (23,183 ) (965,780 ) (1,035,481 ) (709,738 ) Future income taxes — — — — Future net cash flows (1) 1,209,226 2,276,745 2,146,796 1,025,709 Discount to present value at 10 percent per annum (396,375 ) (1,096,859 ) (1,040,874 ) (467,101 ) Standardized measure of discounted future net cash flows $ 812,851 $ 1,179,886 $ 1,105,922 $ 558,608 Base price for crude oil, per barrel, in the above computation $ 65.56 $ 52.89 $ 51.34 $ 42.75 Base price for natural gas, per MMBtu, in the above computation $ 3.10 $ 2.99 $ 2.98 $ 2.49 Realized price for NGLs, per barrel, in the above computation $ 22.44 $ 27.48 $ 26.06 $ 15.18 |
Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Balance at beginning of period $ 1,179,886 $ 1,105,922 $ 558,608 $ 629,596 Sales and transfers of oil and gas produced, net of production costs (278,091 ) (30,391 ) (202,232 ) (124,610 ) Net changes in prices and production costs 38,963 71,334 354,900 (324,638 ) Revisions of previous quantity estimates (1) (1,120,097 ) 10,887 (12,106 ) (35,972 ) Purchases of reserves in-place 24,376 — 11,483 40,611 Sales of reserves in-place (2) — (4,807 ) (20,423 ) 2,345 Current year discoveries and extensions, less related costs 684,700 — 513,012 356,631 Changes in estimated future development costs (39,069 ) 491 (5,869 ) 849 Development costs incurred during the period 160,583 — 26,317 8,363 Accretion of discount 117,989 110,592 55,861 62,960 Net change in income taxes — — — — Change in production rate (timing) and other 43,611 (84,142 ) (173,629 ) (57,527 ) Net change (367,035 ) 73,964 547,314 (70,988 ) Balance at end of period $ 812,851 $ 1,179,886 $ 1,105,922 $ 558,608 _________________ (1) Our revisions include approximately $250.0 million of proved undeveloped reserves that were removed at December 31, 2018 due to our subsequent determination of substantial doubt about our ability to continue as a going-concern and the impact on our ability to fund the costs associated with developing those reserves. (2) The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties, and in 2017 the sale of Weeks Island Field and other assets, all of which are reflected as discontinued operations in the Company’s consolidated financial statements. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Details) | Apr. 01, 2019USD ($) | Jun. 30, 2019USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018$ / bbl | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($)$ / bbl | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Mar. 25, 2019USD ($) | Feb. 22, 2019$ / shares | Jan. 01, 2019USD ($) | Dec. 30, 2018USD ($) | Feb. 09, 2018USD ($) | Feb. 08, 2018USD ($) |
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Vesting period | 3 years | |||||||||||||||||||
2024 Notes | $ 533,600,000 | |||||||||||||||||||
Other write-downs and impairment expense | $ 0 | $ 0 | ||||||||||||||||||
Liability for uncertain tax positions | $ 0 | $ 0 | $ 0 | 0 | 0 | |||||||||||||||
Income tax penalties and interest | 0 | 0 | ||||||||||||||||||
Investment in LLC — cost | 9,000,000 | $ 9,000,000 | ||||||||||||||||||
Net loss | $ 34,571,000 | 2,037,170,000 | $ (17,844,000) | $ 22,477,000 | $ 35,733,000 | $ 22,163,000 | $ (15,620,000) | $ (29,430,000) | 2,076,374,000 | 2,000,000,000 | ||||||||||
Current liabilities in excess of current assets | 68,500,000 | $ 68,500,000 | $ 68,500,000 | |||||||||||||||||
Base Price Per Unit for Crude Oil | $ / bbl | 40 | 65.56 | ||||||||||||||||||
Minimum | Other Property And Equipment | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Depreciable life of property and equipment | 3 years | |||||||||||||||||||
Maximum | Other Property And Equipment | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Depreciable life of property and equipment | 7 years | |||||||||||||||||||
7.875% Senior Unsecured Notes Due 2024 | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
2024 Notes | 500,000,000 | $ 500,000,000 | $ 500,000,000 | |||||||||||||||||
Alta Mesa Holdings LP | 7.875% Senior Unsecured Notes Due 2024 | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
2024 Notes | 500,000,000 | 500,000,000 | 500,000,000 | |||||||||||||||||
Alta Mesa Holdings LP | 7.875% Senior Unsecured Notes Due 2024 | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
2024 Notes | 500,000,000 | 500,000,000 | 500,000,000 | |||||||||||||||||
Fair value of senior notes payable | 533,600,000 | 533,600,000 | 533,600,000 | |||||||||||||||||
ASU 2016-02 | Forecast | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Lease liability | $ 20,000,000 | |||||||||||||||||||
Right-of-use asset | $ 20,000,000 | |||||||||||||||||||
Subsequent Event | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Unsecured Debt | $ 500,000,000 | |||||||||||||||||||
Subsequent Event | Forecast | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Periodic interest payment | $ 20,000,000 | |||||||||||||||||||
AMR | Common Class A | Subsequent Event | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Common stock par value (in dollars per share) | $ / shares | $ 1 | |||||||||||||||||||
Alta Mesa Credit Facility | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Credit facility amount | $ 400,000,000 | $ 400,000,000 | $ 400,000,000 | $ 370,000,000 | $ 1,000,000,000 | |||||||||||||||
Alta Mesa Credit Facility | Subsequent Event | ||||||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||||||||
Credit facility amount | $ 370,000,000 | |||||||||||||||||||
Credit facility amount drew | $ 70,000,000 |
Impairment of Assets (Details)
Impairment of Assets (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |||||
Impairment of unproved properties | $ 742,065 | ||||
Impairment of proved properties | 1,291,647 | ||||
Total impairment of assets | $ 2,033,712 | ||||
Predecessor | |||||
Segment Reporting Information [Line Items] | |||||
Impairment of unproved properties | $ 0 | $ 0 | $ 16 | ||
Impairment of proved properties | 0 | 1,188 | 366 | ||
Total impairment of assets | $ 0 | $ 1,188 | $ 382 | ||
Proved And Unproved Oil and Gas Properties | |||||
Segment Reporting Information [Line Items] | |||||
Total impairment of assets | $ 2,000,000 |
Receivables (Schedule of Accoun
Receivables (Schedule of Accounts Receivable) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Production sales | $ 31,532 | |
Joint interest billings | 18,147 | |
Pooling interest | 18,786 | |
Allowance for doubtful accounts | (95) | |
Accounts receivable, net | $ 68,370 | |
Predecessor | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Production sales | $ 26,916 | |
Joint interest billings | 13,821 | |
Pooling interest | 35,839 | |
Allowance for doubtful accounts | (415) | |
Accounts receivable, net | $ 76,161 |
Receivables (Allowance for doub
Receivables (Allowance for doubtful accounts) (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Mar. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Charged to expense | $ 22,438 | ||||
Predecessor | |||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Charged to expense | $ 0 | $ 0 | $ 0 | ||
Trade receivables | |||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Balance at beginning of period | $ 95 | 415 | |||
Charged to expense | 25 | ||||
Deductions | (345) | ||||
Balance at end of period | 415 | 95 | |||
Trade receivables | Predecessor | |||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Balance at beginning of period | 415 | 415 | 490 | 1,030 | |
Charged to expense | 0 | (69) | 243 | ||
Deductions | 0 | (6) | (783) | ||
Balance at end of period | 415 | 415 | 490 | ||
Related party receivables | |||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Balance at beginning of period | 22,438 | 0 | |||
Charged to expense | 22,438 | ||||
Deductions | 0 | ||||
Balance at end of period | 0 | 22,438 | |||
Related party receivables | Predecessor | |||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Balance at beginning of period | 0 | 0 | 0 | 0 | |
Charged to expense | 0 | 0 | 0 | ||
Deductions | 0 | 0 | 0 | ||
Balance at end of period | $ 0 | $ 0 | $ 0 | ||
High Mesa | |||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Accounts receivable, related party | 23,400 | ||||
Subsequent Event | High Mesa | |||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Accounts receivable, related party | 22,400 | ||||
Payment received | 1,000 | ||||
General and Administrative Expense | High Mesa | |||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||||
Balance at beginning of period | $ 22,400 | ||||
Balance at end of period | $ 22,400 |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Supplemental Disclosures to the Consolidated Statements of Cash Flows) (Details) - USD ($) | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental cash flow information: | ||||
Cash paid for interest | $ 47,862,000 | |||
Cash paid for state income taxes, net of refunds | 4,000 | |||
Non-cash investing and financing activities: | ||||
Increase in asset retirement obligations | 5,665,000 | |||
Asset retirement obligations assumed on purchased properties | 0 | |||
Increase in accruals or payables for capital expenditures | 5,389,000 | |||
Increase in accounts payable to related party for capital expenditures | 4,082,000 | |||
Increase in withholding tax accruals for share-based compensation | $ 0 | 535,000 | $ 0 | $ 0 |
Distribution of non-STACK assets, net of liabilities | 0 | |||
Contribution of interests in oil and gas properties | 0 | 65,700,000 | ||
Contribution receivable | $ 0 | |||
Predecessor | ||||
Supplemental cash flow information: | ||||
Cash paid for interest | 1,145,000 | 47,773,000 | 74,694,000 | |
Cash paid for state income taxes, net of refunds | 0 | 0 | 285,000 | |
Non-cash investing and financing activities: | ||||
Increase in asset retirement obligations | 0 | 4,363,000 | 2,719,000 | |
Asset retirement obligations assumed on purchased properties | 0 | 702,000 | 0 | |
Increase in accruals or payables for capital expenditures | 4,896,000 | 71,995,000 | 12,375,000 | |
Increase in accounts payable to related party for capital expenditures | 0 | 7,646,000 | 0 | |
Distribution of non-STACK assets, net of liabilities | 43,482,000 | 0 | 0 | |
Contribution of interests in oil and gas properties | 0 | 0 | 65,740,000 | |
Contribution receivable | $ 0 | $ 0 | $ 7,875,000 |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information (Cash and Restricted Cash) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Feb. 08, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Summary Of Significant Accounting Policies [Line Items] | |||||
Cash and cash equivalents | $ 12,984 | ||||
Restricted cash | 1,001 | ||||
Cash from discontinued operations | 0 | ||||
Total cash, cash equivalents and restricted cash | $ 13,985 | $ 10,345 | |||
Predecessor | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Cash and cash equivalents | 9,070 | $ 3,660 | $ 7,102 | ||
Restricted cash | 1,275 | 1,269 | 433 | ||
Cash from discontinued operations | 0 | 61 | 83 | ||
Total cash, cash equivalents and restricted cash | $ 10,345 | $ 4,990 | $ 7,618 | $ 8,974 |
Significant Acquisitions and _3
Significant Acquisitions and Divestitures (Narrative) (Details) $ in Thousands | Feb. 09, 2018USD ($) | Oct. 31, 2018USD ($) | Sep. 30, 2017USD ($) | Jul. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2016USD ($)well | Dec. 31, 2017USD ($) |
Business Acquisition [Line Items] | |||||||
Contribution of interests in oil and gas properties | $ 0 | $ 65,700 | |||||
Cash contributions | 11,300 | ||||||
Cash collected | 7,900 | ||||||
Alta Mesa Holdings GP, LLC | |||||||
Business Acquisition [Line Items] | |||||||
Contribution to affiliates | $ 554,000 | ||||||
Fenter Energy, LLC | |||||||
Business Acquisition [Line Items] | |||||||
Cash | $ 22,300 | ||||||
B&B Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Cash | $ 8,200 | ||||||
Total fair value assets acquired | 9,900 | ||||||
Bargain purchase gain | $ 1,700 | ||||||
Undeveloped Leasehold In Oklahoma | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration for undeveloped leasehold | $ 10,600 | ||||||
SRII Opco, LP | Alta Mesa RBL | |||||||
Business Acquisition [Line Items] | |||||||
Economic interests | 100.00% | ||||||
Voting interests | 90.00% | ||||||
Weeks Island Field, Louisiana | Disposed of by Sale | |||||||
Business Acquisition [Line Items] | |||||||
Initial net proceeds | $ 22,500 | ||||||
Oklahoma | Unproved Leasehold | |||||||
Business Acquisition [Line Items] | |||||||
Adjusted cost of business acquisition | $ 45,600 | ||||||
High Mesa | |||||||
Business Acquisition [Line Items] | |||||||
Number of wells | well | 24 |
Significant Acquisitions and _4
Significant Acquisitions and Divestitures (Purchase Consideration) (Details) - USD ($) $ / shares in Units, $ in Thousands | Feb. 09, 2018 | Apr. 30, 2018 | Dec. 31, 2018 |
Silver Run Acquisition Corporation Opco Lp | Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
Contingent consideration, term | 7 years | ||
Economic interests | 100.00% | ||
Voting interests | 90.00% | ||
AM Contributor | |||
Business Acquisition [Line Items] | |||
Common units (in shares) | 1,197,934 | ||
Silver Run Acquisition Corporation Opco Lp | Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
SRII Opco Common Units issued | $ 1,261,249 | ||
Estimated fair value of contingent earn-out purchase consideration | 284,109 | ||
Total consideration paid | $ 1,545,358 | ||
Common stock par value (in dollars per share) | $ 7.90 | ||
Silver Run Acquisition Corporation Opco Lp | AM Contributor | Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
Common units (in shares) | 138,402,398 | ||
Silver Run Acquisition Corporation Opco Lp | Riverstone Contributor Agreement | Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
Common units (in shares) | 20,000,000 | ||
As initially reported | Silver Run Acquisition Corporation Opco Lp | Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
SRII Opco Common Units issued | $ 1,251,782 | ||
Estimated fair value of contingent earn-out purchase consideration | 284,109 | ||
Total consideration paid | 1,535,891 | ||
Adjustment | Silver Run Acquisition Corporation Opco Lp | Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
SRII Opco Common Units issued | 9,467 | ||
Total consideration paid | $ 9,467 |
Significant Acquisitions and _5
Significant Acquisitions and Divestitures (Allocation Of Purchase Consideration) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Feb. 09, 2018 | Dec. 31, 2017 |
Business Acquisition [Line Items] | |||
2024 Notes | $ 533,600 | ||
Credit facility amount outstanding | 134,100 | ||
7.875% Senior Unsecured Notes Due 2024 | |||
Business Acquisition [Line Items] | |||
2024 Notes | $ 500,000 | ||
Stated interest rate of senior notes | 7.875% | 7.875% | |
Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
Cash, cash equivalents and restricted cash | 10,345 | ||
Accounts receivable | 101,745 | ||
Other receivables | 2,062 | ||
Receivables due from related party | 907 | ||
Prepaid expenses and other | 1,405 | ||
Derivatives | 352 | ||
oil and gas properties, successful efforts | 2,309,979 | ||
Other property and equipment, net | 43,318 | ||
Notes receivable due from related party | 12,454 | ||
Deposits and other long-term assets | 10,286 | ||
Total fair value of assets acquired | 2,492,853 | ||
Accounts payable and accrued liabilities | 197,361 | ||
Accounts payable — affiliate | 5,476 | ||
Advances from non-operators | 6,803 | ||
Advances from related party | 47,506 | ||
Asset retirement obligations | 5,998 | ||
Derivatives | 11,585 | ||
Long-term debt | 667,700 | ||
Other long-term liabilities | 5,066 | ||
Total fair value of liabilities assumed | 947,495 | ||
Total consideration and fair value | 1,545,358 | ||
Alta Mesa RBL | 7.875% Senior Unsecured Notes Due 2024 | |||
Business Acquisition [Line Items] | |||
2024 Notes | $ 500,000 | ||
Fair value of senior notes payable | $ 533,600 | ||
Alta Mesa RBL | 7.875% Senior Unsecured Notes Due 2024 | Level 1 | |||
Business Acquisition [Line Items] | |||
Fair value of senior notes payable | 533,600 | ||
As initially reported | Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
Cash, cash equivalents and restricted cash | 10,345 | ||
Accounts receivable | 101,745 | ||
Other receivables | 1,222 | ||
Receivables due from related party | 907 | ||
Prepaid expenses and other | 1,405 | ||
Derivatives | 352 | ||
oil and gas properties, successful efforts | 2,314,858 | ||
Other property and equipment, net | 43,318 | ||
Notes receivable due from related party | 12,454 | ||
Deposits and other long-term assets | 10,286 | ||
Total fair value of assets acquired | 2,496,892 | ||
Accounts payable and accrued liabilities | 210,867 | ||
Accounts payable — affiliate | 5,476 | ||
Advances from non-operators | 6,803 | ||
Advances from related party | 47,506 | ||
Asset retirement obligations | 5,998 | ||
Derivatives | 11,585 | ||
Long-term debt | 667,700 | ||
Other long-term liabilities | 5,066 | ||
Total fair value of liabilities assumed | 961,001 | ||
Total consideration and fair value | 1,535,891 | ||
Adjustment | Alta Mesa RBL | |||
Business Acquisition [Line Items] | |||
Cash, cash equivalents and restricted cash | 0 | ||
Accounts receivable | 0 | ||
Other receivables | 840 | ||
Receivables due from related party | 0 | ||
Prepaid expenses and other | 0 | ||
Derivatives | 0 | ||
oil and gas properties, successful efforts | (4,879) | ||
Other property and equipment, net | 0 | ||
Notes receivable due from related party | 0 | ||
Deposits and other long-term assets | 0 | ||
Total fair value of assets acquired | (4,039) | ||
Accounts payable and accrued liabilities | (13,506) | ||
Accounts payable — affiliate | 0 | ||
Advances from non-operators | 0 | ||
Advances from related party | 0 | ||
Asset retirement obligations | 0 | ||
Derivatives | 0 | ||
Long-term debt | 0 | ||
Other long-term liabilities | 0 | ||
Total fair value of liabilities assumed | (13,506) | ||
Total consideration and fair value | $ 9,467 |
Property and Equipment (Summary
Property and Equipment (Summary of Property and Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Property, Plant and Equipment [Line Items] | ||
Unproved properties | $ 816,282 | |
Accumulated impairment of unproved properties | (742,065) | |
Unproved properties, net | 74,217 | |
Proved oil and gas properties | 2,110,346 | |
Accumulated depreciation, depletion, amortization and impairment | (1,421,226) | |
Proved oil and gas properties, net | 689,120 | |
Total oil and gas properties, net | 763,337 | |
Land | 5,059 | |
Fresh water wells | 27,366 | |
Produced water disposal system | 3,608 | |
Office furniture, equipment and vehicles | 2,840 | |
Accumulated depreciation | (726) | |
Other property and equipment, net | 38,147 | |
Total property and equipment, net | $ 801,484 | |
Predecessor | ||
Property, Plant and Equipment [Line Items] | ||
Unproved properties | $ 84,590 | |
Accumulated impairment of unproved properties | 0 | |
Unproved properties, net | 84,590 | |
Proved oil and gas properties | 1,061,105 | |
Accumulated depreciation, depletion, amortization and impairment | (251,065) | |
Proved oil and gas properties, net | 810,040 | |
Total oil and gas properties, net | 894,630 | |
Land | 2,912 | |
Fresh water wells | 0 | |
Produced water disposal system | 30,990 | |
Office furniture, equipment and vehicles | 20,008 | |
Accumulated depreciation | (21,770) | |
Other property and equipment, net | 32,140 | |
Total property and equipment, net | $ 926,770 |
Property and Equipment (Depreci
Property and Equipment (Depreciation and Depletion Expense) (Details) - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | ||||
Oil and gas properties depletion | $ 130,439 | |||
Other property and equipment depreciation | 2,375 | |||
Total depreciation and depletion expense | $ 132,814 | |||
Predecessor | ||||
Property, Plant and Equipment [Line Items] | ||||
Oil and gas properties depletion | $ 11,021 | $ 83,537 | $ 49,481 | |
Other property and equipment depreciation | 609 | 5,240 | 4,004 | |
Total depreciation and depletion expense | $ 11,630 | $ 88,777 | $ 53,485 |
Property and Equipment Property
Property and Equipment Property and Equipment (Sale of Produced Water Assets) (Details) - KFM - Affiliated Entity $ in Millions | Nov. 09, 2018USD ($)well | Dec. 31, 2018USD ($) |
Property, Plant and Equipment [Line Items] | ||
Number of produced water disposal wells sold | well | 20 | |
Proceeds from sale of business | $ 98 | |
Proceeds from sale of water systems | $ 90 | |
Accounts receivable, related party | $ 8 | |
Initial term | 15 years | |
Expenses recognized | $ 4.7 |
Discontinued Operations (Pred_3
Discontinued Operations (Predecessor) (Narrative) (Details) - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Paid-in-Kind Interest | $ 0 | |||
Predecessor | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Paid-in-Kind Interest | $ (103) | $ (1,209) | $ (1,209) | |
Predecessor | Notes Payable To Founder | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Effective rate of interest | 10.00% | |||
Notes payable to founder | $ 28,300 | |||
Paid-in-Kind Interest | $ (100) | $ (1,200) | $ (1,200) |
Discontinued Operations (Pred_4
Discontinued Operations (Predecessor) (Schedule of Operations and Other Items Reclassified n Discontinued Operations) (Details) - Predecessor - Weeks Island Field, Louisiana - Non Stack Assets - Disposed of by Sale - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue: | |||
Oil | $ 1,617 | $ 47,218 | $ 57,866 |
Natural gas | 1,023 | 10,090 | 10,932 |
Natural gas liquids | 236 | 2,359 | 1,489 |
Other | 16 | 316 | 213 |
Operating revenue | 2,892 | 59,983 | 70,500 |
Loss on sale of assets | (1,923) | (22,207) | 3,539 |
Gain on acquisition of oil and gas properties | 0 | 1,626 | 0 |
Total revenue | 969 | 39,402 | 74,039 |
Operating expenses: | |||
Lease operating | 1,770 | 27,763 | 29,474 |
Transportation and marketing | 83 | 1,354 | 1,698 |
Production taxes | 167 | 6,730 | 7,985 |
Workover | 127 | 2,088 | 1,273 |
Exploration | 0 | 11,431 | 7,547 |
Depreciation, depletion and amortization | 884 | 24,519 | 41,320 |
Impairments of assets | 5,560 | 29,129 | 15,924 |
General and administrative | 21 | 82 | 1,290 |
Total operating expenses | 8,612 | 103,096 | 106,511 |
Interest expense | (103) | (1,209) | (1,209) |
Interest income and other | 0 | 88 | 10 |
Total other income (expense) | (103) | (1,121) | (1,199) |
Income tax provision (benefit) | 0 | 0 | (29) |
Loss from discontinued operations, net of state income taxes | $ (7,746) | $ (64,815) | $ (33,642) |
Discontinued Operations (Pred_5
Discontinued Operations (Predecessor) (Schedule of Assets and Liabilities Reclassified in Discontinued Operation) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets associated with discontinued operations: | ||
Current assets — discontinued operations | $ 0 | |
Noncurrent assets | ||
Total noncurrent assets | 0 | |
Current liabilities | ||
Asset retirement obligations | 0 | |
Noncurrent liabilities | ||
Total noncurrent liabilities | $ 0 | |
Predecessor | ||
Current assets associated with discontinued operations: | ||
Current assets — discontinued operations | $ 5,195 | |
Noncurrent assets | ||
Total noncurrent assets | 43,785 | |
Current liabilities | ||
Asset retirement obligations | 15,419 | |
Noncurrent liabilities | ||
Total noncurrent liabilities | 66,862 | |
Non Stack Assets | Predecessor | Weeks Island Field, Louisiana | Disposed of by Sale | ||
Current assets associated with discontinued operations: | ||
Cash | 61 | |
Accounts receivable | 4,980 | |
Other receivables | 154 | |
Current assets — discontinued operations | 5,195 | |
Noncurrent assets | ||
Investments | 9,000 | |
Proved oil and gas properties, net | 33,618 | |
Other long-term assets | 1,167 | |
Total noncurrent assets | 43,785 | |
Total assets associated with discontinued operations | 48,980 | |
Current liabilities | ||
Accounts payable and accrued liabilities | 7,882 | |
Asset retirement obligations | 7,537 | |
Asset retirement obligations | 15,419 | |
Noncurrent liabilities | ||
Asset retirement obligations, net of current portion | 37,049 | |
Founder Notes | 28,166 | |
Other long-term liabilities | 1,647 | |
Total noncurrent liabilities | 66,862 | |
Total liabilities associated with discontinued operations | $ 82,281 |
Discontinued Operations (Pred_6
Discontinued Operations (Predecessor) (Total Operating and Investing Cash Flows of Discontinued Operations) (Details) - Predecessor - Weeks Island Field, Louisiana - Disposed of by Sale - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Total operating cash flows of discontinued operations | $ 2,974 | $ 21,138 | $ 31,255 |
Total investing cash flows of discontinued operations | $ (601) | $ 6,891 | $ (14,378) |
Fair Value Disclosures (Narrati
Fair Value Disclosures (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Feb. 09, 2018 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
2024 Notes | $ 533.6 | |
Alta Mesa RBL | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value of senior notes | $ 312.5 | $ 533.6 |
Fair Value Disclosures (Non-rec
Fair Value Disclosures (Non-recurring Measurements) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Original Carrying Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unproved oil and gas properties | $ 816,282 | |
Proved oil and gas properties | 1,895,670 | |
Total | 2,711,952 | |
Original Carrying Value | Predecessor | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unproved oil and gas properties | $ 0 | |
Proved oil and gas properties | 3,350 | |
Total | 3,350 | |
Estimated Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unproved oil and gas properties | 74,217 | |
Proved oil and gas properties | 604,023 | |
Total | 678,240 | |
Estimated Fair Value | Predecessor | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unproved oil and gas properties | 0 | |
Proved oil and gas properties | 2,162 | |
Total | 2,162 | |
Impairment | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unproved oil and gas properties | 742,065 | |
Proved oil and gas properties | 1,291,647 | |
Total | $ 2,033,712 | |
Impairment | Predecessor | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unproved oil and gas properties | 0 | |
Proved oil and gas properties | 1,188 | |
Total | $ 1,188 |
Derivatives (Fair Values of Der
Derivatives (Fair Values of Derivative Contracts) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Derivatives, Fair Value [Line Items] | ||
Gross fair value of assets | $ 30,422 | $ 4,416 |
Gross liabilities offset against assets in the Balance Sheet | (11,052) | (4,192) |
Net fair value of assets presented in the Balance Sheet | 19,370 | 224 |
Gross fair value of liabilities | 12,942 | 24,609 |
Gross assets offset against liabilities in the Balance Sheet | (11,052) | (4,192) |
Net fair value of liabilities presented in the Balance Sheet | 1,890 | 20,417 |
Derivatives, current assets | ||
Derivatives, Fair Value [Line Items] | ||
Gross fair value of assets | 22,512 | 1,406 |
Gross liabilities offset against assets in the Balance Sheet | (6,089) | (1,190) |
Net fair value of assets presented in the Balance Sheet | 16,423 | 216 |
Derivatives, long-term assets | ||
Derivatives, Fair Value [Line Items] | ||
Gross fair value of assets | 7,910 | 3,010 |
Gross liabilities offset against assets in the Balance Sheet | (4,963) | (3,002) |
Net fair value of assets presented in the Balance Sheet | 2,947 | 8 |
Derivatives, current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Gross fair value of liabilities | 7,799 | 20,493 |
Gross assets offset against liabilities in the Balance Sheet | (6,089) | (1,190) |
Net fair value of liabilities presented in the Balance Sheet | 1,710 | 19,303 |
Derivatives, long-term liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Gross fair value of liabilities | 5,143 | 4,116 |
Gross assets offset against liabilities in the Balance Sheet | (4,963) | (3,002) |
Net fair value of liabilities presented in the Balance Sheet | $ 180 | $ 1,114 |
Derivatives (Effect of Derivati
Derivatives (Effect of Derivative Instruments in the Consolidated Statements of Operations) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 11 Months Ended | 12 Months Ended | |||||||
Feb. 08, 2018 | Mar. 31, 2018 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | $ (22,600) | $ 52,800 | $ (11,200) | $ (29,200) | $ (29,700) | $ (10,500) | $ 18,300 | $ 30,200 | $ (10,247) | |||
Predecessor | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | $ 6,663 | $ 8,287 | $ (40,460) | |||||||||
Derivatives Not Designated As Hedging | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | (10,247) | |||||||||||
Derivatives Not Designated As Hedging | Oil commodity contracts | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | (3,559) | |||||||||||
Derivatives Not Designated As Hedging | Natural gas commodity contracts | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | (6,688) | |||||||||||
Derivatives Not Designated As Hedging | Natural gas liquids commodity contracts | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | $ 0 | |||||||||||
Derivatives Not Designated As Hedging | Predecessor | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | 6,663 | 8,287 | (40,460) | |||||||||
Derivatives Not Designated As Hedging | Predecessor | Oil commodity contracts | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | 4,796 | 1,450 | (36,572) | |||||||||
Derivatives Not Designated As Hedging | Predecessor | Natural gas commodity contracts | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | 1,867 | 7,288 | (2,410) | |||||||||
Derivatives Not Designated As Hedging | Predecessor | Natural gas liquids commodity contracts | ||||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||||||||
Total gains (loss) on derivative contracts | $ 0 | $ (451) | $ (1,478) |
Derivatives (Additional Informa
Derivatives (Additional Information) (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Contracts To be Settled January 2019 | ||
Derivative [Line Items] | ||
Derivative contracts | $ 1.3 | $ 1.4 |
Derivatives (Oil Derivative Con
Derivatives (Oil Derivative Contracts) (Details) - Oil Derivative Contracts | 12 Months Ended |
Dec. 31, 2018$ / bblbbl | |
Price Swap Contracts | 2019 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 182,500 |
Weighted Average Swap Price (USD per unit) | 63.03 |
Price Swap Contracts | 2019 | Maximum | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 63.03 |
Price Swap Contracts | 2019 | Minimum | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 63.03 |
Short Call Options | 2019 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 2,701,000 |
Weighted Average Option Price (USD per unit) | 66.31 |
Short Call Options | 2019 | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 75.20 |
Short Call Options | 2019 | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 56.50 |
Short Call Options | 2020 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 585,600 |
Weighted Average Option Price (USD per unit) | 64.32 |
Short Call Options | 2020 | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 73.80 |
Short Call Options | 2020 | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 59.55 |
Long Put Options | 2019 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 2,883,500 |
Weighted Average Option Price (USD per unit) | 53.80 |
Long Put Options | 2019 | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 62 |
Long Put Options | 2019 | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 50 |
Long Put Options | 2020 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,537,200 |
Weighted Average Option Price (USD per unit) | 55.54 |
Long Put Options | 2020 | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 62.50 |
Long Put Options | 2020 | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 50 |
Short Put Options | 2019 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 2,883,500 |
Weighted Average Option Price (USD per unit) | 42.72 |
Short Put Options | 2019 | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 52 |
Short Put Options | 2019 | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 37.50 |
Short Put Options | 2020 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,537,200 |
Weighted Average Option Price (USD per unit) | 44.64 |
Short Put Options | 2020 | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 50 |
Short Put Options | 2020 | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 37.50 |
Derivatives (Natural Gas Deriva
Derivatives (Natural Gas Derivative Contracts) (Details) - Natural Gas Derivative Contract | 12 Months Ended |
Dec. 31, 2018MMBTU$ / MMBTU | |
2019 | Price Swap Contracts | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 10,905,000 |
Weighted Average Swap Price (USD per unit) | 2.69 |
2019 | Price Swap Contracts | Maximum | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 3.09 |
2019 | Price Swap Contracts | Minimum | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 2.64 |
2019 | Short Call Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 4,000,000 |
Weighted Average Option Price (USD per unit) | 3.31 |
2019 | Short Call Options | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.75 |
2019 | Short Call Options | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.17 |
2019 | Long Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 3,550,000 |
Weighted Average Option Price (USD per unit) | 2.81 |
2019 | Long Put Options | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.90 |
2019 | Long Put Options | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.70 |
2019 | Short Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 2,425,000 |
Weighted Average Option Price (USD per unit) | 2.27 |
2019 | Short Put Options | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.40 |
2019 | Short Put Options | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.20 |
2020 | Short Call Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 2,275,000 |
Weighted Average Option Price (USD per unit) | 3.19 |
2020 | Short Call Options | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.20 |
2020 | Short Call Options | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.17 |
2020 | Long Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 9,150,000 |
Weighted Average Option Price (USD per unit) | 2.57 |
2020 | Long Put Options | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.70 |
2020 | Long Put Options | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.50 |
2020 | Short Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 9,150,000 |
Weighted Average Option Price (USD per unit) | 2.07 |
2020 | Short Put Options | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.20 |
2020 | Short Put Options | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2 |
2021 | Long Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 2,250,000 |
Weighted Average Option Price (USD per unit) | 2.65 |
2021 | Long Put Options | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.65 |
2021 | Long Put Options | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.65 |
2021 | Short Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 2,250,000 |
Weighted Average Option Price (USD per unit) | 2.15 |
2021 | Short Put Options | Maximum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.15 |
2021 | Short Put Options | Minimum | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.15 |
Derivatives (Basis Swap Derivat
Derivatives (Basis Swap Derivative Contracts) (Details) - Natural Gas Basis Swap Derivative Contracts | 12 Months Ended |
Dec. 31, 2018MMBTU$ / MMBTU | |
Jul 19 - Dec 19 | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 460,000 |
Weighted average spread | $ / MMBTU | (0.93) |
Jan 19 - Dec 19 | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 17,950,000 |
Weighted average spread | $ / MMBTU | (0.68) |
Jan 20 - Mar 20 | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 910,000 |
Weighted average spread | $ / MMBTU | (0.49) |
Jan 19 - Oct 19 | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 2,365,000 |
Weighted average spread | $ / MMBTU | (0.78) |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | ||
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation [Line Items] | |||||
Balance, beginning of period | $ 5,998 | ||||
Liabilities assumed | 0 | ||||
Liabilities incurred | 2,536 | ||||
Liabilities settled | (1,610) | ||||
Liabilities transferred via sale | (383) | ||||
Revisions to estimates | 4,130 | ||||
Accretion expense | (738) | ||||
Balance, end of period | 5,998 | $ 11,409 | |||
Less: Current portion | 2,079 | ||||
Long-term portion | $ 9,330 | ||||
Predecessor | |||||
Asset Retirement Obligation [Line Items] | |||||
Balance, beginning of period | $ 10,469 | 10,508 | $ 8,400 | ||
Liabilities assumed | 604 | ||||
Liabilities incurred | 1,583 | ||||
Liabilities settled | (63) | (119) | |||
Liabilities transferred via sale | 0 | ||||
Revisions to estimates | 63 | (337) | |||
Accretion expense | (39) | (338) | |||
Balance, end of period | $ 10,469 | $ 10,508 | $ 8,400 | $ 10,469 | |
Less: Current portion | 69 | ||||
Long-term portion | $ 10,400 | ||||
Asset retirement obligation, interest rate | 10.20% | ||||
Minimum | |||||
Asset Retirement Obligation [Line Items] | |||||
Asset retirement obligation, interest rate | 4.40% | ||||
Maximum | |||||
Asset Retirement Obligation [Line Items] | |||||
Asset retirement obligation, interest rate | 8.80% |
Long Term Debt, Net (Schedule o
Long Term Debt, Net (Schedule of Long-Term Debt, Net) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Feb. 09, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | |||
Credit facility amount outstanding | $ 134,100 | ||
2024 Notes | $ 533,600 | ||
Unamortized deferred financing costs | $ 0 | ||
Total long-term debt, net | 690,123 | ||
2024 Notes | |||
Debt Instrument [Line Items] | |||
2024 Notes | 500,000 | ||
Unamortized premium on 2024 notes | |||
Debt Instrument [Line Items] | |||
Unamortized premium on 2024 notes | 29,123 | ||
Alta Mesa RBL | 2024 Notes | |||
Debt Instrument [Line Items] | |||
2024 Notes | 500,000 | ||
Alta Mesa Predecessor Credit Facility | |||
Debt Instrument [Line Items] | |||
Credit facility amount outstanding | 0 | ||
Predecessor | |||
Debt Instrument [Line Items] | |||
Unamortized deferred financing costs | $ (9,625) | ||
Total long-term debt, net | 607,440 | ||
Predecessor | 2024 Notes | |||
Debt Instrument [Line Items] | |||
2024 Notes | 500,000 | ||
Predecessor | Unamortized premium on 2024 notes | |||
Debt Instrument [Line Items] | |||
Unamortized premium on 2024 notes | 0 | ||
Predecessor | Alta Mesa Predecessor Credit Facility | |||
Debt Instrument [Line Items] | |||
Credit facility amount outstanding | 117,065 | ||
Alta Mesa RBL | Alta Mesa RBL | |||
Debt Instrument [Line Items] | |||
Credit facility amount outstanding | $ 161,000 | ||
Alta Mesa RBL | Predecessor | Alta Mesa RBL | |||
Debt Instrument [Line Items] | |||
Credit facility amount outstanding | $ 0 |
Long Term Debt, Net (Narrative)
Long Term Debt, Net (Narrative) (Details) | 1 Months Ended | 11 Months Ended | 12 Months Ended | |||||||
Feb. 08, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Apr. 01, 2019USD ($) | Dec. 30, 2018USD ($) | Sep. 30, 2018 | Apr. 30, 2018USD ($) | Feb. 09, 2018USD ($) | |
Debt Instrument [Line Items] | ||||||||||
Deferred financing costs | $ 0 | $ 0 | ||||||||
2024 Notes | $ 533,600,000 | |||||||||
Amortization of deferred financing costs | 221,000 | |||||||||
Senior secured revolving credit facility | 134,100,000 | |||||||||
Amortization of debt (premium) discount | (4,512,000) | |||||||||
7.875% Senior Unsecured Notes Due 2024 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
2024 Notes | $ 500,000,000 | $ 500,000,000 | ||||||||
Stated interest rate of senior notes | 7.875% | 7.875% | 7.875% | |||||||
Alta Mesa Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Credit facility borrowing base | $ 350,000,000 | |||||||||
Debt covenant, current ratio, minimum required | 1 | 1 | ||||||||
Letter of credit outstanding | $ 21,900,000 | $ 21,900,000 | ||||||||
Maximum leverage ratio | 4 | |||||||||
Deferred financing costs | 1,400,000 | $ 1,400,000 | ||||||||
Credit facility amount | 1,000,000,000 | 400,000,000 | $ 400,000,000 | $ 370,000,000 | ||||||
Alta Mesa Credit Facility | Federal Funds Effective Swap Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Margin interest rate | 0.50% | |||||||||
Alta Mesa Credit Facility | Minimum | Federal Funds Effective Swap Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Additional basis spread on variable rate | 1.00% | |||||||||
Alta Mesa Credit Facility | Minimum | Eurodollar | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Margin interest rate | 2.00% | |||||||||
Alta Mesa Credit Facility | Maximum | Federal Funds Effective Swap Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Additional basis spread on variable rate | 2.00% | |||||||||
Alta Mesa Credit Facility | Maximum | Eurodollar | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Margin interest rate | 3.00% | |||||||||
Eighth A&R Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of Credit Facility, Remaining borrowing capacity | 217,094 | $ 217,094 | ||||||||
Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Unamortized premium on 2024 notes | 33,600,000 | |||||||||
Predecessor | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Deferred financing costs | $ 9,625,000 | |||||||||
Amortization of deferred financing costs | 171,000 | 2,700,000 | 2,732,000 | $ 3,905,000 | ||||||
Amortization of debt (premium) discount | $ 0 | 0 | $ 468,000 | |||||||
Predecessor | Credit Facility, Term Loan Facility And Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Deferred financing costs | $ 0 | |||||||||
Predecessor | 7.875% Senior Unsecured Notes Due 2024 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
2024 Notes | 500,000,000 | |||||||||
Alta Mesa Predecessor Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Senior secured revolving credit facility | 0 | $ 0 | ||||||||
Alta Mesa Predecessor Credit Facility | Predecessor | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Senior secured revolving credit facility | 117,065,000 | |||||||||
Alta Mesa RBL | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Credit facility borrowing base | $ 400,000,000 | |||||||||
Alta Mesa RBL | 7.875% Senior Unsecured Notes Due 2024 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Redemption percentage of Senior Notes | 101.00% | |||||||||
2024 Notes | $ 500,000,000 | $ 500,000,000 | ||||||||
Stated interest rate of senior notes | 7.875% | |||||||||
Alta Mesa RBL | 7.875% Senior Unsecured Notes Due 2024 | Prior to December 2019 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Redemption price | 107.875% | |||||||||
Alta Mesa RBL | Credit Facility and Senior Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Deferred financing cost write-off | $ 11,400,000 | |||||||||
Alta Mesa RBL | Maximum | 7.875% Senior Unsecured Notes Due 2024 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Redemption percentage of Senior Notes | 35.00% | |||||||||
Subsequent Event | Alta Mesa Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Credit facility amount | $ 370,000,000 | |||||||||
Subsequent Event | Alta Mesa RBL | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Credit facility borrowing base | $ 370,000,000 |
Long Term Debt, Net (Redemption
Long Term Debt, Net (Redemptions Prices) (Details) - 7.875% Senior Unsecured Notes Due 2024 - Alta Mesa RBL | 12 Months Ended |
Dec. 31, 2018 | |
2019 | |
Debt Instrument [Line Items] | |
Redemption price due to specific change of control events | 105.906% |
2020 | |
Debt Instrument [Line Items] | |
Redemption price due to specific change of control events | 103.938% |
2021 | |
Debt Instrument [Line Items] | |
Redemption price due to specific change of control events | 101.969% |
Beginning on December 15, 2022 | |
Debt Instrument [Line Items] | |
Redemption price due to specific change of control events | 100.00% |
Long Term Debt, Net (Summary of
Long Term Debt, Net (Summary of Future Maturities of Long-Term Debt) (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Summary of future maturities of long-term debt | |
2019 | $ 0 |
2020 | 0 |
2021 | 0 |
2022 | 0 |
2023 | 161,000 |
Thereafter | 500,000 |
Total long-term debt | $ 661,000 |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts Payable And Accrued Liabilities [Line Items] | ||
Accounts payable | $ 20,200 | |
Accruals for capital expenditures | 101,214 | |
Revenue and royalties payable | 46,870 | |
Accruals for operating expenses | 16,355 | |
Accrued interest | 1,784 | |
Derivative settlements | 109 | |
Other | 10,532 | |
Total accrued liabilities | 176,864 | |
Accounts payable and accrued liabilities | $ 197,064 | |
Predecessor | ||
Accounts Payable And Accrued Liabilities [Line Items] | ||
Accounts payable | $ 68,578 | |
Accruals for capital expenditures | 48,771 | |
Revenue and royalties payable | 29,514 | |
Accruals for operating expenses | 14,632 | |
Accrued interest | 2,587 | |
Derivative settlements | 2,106 | |
Other | 4,301 | |
Total accrued liabilities | 101,911 | |
Accounts payable and accrued liabilities | $ 170,489 |
Commitments and Contingencies_2
Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Commitment And Contingencies [Line Items] | ||||
Rent expense | $ 7,800 | |||
Contractual Obligation | 100 | |||
General and administrative | 114,735 | |||
Predecessor | ||||
Commitment And Contingencies [Line Items] | ||||
Rent expense | $ 100 | $ 7,800 | $ 3,600 | |
General and administrative | $ 21,234 | $ 55,671 | $ 40,468 | |
Performance Shares | ||||
Commitment And Contingencies [Line Items] | ||||
General and administrative | $ 10,900 |
Commitments And Contingencies_3
Commitments And Contingencies (Future Base Rentals For Non-Cancelable Leases) (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Future base rentals for non-cancelable leases | |
2019 | $ 2,819 |
2020 | 2,851 |
2021 | 2,911 |
2022 | 3,107 |
2023 | 3,038 |
Thereafter | 12,219 |
Total future base rental | $ 26,945 |
Commitments And Contingencies_4
Commitments And Contingencies (Firm Delivery Contracts) (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Other Commitments [Line Items] | |
Firm Delivery Contracts | $ 100 |
Firm Delivery Contracts | |
Other Commitments [Line Items] | |
2019 | 1,551 |
2020 | 1,556 |
2021 | 1,551 |
Firm Delivery Contracts | $ 4,658 |
Commitments And Contingencies_5
Commitments And Contingencies (Firm Transportation Contracts) (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2019 | $ 12,236 |
2020 | 12,236 |
2021 | 12,236 |
2022 | 12,236 |
2023 | 12,236 |
Thereafter | 25,023 |
Firm Transportation Contracts | $ 86,203 |
Significant Concentrations (Det
Significant Concentrations (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 11 Months Ended | 12 Months Ended | ||||||||
Feb. 08, 2018 | Mar. 31, 2018 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Concentration Risk [Line Items] | |||||||||||||
Sales | $ 414,507 | ||||||||||||
Revenues | $ 34,090 | $ 185,589 | $ 122,873 | $ 66,459 | $ 46,567 | $ 57,923 | $ 79,800 | $ 95,079 | 409,011 | ||||
ARM | |||||||||||||
Concentration Risk [Line Items] | |||||||||||||
Amount paid for marketing fees | $ 100 | 800 | $ 800 | $ 1,900 | |||||||||
Accounts receivable | $ 38,400 | 38,400 | $ 38,400 | ||||||||||
Sales | 309,700 | 199,200 | 114,800 | ||||||||||
Predecessor | |||||||||||||
Concentration Risk [Line Items] | |||||||||||||
Sales | 40,136 | 269,386 | 142,356 | ||||||||||
Revenues | 47,639 | 279,369 | $ 101,899 | ||||||||||
Predecessor | ARM | |||||||||||||
Concentration Risk [Line Items] | |||||||||||||
Accounts receivable | $ 22,400 | $ 22,400 | |||||||||||
Sales | $ 28,800 | ||||||||||||
ARM | AM Contributor | |||||||||||||
Concentration Risk [Line Items] | |||||||||||||
Concentration risk percentage | 10.00% | ||||||||||||
Marketing fees | |||||||||||||
Concentration Risk [Line Items] | |||||||||||||
Amount paid for marketing fees | $ 1,400 |
Employee Benefit Plans (Details
Employee Benefit Plans (Details) - USD ($) $ in Millions | 1 Months Ended | 11 Months Ended | 12 Months Ended | ||
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Contribution Plan Disclosure [Line Items] | |||||
Percentage of matching contribution by company | 100.00% | ||||
Maximum percentage of employee's salary deferral contribution | 5.00% | ||||
Employer matching contribution, vesting percentage | 50.00% | ||||
Employer matching contribution, vesting term | 2 years | ||||
Matching contributions to the plan | $ 1 | ||||
Predecessor | |||||
Defined Contribution Plan Disclosure [Line Items] | |||||
Matching contributions to the plan | $ 0.3 | $ 1.2 | $ 1.1 |
Partners' Capital (Details)
Partners' Capital (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Alta Mesa Holdings GP, LLC | Common Class A | |
Partners' Capital l[Line Items] | |
Economic interests | 100.00% |
Alta Mesa Holdings GP, LLC | Common Class B | |
Partners' Capital l[Line Items] | |
Voting interests | 100.00% |
Directors And Affiliates Of Bayou City And Highbridge | Alta Mesa Holdings GP, LLC | Common Class B | |
Partners' Capital l[Line Items] | |
Voting interests | 10.00% |
SRII Opco, LP | Alta Mesa Holdings GP, LLC | Common Class B | |
Partners' Capital l[Line Items] | |
Economic interests | 90.00% |
Equity-Based Compensation (Su_3
Equity-Based Compensation (Successor) (Narrative) (Details) $ in Thousands | 11 Months Ended |
Dec. 31, 2018USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares authorized under plan (in shares) | 50,000,000 |
Equity-based compensation expense | $ | $ 20,000 |
Vesting period | 3 years |
Stock options | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Option expiration period | 7 years |
Unrecognized compensation cost | $ | $ 9,800 |
Period for unrecognized compensation cost | 2 years 2 months 9 days |
Restricted Stock Awards | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized compensation cost | $ | $ 7,300 |
Vested restricted stock awards (in shares) | 286,214 |
Granted (shares) | 1,720,949 |
RSUs | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting period | 3 years |
Unrecognized compensation cost | $ | $ 0 |
Vested restricted stock awards (in shares) | 1,559,749 |
Granted (shares) | 2,049,105 |
RSUs | Minimum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Percentage of shares that may be earned | 0.00% |
RSUs | Maximum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Percentage of shares that may be earned | 200.00% |
RSUs | Tranche one | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting rate | 20.00% |
RSUs | Tranche two | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting rate | 30.00% |
RSUs | Tranche three | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting rate | 50.00% |
Equity-Based Compensation (Su_4
Equity-Based Compensation (Successor) (Schedule of Outstanding Stock Options) (Details) $ / shares in Units, $ in Thousands | 11 Months Ended | 12 Months Ended |
Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2018USD ($)$ / sharesshares | |
Stock Options | ||
Outstanding, beginning balance (shares) | shares | 0 | |
Granted (shares) | shares | 4,840,799 | |
Exercised (shares) | shares | 0 | |
Forfeited or expired (shares) | shares | (134,956) | |
Outstanding, ending balance (shares) | shares | 4,705,843 | 4,705,843 |
Vested or expected to vest in future (in shares) | shares | 4,705,843 | 4,705,843 |
Exercisable (shares) | shares | 1,509,434 | 1,509,434 |
Weighted Average Exercise Price | ||
Balance (usd per share) | $ 0 | |
Granted (usd per share) | 8.90 | |
Exercised (usd per share) | 0 | |
Forfeited or expired (usd per share) | 9.37 | |
Balance (usd per share) | 8.89 | $ 8.89 |
Vested or expected to vest in future (usd per share) | 8.89 | 8.89 |
Exercisable (usd per share) | 9.54 | 9.54 |
Weighted Average Grant-Date FV | ||
Outstanding, beginning balance (usd per share) | 0 | |
Granted (usd per share) | 4.37 | |
Forfeited or expired (usd per share) | 4.55 | |
Outstanding, ending balance (usd per share) | 4.36 | 4.36 |
Vested or expected to vest in future (usd per share) | 4.36 | 4.36 |
Exercisable (usd per share) | $ 4.62 | $ 4.62 |
Outstanding, weighted average remaining term | 5 years 2 months 12 days | |
Vested or expected to vest in future, weighted average remaining term | 5 years 2 months 12 days | |
Exercisable, weighted average remaining term | 3 years | |
Outstanding, Aggregate Intrinsic Value | $ | $ 0 | $ 0 |
Exercisable, Aggregate Intrinsic Value | $ | $ 0 | $ 0 |
Equity-Based Compensation (Su_5
Equity-Based Compensation (Successor) (Summary of Assumptions Used to Determine the Fair Value of Options) (Details) - Stock options | 11 Months Ended |
Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Expected term (in years) | 4 years 6 months |
Expected stock volatility | 64.60% |
Dividend yield | 0.00% |
Risk-free interest rate | 2.50% |
Equity-Based Compensation (Su_6
Equity-Based Compensation (Successor) (Schedule of Restricted Stock Awards and PSUs Granted) (Details) | 11 Months Ended |
Dec. 31, 2018$ / sharesshares | |
Restricted Stock Awards | |
Restricted Stock Awards | |
Outstanding, beginning balance (shares) | 0 |
Granted (shares) | 1,720,949 |
Vested (shares) | (286,214) |
Forfeited or expired (shares) | (59,980) |
Outstanding, ending balance (shares) | 1,374,755 |
Weighted Average Grant Date Fair Value per share | |
Outstanding, beginning balance (usd per share) | $ / shares | $ 0 |
Granted (usd per share) | $ / shares | 7.61 |
Vested (usd per share) | $ / shares | 8.38 |
Forfeited or expired (usd per share) | $ / shares | (8.80) |
Outstanding, ending balance (usd per share) | $ / shares | $ 7.39 |
Shares withheld for tax withholding | 94,576 |
RSUs | |
Restricted Stock Awards | |
Outstanding, beginning balance (shares) | 0 |
Granted (shares) | 2,049,105 |
Vested (shares) | (1,559,749) |
Forfeited or expired (shares) | (489,356) |
Outstanding, ending balance (shares) | 0 |
Weighted Average Grant Date Fair Value per share | |
Outstanding, beginning balance (usd per share) | $ / shares | $ 0 |
Granted (usd per share) | $ / shares | 3.99 |
Vested (usd per share) | $ / shares | 2.53 |
Forfeited or expired (usd per share) | $ / shares | (8.61) |
Outstanding, ending balance (usd per share) | $ / shares | $ 0 |
Shares withheld for tax withholding | 388,655 |
Related Party Transactions (Det
Related Party Transactions (Details) | Nov. 09, 2018USD ($)well | Feb. 08, 2018USD ($) | Dec. 31, 2016USD ($) | Feb. 08, 2018USD ($) | Dec. 31, 2018USD ($)well | Mar. 31, 2019USD ($) | Dec. 31, 2018USD ($)well | Dec. 31, 2018USD ($)well | Dec. 31, 2018USD ($)well | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 29, 2017USD ($) | Jan. 13, 2016well |
Related Party Transaction [Line Items] | |||||||||||||
General and administrative | $ 114,735,000 | ||||||||||||
Advances from related party | $ 9,822,000 | $ 9,822,000 | 9,822,000 | $ 9,822,000 | |||||||||
Notes receivable from related party | 0 | 0 | 0 | 0 | |||||||||
Related party receivables | 24,282,000 | 24,282,000 | 24,282,000 | 24,282,000 | |||||||||
Long-term note receivable | 0 | 0 | 0 | 0 | |||||||||
8% long-term note receivable | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Allowance for uncollectible accounts | 13,400,000 | 13,400,000 | 13,400,000 | 13,400,000 | |||||||||
BCE | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Advances from related party | 9,839,000 | 9,839,000 | 9,839,000 | 9,839,000 | |||||||||
NWGP | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Promissory note receivable | $ 1,500,000 | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.00% | ||||||||||||
Notes receivable from related party | 1,700,000 | 1,700,000 | 1,700,000 | 1,700,000 | $ 1,500,000 | ||||||||
Long-term note receivable | $ 11,700,000 | $ 11,700,000 | $ 11,700,000 | $ 11,700,000 | 10,800,000 | ||||||||
HMS | 8% long-term note receivable | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.00% | 8.00% | 8.00% | 8.00% | |||||||||
Related party receivables | $ 8,500,000 | $ 8,500,000 | $ 8,500,000 | $ 8,500,000 | |||||||||
High Mesa | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Accounts receivable, related party | 23,400,000 | 23,400,000 | 23,400,000 | $ 23,400,000 | |||||||||
Predecessor | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
General and administrative | $ 21,234,000 | 55,671,000 | $ 40,468,000 | ||||||||||
Advances from related party | 23,390,000 | ||||||||||||
Notes receivable from related party | 0 | ||||||||||||
Related party receivables | 790,000 | ||||||||||||
Long-term note receivable | 12,369,000 | ||||||||||||
Predecessor | BCE | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Advances from related party | 23,400,000 | ||||||||||||
Kingfisher | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Shortfall fee reimbursement percent | 50.00% | ||||||||||||
Accounts payable, related party | 100,000 | 100,000 | 100,000 | $ 100,000 | |||||||||
Land consulting services | Vice President | David Murrell, VP of Land and Business Development | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Expenditures under arrangement with related party | 166,000 | ||||||||||||
General and administrative | 8,523 | ||||||||||||
Land consulting services | Predecessor | Vice President | David Murrell, VP of Land and Business Development | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Expenditures under arrangement with related party | $ 28,000 | 186,000 | 146,000 | ||||||||||
Compensation To Related Party | Vice President | David Mcclure Vp Of Facilities And Midstream | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Total compensation | 1,157,774 | ||||||||||||
Compensation To Related Party | Landman | David Pepper, Landman And Cousin Of VP Of Land And Business Development | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Total compensation | 297,134 | ||||||||||||
Compensation To Related Party | Predecessor | Vice President | David Mcclure Vp Of Facilities And Midstream | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Total compensation | 250,000 | 425,000 | |||||||||||
Employee benefits and share-based compensation | 28,874 | ||||||||||||
Compensation To Related Party | Predecessor | Landman | David Pepper, Landman And Cousin Of VP Of Land And Business Development | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Total compensation | 150,000 | 180,000 | |||||||||||
Employee benefits and share-based compensation | 67,322 | ||||||||||||
Long-term note receivable from HMS | HMS | 8% long-term note receivable | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Interest income note receivable | 900,000 | ||||||||||||
Long-term note receivable from HMS | Predecessor | HMS | 8% long-term note receivable | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Interest income note receivable | $ 100,000 | 900,000 | 800,000 | ||||||||||
High Mesa Agreement | High Mesa | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Long-term note receivable | 10,000,000 | $ 10,000,000 | 10,000,000 | 10,000,000 | |||||||||
Initial term | 180 days | ||||||||||||
Renewal term | 180 days | ||||||||||||
Required notice period to terminate agreement | 90 days | ||||||||||||
Management fee | $ 10,000 | ||||||||||||
Costs incurred prior to 2018 | 800,000 | ||||||||||||
Allowance for uncollectible accounts | 9,000,000 | 9,000,000 | 9,000,000 | 9,000,000 | |||||||||
High Mesa Agreement | Predecessor | High Mesa | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Long-term note receivable | $ 800,000 | ||||||||||||
KFM | High Mesa | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Number of produced water disposal wells sold | well | 20 | ||||||||||||
Proceeds from sale of business | $ 98,000,000 | ||||||||||||
Proceeds from sale of water systems | $ 90,000,000 | ||||||||||||
Accounts receivable, related party | 8,000,000 | 8,000,000 | 8,000,000 | 8,000,000 | |||||||||
Expenditures under arrangement with related party | 4,700,000 | ||||||||||||
Initial term | 15 years | ||||||||||||
Joint Development Agreement | BCE | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Advances from related party | $ 39,500,000 | $ 39,500,000 | $ 39,500,000 | $ 39,500,000 | |||||||||
Number of wells drilled | well | 61 | 61 | 61 | 61 | |||||||||
Joint Development Agreement | Predecessor | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Number of wells to be drilled in three tranches | well | 60 | ||||||||||||
Number of additional wells to be drilled | well | 20 | ||||||||||||
Reduced interest (percent) | 12.50% | ||||||||||||
Internal rate of return | 25.00% | ||||||||||||
Joint Development Agreement | Predecessor | BCE | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Percent committed to fund | 100.00% | ||||||||||||
Drilling and completion costs (maximum) | $ 3,200,000 | $ 3,200,000 | |||||||||||
Working interest received (percent) | 80.00% | ||||||||||||
Reduced interest (percent) | 20.00% | ||||||||||||
Internal rate of return | 15.00% | ||||||||||||
Subsequent Event | High Mesa | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Accounts receivable, related party | $ 22,400,000 | ||||||||||||
Payment received | 1,000,000 | ||||||||||||
Subsequent Event | High Mesa Agreement | High Mesa | |||||||||||||
Related Party Transaction [Line Items] | |||||||||||||
Contract receivable | $ 900,000 |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) $ in Millions | 3 Months Ended | |
Jun. 30, 2019 | Mar. 31, 2019 | |
Forecast | Subsequent Event | ||
Subsequent Event [Line Items] | ||
Restructuring charges | $ 1.2 | $ 4.7 |
Supplemental Quarterly Inform_3
Supplemental Quarterly Information (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 11 Months Ended | 12 Months Ended | ||||||||
Feb. 08, 2018 | Mar. 31, 2018 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Line Items] | |||||||||||||
Total operating revenue and other | $ 34,090 | $ 185,589 | $ 122,873 | $ 66,459 | $ 46,567 | $ 57,923 | $ 79,800 | $ 95,079 | $ 409,011 | ||||
Income (loss) from continuing operations | (34,571) | (2,037,170) | 17,844 | (22,477) | (35,733) | (22,163) | 15,620 | 29,430 | (2,076,374) | $ (2,000,000) | |||
Income (loss) from discontinued operations | 0 | 0 | 0 | 0 | (27,325) | (2,041) | (30,934) | (4,515) | 0 | ||||
Net income (loss) | (34,571) | (2,037,170) | 17,844 | (22,477) | (63,058) | (24,204) | (15,314) | 24,915 | (2,076,374) | ||||
Impairment of assets | 2,000,000 | 1,200 | 2,033,712 | ||||||||||
Gain (loss) on derivatives | (22,600) | $ 52,800 | $ (11,200) | $ (29,200) | (29,700) | (10,500) | $ 18,300 | $ 30,200 | (10,247) | ||||
Gain on sale of assets | $ 6,000 | $ 4,751 | |||||||||||
Gain (Loss) on Sale of Assets and Asset Impairment Charges | (22,200) | ||||||||||||
Predecessor | |||||||||||||
Quarterly Financial Information Disclosure [Line Items] | |||||||||||||
Total operating revenue and other | $ 47,639 | $ 279,369 | $ 101,899 | ||||||||||
Income (loss) from continuing operations | (7,116) | (12,846) | (134,279) | ||||||||||
Income (loss) from discontinued operations | (7,746) | (64,815) | (33,642) | ||||||||||
Net income (loss) | (14,862) | (77,661) | (167,921) | ||||||||||
Impairment of assets | 0 | 1,188 | 382 | ||||||||||
Gain (loss) on derivatives | 6,663 | 8,287 | (40,460) | ||||||||||
Gain (loss) on acquisition of oil and gas property | $ (3,600) | $ 5,300 | |||||||||||
Gain on sale of assets | $ 840 | $ 28 | $ 3 |
Supplemental Oil And Natural _3
Supplemental Oil And Natural Gas Disclosures (Estimated Quantities Of Proved Reserves) (Details) MMcf in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | |||
Feb. 08, 2018MBblsMMcf | Dec. 31, 2018aMBblsMMcf | Dec. 31, 2018MBblsMMcf | Dec. 31, 2017MBblsMMcf | Dec. 31, 2016MBblsMMcf | Dec. 31, 2015MBblsMMcf | |
2018 Development Drilling Programs | ||||||
Total Proved Reserves: | ||||||
Purchases in place | 47,092 | |||||
Revisions of previous quantity estimates and other | 101,516 | |||||
Number of Acres | a | 640 | |||||
Higher Average Commodity Price | ||||||
Total Proved Reserves: | ||||||
Revisions of previous quantity estimates and other | 11,196 | |||||
Oil | ||||||
Total Proved Reserves: | ||||||
Proved Reserves, Ending balance | 25,272,000 | 25,272,000 | ||||
Proved Developed Reserves | 19,345,000 | 25,272,000 | 25,272,000 | 20,347,000 | 16,832,000 | 14,942,000 |
Proved Undeveloped Reserves | 52,360,000 | 0 | 0 | 53,171,000 | 40,967,000 | 19,200,000 |
Natural gas | ||||||
Total Proved Reserves: | ||||||
Proved Reserves, Ending balance | MMcf | 144,148 | 144,148 | ||||
Proved Developed Reserves | MMcf | 126,231 | 144,148 | 144,148 | 150,183 | 93,361 | 71,752 |
Proved Undeveloped Reserves | MMcf | 284,571 | 0 | 0 | 283,336 | 222,644 | 83,671 |
Natural gas liquids | ||||||
Total Proved Reserves: | ||||||
Proved Reserves, Ending balance | 19,792,000 | 19,792,000 | ||||
Proved Developed Reserves | 11,348,000 | 19,792,000 | 19,792,000 | 12,180,000 | 7,977,000 | 6,958,000 |
Proved Undeveloped Reserves | 24,896,000 | 0 | 0 | 24,707,000 | 20,313,000 | 11,479,000 |
BOE | ||||||
Total Proved Reserves: | ||||||
Proved Reserves, Ending balance | 69,089,000 | 69,089,000 | ||||
Proved Developed Reserves | 51,731,000 | 69,089,000 | 69,089,000 | 57,557,000 | 40,371,000 | 33,859,000 |
Proved Undeveloped Reserves | 124,685,000 | 0 | 0 | 125,101,000 | 98,386,000 | 44,624,000 |
BOE | High Mesa Agreement | ||||||
Total Proved Reserves: | ||||||
Purchases in place | 3.1 | |||||
Predecessor | Oil | ||||||
Total Proved Reserves: | ||||||
Proved Reserves, Beginning Balance | 73,518,000 | 71,705,000 | 73,518,000 | 57,799,000 | 34,142,000 | |
Production | (521,000) | (5,053,000) | (4,850,000) | (4,001,000) | ||
Purchases in place | 0 | 2,658,000 | 725,000 | 1,508,000 | ||
Discoveries and extensions | 0 | 30,026,000 | 20,135,000 | 29,903,000 | ||
Sales of reserves in place | (1,667,000) | 0 | (3,622,000) | (73,000) | ||
Revisions of previous quantity estimates and other | 375,000 | (74,064,000) | 3,331,000 | (3,680,000) | ||
Proved Reserves, Ending balance | 71,705,000 | 73,518,000 | 57,799,000 | |||
Predecessor | Natural gas | ||||||
Total Proved Reserves: | ||||||
Proved Reserves, Beginning Balance | MMcf | 433,519 | 410,802 | 433,519 | 316,005 | 155,423 | |
Production | MMcf | (1,984) | (16,913) | (18,218) | (13,959) | ||
Purchases in place | MMcf | 0 | 13,331 | 4,860 | 6,754 | ||
Discoveries and extensions | MMcf | 0 | 155,306 | 108,676 | 154,653 | ||
Sales of reserves in place | MMcf | (24,239) | 0 | (1,280) | (966) | ||
Revisions of previous quantity estimates and other | MMcf | 3,506 | (418,378) | 23,476 | 14,100 | ||
Proved Reserves, Ending balance | MMcf | 410,802 | 433,519 | 316,005 | |||
Predecessor | Natural gas liquids | ||||||
Total Proved Reserves: | ||||||
Proved Reserves, Beginning Balance | 36,887,000 | 36,244,000 | 36,887,000 | 28,290,000 | 18,437,000 | |
Production | (161,000) | (2,268,000) | (1,387,000) | (956,000) | ||
Purchases in place | 0 | 1,751,000 | 401,000 | 613,000 | ||
Discoveries and extensions | 0 | 19,646,000 | 9,640,000 | 14,000,000 | ||
Sales of reserves in place | (771,000) | 0 | 0 | (10,000) | ||
Revisions of previous quantity estimates and other | 289,000 | (35,581,000) | (57,000) | (3,794,000) | ||
Proved Reserves, Ending balance | 36,244,000 | 36,887,000 | 28,290,000 | |||
Predecessor | BOE | ||||||
Total Proved Reserves: | ||||||
Proved Reserves, Beginning Balance | 182,658,000 | 176,416,000 | 182,658,000 | 138,757,000 | 78,483,000 | |
Production | (1,012,000) | (10,140,000) | (9,274,000) | (7,284,000) | ||
Purchases in place | 0 | 6,631,000 | 1,936,000 | 3,247,000 | ||
Discoveries and extensions | 0 | 75,557,000 | 47,888,000 | 69,679,000 | ||
Sales of reserves in place | (6,478,000) | 0 | (3,836,000) | (244,000) | ||
Revisions of previous quantity estimates and other | 1,248,000 | (179,375,000) | 7,187,000 | (5,124,000) | ||
Proved Reserves, Ending balance | 176,416,000 | 182,658,000 | 138,757,000 |
Supplemental Oil And Natural _4
Supplemental Oil And Natural Gas Disclosures (Results of Operations) (Details) - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reserve Quantities [Line Items] | ||||
Operating revenue | $ 414,507 | |||
Production expense | 247,748 | |||
Depreciation, depletion and amortization | 133,554 | |||
Exploration expense | 34,085 | |||
Impairment expense | 2,033,712 | |||
Income tax expense (benefit) | 4 | |||
Results of operations | $ (2,034,596) | |||
Predecessor | ||||
Reserve Quantities [Line Items] | ||||
Operating revenue | $ 40,136 | $ 269,386 | $ 142,356 | |
Production expense | 30,743 | 138,833 | 87,869 | |
Depreciation, depletion and amortization | 11,670 | 89,115 | 53,755 | |
Exploration expense | 7,003 | 13,563 | 17,230 | |
Impairment expense | 0 | 1,188 | 382 | |
Income tax expense (benefit) | 0 | 6 | 0 | |
Results of operations | $ (9,280) | $ 26,681 | $ (16,880) |
Supplemental Oil And Natural _5
Supplemental Oil And Natural Gas Disclosures (Capitalized Costs Relating To Oil And Natural Gas Producing Activities) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Capitalized costs: | ||
Proved properties | $ 2,110,346 | |
Unproved properties | 816,282 | |
Total | 2,926,628 | |
Accumulated depreciation, depletion, amortization and impairment | (2,163,291) | |
Net capitalized costs | $ 763,337 | |
Predecessor | ||
Capitalized costs: | ||
Proved properties | $ 1,545,963 | |
Unproved properties | 116,787 | |
Total | 1,662,750 | |
Accumulated depreciation, depletion, amortization and impairment | (711,275) | |
Net capitalized costs | $ 951,475 |
Supplemental Oil And Natural _6
Supplemental Oil And Natural Gas Disclosures (Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities) (Details) - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | ||
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities | |||||
Property acquisition costs, unproved properties | $ 54,587 | ||||
Property acquisition costs, proved properties | 16,300 | ||||
Costs incurred, exploration | 32,130 | ||||
Costs incurred, development | 664,138 | ||||
Costs Incurred, Total | 767,155 | ||||
Costs Incurred, Additional Information [Abstract] | |||||
Additions to asset retirement obligations | 5,600 | ||||
Unproven leasehold acquisition cost | $ 22,300 | ||||
Predecessor | |||||
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities | |||||
Property acquisition costs, unproved properties | $ 4,240 | $ 88,378 | $ 66,788 | ||
Property acquisition costs, proved properties | 327 | 11,704 | 68,478 | ||
Costs incurred, exploration | 3,678 | 26,836 | 28,480 | ||
Costs incurred, development | 37,672 | 351,570 | 165,796 | ||
Costs Incurred, Total | $ 45,917 | 478,488 | 329,542 | ||
Costs Incurred, Additional Information [Abstract] | |||||
Additions to asset retirement obligations | $ 0 | 4,400 | 1,900 | ||
Unproven leasehold acquisition cost | $ 45,600 | ||||
Predecessor | Stone | |||||
Costs Incurred, Additional Information [Abstract] | |||||
Total cost of business acquisition | $ 65,700 |
Supplemental Oil And Natural _7
Supplemental Oil And Natural Gas Disclosures (Components Of The Standardized Measure Of Discounted Future Net Cash Flows) (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 11 Months Ended | 12 Months Ended | ||
Feb. 08, 2018USD ($)$ / bbl$ / MMcf | Mar. 31, 2018$ / bbl | Dec. 31, 2018USD ($)$ / bbl$ / MMcf | Dec. 31, 2017USD ($)$ / bbl$ / MMcf | Dec. 31, 2016USD ($)$ / bbl$ / MMcf | Dec. 31, 2015USD ($) | |
Components of the standardized measure of discounted future net cash flows | ||||||
Future cash flows | $ 2,446,888 | |||||
Future production costs | (1,214,479) | |||||
Future development costs | (23,183) | |||||
Future taxes on income | 0 | |||||
Future net cash flows | 1,209,226 | |||||
Discount to present value at 10 percent per annum | (396,375) | |||||
Standardized measure of discounted future net cash flows | $ 1,179,886 | $ 812,851 | ||||
Base price for crude oil, per Bbl, in the above computation was | $ / bbl | 40 | 65.56 | ||||
Base price for natural gas, per Mcf, in the above computation was | $ / MMcf | 3.10 | |||||
Base Price Per Unit For Natural Gas Liquids | $ / MMcf | 22.44 | |||||
Predecessor | ||||||
Components of the standardized measure of discounted future net cash flows | ||||||
Future cash flows | 5,798,886 | $ 5,799,753 | $ 3,547,130 | |||
Future production costs | (2,556,361) | (2,617,476) | (1,811,683) | |||
Future development costs | (965,780) | (1,035,481) | (709,738) | |||
Future taxes on income | 0 | 0 | 0 | |||
Future net cash flows | 2,276,745 | 2,146,796 | 1,025,709 | |||
Discount to present value at 10 percent per annum | (1,096,859) | (1,040,874) | (467,101) | |||
Standardized measure of discounted future net cash flows | $ 1,179,886 | $ 1,105,922 | $ 558,608 | $ 629,596 | ||
Base price for crude oil, per Bbl, in the above computation was | $ / bbl | 52.89 | 51.34 | 42.75 | |||
Base price for natural gas, per Mcf, in the above computation was | $ / MMcf | 2.99 | 2.98 | 2.49 | |||
Base Price Per Unit For Natural Gas Liquids | $ / bbl | 27.48 | 26.06 | 15.18 |
Supplemental Oil And Natural _8
Supplemental Oil And Natural Gas Disclosures (Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Components of changes in standardized measure of discounted future net cash flows | ||||
Balance at beginning of year | $ 1,179,886 | |||
Sales of oil and natural gas, net of production costs | (278,091) | |||
Changes in sales and transfer prices, net of production costs | 38,963 | |||
Revisions of previous quantity estimates | (1,120,097) | |||
Purchases of reserves-in-place | 24,376 | |||
Sales of reserves-in-place | 0 | |||
Current year discoveries and extensions | 684,700 | |||
Changes in estimated future development costs | (39,069) | |||
Development costs incurred during the year | 160,583 | |||
Accretion of discount | 117,989 | |||
Net change in income taxes | 0 | |||
Change in production rate (timing) and other | 43,611 | |||
Net change | (367,035) | |||
Balance at end of year | $ 1,179,886 | 812,851 | ||
Amount of proved undeveloped reserves, derecognized | 250,000 | |||
Predecessor | ||||
Components of changes in standardized measure of discounted future net cash flows | ||||
Balance at beginning of year | 1,105,922 | $ 1,179,886 | $ 558,608 | $ 629,596 |
Sales of oil and natural gas, net of production costs | (30,391) | (202,232) | (124,610) | |
Changes in sales and transfer prices, net of production costs | 71,334 | 354,900 | (324,638) | |
Revisions of previous quantity estimates | 10,887 | (12,106) | (35,972) | |
Purchases of reserves-in-place | 0 | 11,483 | 40,611 | |
Sales of reserves-in-place | (4,807) | (20,423) | 2,345 | |
Current year discoveries and extensions | 0 | 513,012 | 356,631 | |
Changes in estimated future development costs | 491 | (5,869) | 849 | |
Development costs incurred during the year | 0 | 26,317 | 8,363 | |
Accretion of discount | 110,592 | 55,861 | 62,960 | |
Net change in income taxes | 0 | 0 | 0 | |
Change in production rate (timing) and other | (84,142) | (173,629) | (57,527) | |
Net change | 73,964 | 547,314 | (70,988) | |
Balance at end of year | $ 1,179,886 | $ 1,105,922 | $ 558,608 |