Document And Entity Information
Document And Entity Information | 3 Months Ended |
Mar. 31, 2019shares | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | Alta Mesa Holdings, LP |
Entity Central Index Key | 0001518403 |
Document Type | 10-Q |
Document Period End Date | Mar. 31, 2019 |
Amendment Flag | false |
Document Fiscal Year Focus | 2019 |
Document Fiscal Period Focus | Q1 |
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 Shell Company | false |
Entity Common Stock, Shares Outstanding (in shares) | 0 |
Entity Current Reporting Status | No |
Condensed Consolidated Statemen
Condensed Consolidated Statements Of Operations (Unaudited) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | |
Revenue | |||
Operating revenue | $ 50,757 | $ 116,597 | |
Gain on sale of assets | 5,139 | 1,483 | |
Gain (loss) on derivatives | (22,011) | (23,777) | |
Total revenue | 33,885 | 94,303 | |
Operating expenses | |||
Lease operating | 8,317 | 25,108 | |
Transportation and marketing | 5,582 | 17,761 | |
Production taxes | 1,415 | 5,483 | |
Workovers | 1,245 | 197 | |
Exploration | 1,585 | 2,054 | |
Depreciation, depletion and amortization | 11,038 | 34,675 | |
General and administrative | 34,654 | 20,947 | |
Total operating expenses | 63,836 | 106,225 | |
Operating income | (29,951) | (11,922) | |
Other income (expense) | |||
Interest expense | (5,196) | (12,830) | |
Interest income and other | 546 | 27 | |
Total other expense, net | (4,650) | (12,803) | |
Loss from continuing operations | (34,601) | (24,725) | |
Loss from discontinued operations, net of tax | 0 | 0 | |
Net loss | (34,601) | (24,725) | |
Oil | |||
Revenue | |||
Operating revenue | 40,278 | 86,363 | |
Natural gas | |||
Revenue | |||
Operating revenue | 5,210 | 18,450 | |
Natural gas liquids | |||
Revenue | |||
Operating revenue | 4,714 | 11,216 | |
Other | |||
Revenue | |||
Operating revenue | $ 555 | $ 568 | |
Predecessor | |||
Revenue | |||
Operating revenue | $ 40,136 | ||
Gain on sale of assets | 840 | ||
Gain (loss) on derivatives | 6,663 | ||
Total revenue | 47,639 | ||
Operating expenses | |||
Lease operating | 4,408 | ||
Transportation and marketing | 3,725 | ||
Production taxes | 953 | ||
Workovers | 423 | ||
Exploration | 7,003 | ||
Depreciation, depletion and amortization | 11,670 | ||
General and administrative | 21,234 | ||
Total operating expenses | 49,416 | ||
Operating income | (1,777) | ||
Other income (expense) | |||
Interest expense | (5,511) | ||
Interest income and other | 172 | ||
Total other expense, net | (5,339) | ||
Loss from continuing operations | (7,116) | ||
Loss from discontinued operations, net of tax | (7,746) | ||
Net loss | (14,862) | ||
Predecessor | Oil | |||
Revenue | |||
Operating revenue | 30,972 | ||
Predecessor | Natural gas | |||
Revenue | |||
Operating revenue | 4,276 | ||
Predecessor | Natural gas liquids | |||
Revenue | |||
Operating revenue | 4,000 | ||
Predecessor | Other | |||
Revenue | |||
Operating revenue | $ 888 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Current assets | ||
Cash and cash equivalents | $ 27,045 | $ 12,984 |
Restricted cash | 798 | 1,001 |
Accounts receivable, net | 65,403 | 68,370 |
Other receivables | 2,239 | 6,267 |
Related party receivables, net | 17,126 | 24,282 |
Notes receivable from related party, net | 0 | 0 |
Prepaid expenses and other current assets | 4,549 | 747 |
Derivatives | 0 | 16,423 |
Total current assets | 117,160 | 130,074 |
Property and equipment | ||
Oil and gas properties, successful efforts method, net | 777,750 | 763,337 |
Other property and equipment, net | 38,099 | 38,147 |
Total property and equipment, net | 815,849 | 801,484 |
Other assets | ||
Operating lease right-of-use assets, net | 14,758 | |
Deferred financing costs, net | 1,115 | 1,151 |
Deposits and other long-term assets | 48 | 63 |
Derivatives | 461 | 2,947 |
Total other assets | 16,382 | 4,161 |
Total assets | 949,391 | 935,719 |
Current liabilities | ||
Accounts payable and accrued liabilities | 108,666 | 197,064 |
Accounts payable - related party | 481 | 3,425 |
Advances from non-operators | 2,367 | 5,193 |
Advances from related party | 4,479 | 9,822 |
Asset retirement obligations | 48 | 2,079 |
Current operating lease liability | 895 | |
Derivatives | 5,057 | 1,710 |
Total current liabilities | 121,993 | 219,293 |
Long-term liabilities | ||
Asset retirement obligations, net of current portion | 11,750 | 9,330 |
Long-term debt, net | 805,892 | 690,123 |
Operating lease liabilities, net of current portion | 13,962 | |
Derivatives | 2,065 | 180 |
Total long-term liabilities | 833,669 | 699,633 |
Total liabilities | 955,662 | 918,926 |
Commitments and contingencies (Note 13) | ||
Partners’ capital | (6,271) | 16,793 |
Total liabilities and partners’ capital | $ 949,391 | $ 935,719 |
Condensed Consolidated Statem_2
Condensed Consolidated Statements Of Changes In Partners' Capital (Unaudited) $ in Thousands | USD ($) |
BALANCE, BEGINNING (Predecessor) at Dec. 31, 2017 | $ 154,445 |
Distribution of non-STACK oil and gas assets, net of associated liabilities, and 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 |
Distribution of non-STACK oil and gas assets, net of associated liabilities, and Contributions | 560,344 |
Equity-based compensation expense | 2,768 |
Net loss | (34,601) |
BALANCE, ENDING at Mar. 31, 2018 | 2,064,402 |
BALANCE, BEGINNING at Dec. 31, 2018 | 16,793 |
Equity-based compensation expense | 1,661 |
Net loss | (24,725) |
BALANCE, ENDING at Mar. 31, 2019 | $ (6,271) |
Condensed Consolidated Statem_3
Condensed Consolidated Statements Of Cash Flows (Unaudited) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | |
Cash flows from operating activities: | |||
Net loss | $ (34,601) | $ (24,725) | |
Adjustments to reconcile net loss to cash from operating activities: | |||
Depreciation, depletion, amortization and ARO accretion | 11,038 | 34,675 | |
Non-cash lease expense | $ 0 | 0 | 99 |
Provision for uncollectible related party receivables | 0 | 853 | |
Impairments | 0 | 0 | |
Amortization of deferred financing costs | 0 | 45 | |
Amortization of debt premium discount | (820) | (1,231) | |
Equity-based compensation expense | 2,768 | 1,661 | |
Expired leases | 4,189 | 162 | |
(Gain) Loss on derivatives | 22,011 | 23,777 | |
Cash settlements of derivatives | (3,975) | 365 | |
Interest converted into debt | 0 | 0 | |
Interest added to notes receivable from affiliate | (162) | 0 | |
Loss on sale of fixed assets | 0 | 0 | |
Impact on cash from changes in: | |||
Accounts receivable | 3,097 | 2,968 | |
Other receivables | 1,427 | 4,029 | |
Receivables from affiliate and related party | (7,880) | 6,303 | |
Prepaid expenses and other non-current assets | (2,240) | (3,787) | |
Advances from related party | (7,008) | (5,344) | |
Settlement of asset retirement obligations | (166) | (147) | |
Accounts payable to related party | (1,824) | (2,944) | |
Accounts payable, accrued liabilities and other liabilities | (35,165) | (6,824) | |
Cash from operating activities | (49,311) | 29,935 | |
Cash flows from investing activities: | |||
Capital expenditures | (129,310) | (133,077) | |
Acquisitions, net of cash acquired | 0 | 0 | |
Cash from investing activities | (129,310) | (133,077) | |
Cash flows from financing activities: | |||
Proceeds from long-term debt borrowings | 0 | 117,000 | |
Repayments of long-term debt | (134,065) | 0 | |
Deferred financing costs paid | (1,007) | 0 | |
Capital distributions | 0 | 0 | |
Capital contributions | 560,344 | 0 | |
Cash from financing activities | 425,272 | 117,000 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect | 246,651 | 13,858 | |
Cash, cash equivalents and restricted cash, beginning of period | 10,345 | 13,985 | |
Cash, cash equivalents and restricted cash, end of period | 10,345 | 256,996 | $ 27,843 |
Predecessor | |||
Cash flows from operating activities: | |||
Net loss | (14,862) | ||
Adjustments to reconcile net loss to cash from operating activities: | |||
Depreciation, depletion, amortization and ARO accretion | 12,554 | ||
Provision for uncollectible related party receivables | 0 | ||
Impairments | 5,560 | ||
Amortization of deferred financing costs | 171 | ||
Amortization of debt premium discount | 0 | ||
Equity-based compensation expense | 0 | ||
Expired leases | 4,575 | ||
(Gain) Loss on derivatives | (6,663) | ||
Cash settlements of derivatives | (2,296) | ||
Interest converted into debt | 103 | ||
Interest added to notes receivable from affiliate | (85) | ||
Loss on sale of fixed assets | 1,923 | ||
Impact on cash from changes in: | |||
Accounts receivable | (21,184) | ||
Other receivables | (662) | ||
Receivables from affiliate and related party | (117) | ||
Prepaid expenses and other non-current assets | (591) | ||
Advances from related party | 24,116 | ||
Settlement of asset retirement obligations | (63) | ||
Accounts payable to related party | 0 | ||
Accounts payable, accrued liabilities and other liabilities | 23,857 | ||
Cash from operating activities | 26,336 | ||
Cash flows from investing activities: | |||
Capital expenditures | (36,695) | ||
Acquisitions, net of cash acquired | (1,218) | ||
Cash from investing activities | (37,913) | ||
Cash flows from financing activities: | |||
Proceeds from long-term debt borrowings | 60,000 | ||
Repayments of long-term debt | (43,000) | ||
Deferred financing costs paid | 0 | ||
Capital distributions | (68) | ||
Capital contributions | 0 | ||
Cash from financing activities | 16,932 | ||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect | 5,355 | ||
Cash, cash equivalents and restricted cash, beginning of period | 4,990 | $ 10,345 | |
Cash, cash equivalents and restricted cash, end of period | $ 10,345 |
Description of Business
Description of Business | 3 Months Ended |
Mar. 31, 2019 | |
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 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 natural gas interests in Texas, Idaho, Louisiana and Florida. In connection with our acquisition by Alta Mesa Resources, Inc. (“AMR”), on February 9, 2018 (“the Business Combination”), we distributed the non-STACK oil and gas assets and liabilities to our prior owner, High Mesa Holdings, LP (“High Mesa”), and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK. Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“HMI”). |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2019 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation All intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements are unaudited, but we believe these statements reflect all adjustments necessary for a fair presentation for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with the SEC’s rules for interim financial statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”) for complete financial statements. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three months ended March 31, 2019, are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented. Recently Issued Accounting Standards Applicable to Us Adopted Effective January 1, 2019, we adopted 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. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019. Not Yet Adopted 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 and notes 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 and notes 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 do not expect the adoption of this standard to impact our financial position or results of operations. |
Adoption of ASU No. 2016-02, Le
Adoption of ASU No. 2016-02, Leases | 3 Months Ended |
Mar. 31, 2019 | |
Leases [Abstract] | |
Adoption of ASU No. 2016-02, Leases | ADOPTION OF ASU NO. 2016-02, LEASES ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on the balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method to apply the standard as January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets of $15.0 million and operating lease liabilities of $15.0 million . There was no adjustment to retained earnings We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services by the lessors for the underlying assets. All of our leases of office space and office equipment, were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not sublease any of our ROU assets. Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred. Upon adoption, we selected the following practical expedients: Practical expedient package We did not reassess whether any expired or existing contracts are, or contain, leases. We did not reassess the lease classification of any expired or existing leases. We did not reassess initial direct costs of any expired or existing leases. Hindsight practical expedient We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets. Easement expedient We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease. Combining lease and non-lease components expedient We elected to account for lease and non-lease components as a single component. Short-term lease expedient We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet. As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, comparable companies and credit analysis and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At March 31, 2019 , for our operating leases the weighted-average remaining lease terms were approximately 8.3 years and our weighted-average discount rates were 14.3% . The following summarizes the components of our lease expense: (in thousands) Three Months Ended Operating lease cost $ 811 Variable lease cost 323 Short-term lease cost 2,187 Total lease cost $ 3,321 For the three months ended March 31, 2019, we recognized $ 2.3 million of lease costs in lease operating expense and $ 1.0 million in general and administrative expense. Maturities of our operating lease liabilities were as follows as of March 31, 2019 : Fiscal year (in thousands) Remainder of 2019 $ 2,200 2020 2,965 2021 2,942 2022 3,010 2023 2,718 Thereafter 12,647 Total lease payments 26,482 Less: imputed interest (11,625 ) Present value of operating lease liabilities $ 14,857 Current portion of operating lease liabilities $ 895 Operating lease liabilities, net of current portion 13,962 Present value of operating lease liabilities $ 14,857 As described further in our 2018 Annual Report on Form 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter. |
Going Concern
Going Concern | 3 Months Ended |
Mar. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
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: • At March 31, 2019 , our current liabilities exceeded our current assets by $ 4.8 million. • We have failed to meet the timelines to provide our audited and unaudited financial information under our debt agreements. • 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. • Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect for our operating cash flow to be less than our capital spending for all of 2019. • On April 1, 2019, our borrowing base was reduced to $370.0 million under the Alta Mesa RBL and we have no further capacity thereunder. There is risk that future redeterminations could reduce the borrowing base further, which would trigger rateable repayments of excess borrowings over five months. Without additional capital, we will only be able to utilize the cash on hand, which at May 31, 2019 was $93.7 million , to fund development and meet our financial obligations and may be unable to maintain our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. The lenders have an ability to make an optional redetermination ahead of the regular redetermination scheduled in October 2019. • We anticipate having difficulty meeting our existing leverage covenants during the next 12 months without relief from our lenders. 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. • 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, which could become an event of default if unpaid within the cure period. 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, AMR was notified by NASDAQ that it was 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 and our parent’s ability to continue as a going concern. To address this, we have: • retained financial advisors to assist in evaluating financial alternatives; • engaged in discussions with the Alta Mesa RBL lenders and their advisors 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, however, such efforts have not reached a stage where significant terms have been agreed to; • engaged in discussions with advisors to a group of holders of the 2024 Notes regarding potential options to address overall leverage, but have not agreed upon any significant strategy or 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. We have continued reporting our long-term debt as noncurrent, since a conclusion regarding going concern has no effect on debt compliance. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 3 Months Ended |
Mar. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | SUPPLEMENTAL CASH FLOW INFORMATION Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Supplemental cash flow information: Cash paid for interest $ 1,750 $ 1,092 $ 1,145 Non-cash investing and financing activities: Increase in asset retirement obligations 314 421 — Increase (decrease) in accruals or payables for capital expenditures (84,162 ) (36,866 ) 4,896 Distribution of non-STACK assets, net of liabilities — — 43,482 The following table summarizes cash, cash equivalents and restricted cash in the statements of cash flows: Successor Predecessor (in thousands) March 31, 2019 March 31, 2018 February 8, 2018 Cash and cash equivalents $ 27,045 $ 255,701 $ 9,070 Restricted cash 798 1,295 1,275 Total cash, cash equivalents and restricted cash $ 27,843 $ 256,996 $ 10,345 |
Receivables
Receivables | 3 Months Ended |
Mar. 31, 2019 | |
Receivables [Abstract] | |
Receivables | RECEIVABLES Accounts Receivable (in thousands) March 31, 2019 December 31, 2018 Production sales $ 32,332 $ 31,532 Joint interest billings 18,224 18,147 Pooling interest (1) 14,960 18,786 Allowance for doubtful accounts (113 ) (95 ) Total accounts receivable, net $ 65,403 $ 68,370 _________________ (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. Related Party Receivables (in thousands) March 31, 2019 December 31, 2018 Related party receivables $ 27,013 $ 33,316 Allowance for doubtful accounts (9,887 ) (9,034 ) Related party receivables, net 17,126 24,282 Notes receivable from related parties 13,403 13,403 Allowance for doubtful accounts (13,403 ) (13,403 ) Notes receivable from related parties, net — — Total related party receivables, net $ 17,126 $ 24,282 KFM Receivables We have entered into a Crude Oil Gathering Agreement and a Gas Gathering and Processing Agreement with KFM. During the three months ended March 31, 2019, the period February 9, 2018 through March 31, 2018, and the Predecessor Period January 1, 2018 through February 8, 2018, we incurred $15.2 million , $4.6 million , and $3.1 million , respectively, in transportation and marketing expenses related to these agreements. Additionally, related party receivables from KFM for the marketing of our processed natural gas and NGLs were $2.3 million and $7.8 million at March 31, 2019 and December 31, 2018, respectively. In addition, we sold a produced water disposal system to KFM during the fourth quarter of 2018. As of March 31, 2019 and December 31, 2018, related party receivables included $9.1 million and $8.7 million , respectively, attributable to a purchase price adjustment due from KFM. We collected these amounts during June 2019. We incur general and administrative costs that may be partially or fully allocable to KFM. These costs are either allocated monthly or charged directly to KFM but are cash settled in arrears. As of March 31, 2019 and December 31, 2018, respectively, we have receivables from KFM for such costs totaling $1.9 million and $3.4 million , respectively. AMR Receivables We incur general and administrative costs that may be partially or fully allocable to AMR. These costs are either allocated monthly or charged directly to AMR but are cash settled in arrears. As of March 31, 2019 and December 31, 2018, respectively, we have receivables from AMR for such costs totaling $3.8 million and $3.3 million , respectively. Management Services Agreement with High Mesa Just prior to the Business Combination, we distributed the non-STACK oil and gas assets to High Mesa. High Mesa and certain of its 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. We also entered into a management services agreement (the “High Mesa Agreement”) with HMI with respect to the non-STACK assets. 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 and (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 us 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. As of March 31, 2019 , and December 31, 2018 , approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. 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 of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of March 31, 2019 and December 31, 2018 , respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation relating to the non-STACK assets. As of March 31, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa. In addition, we sold a produced water disposal system to KFM during the fourth quarter of 2018. As of March 31, 2019 and December 31, 2018, related party receivables included $9.1 million attributable to the final purchase price adjustment due from KFM. This amount was collected during June 2019. As of March 31, 2019 and December 31, 2018, the Company had $3.8 million and $3.3 million in related party receivables due from AMR for expenses we paid on their behalf. Promissory notes receivable In September, 2017, we entered into a $ 1.5 million promissory note receivable with our affiliate, Northwest Gas Processing, LLC, whose obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bore interest, which could be paid-in-kind and added to the principal amount at a rate of 8% per annum, and matured in February 2019. 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 owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, due of $1.7 million as of March 31, 2019 and December 31, 2018 . In addition, we have an $ 8.5 million 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. HMI disputes its obligations under the $8.5 million note. As of March 31, 2019 , and December 31, 2018 , the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods. We oppose HMI’s claims and believe HMI’s obligations under the notes to be 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 notes. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter. |
Property And Equipment
Property And Equipment | 3 Months Ended |
Mar. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Property And Equipment | PROPERTY AND EQUIPMENT (in thousands) March 31, 2019 December 31, 2018 Oil and gas properties Unproved properties $ 811,804 $ 816,282 Accumulated impairment of unproved properties (742,065 ) (742,065 ) Unproved properties, net 69,739 74,217 Proved oil and gas properties 2,163,279 2,110,346 Accumulated depletion and impairment (1,455,268 ) (1,421,226 ) Proved oil and gas properties, net 708,011 689,120 Total oil and gas properties, net 777,750 763,337 Other property and equipment Land 5,059 5,059 Fresh water wells 27,742 27,366 Produced water disposal system 3,590 3,608 Office furniture, equipment and vehicles 2,842 2,840 Accumulated depreciation (1,134 ) (726 ) Other property and equipment, net 38,099 38,147 Total property and equipment, net $ 815,849 $ 801,484 Depletion and Depreciation Expense Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Oil and gas properties depletion $ 34,042 $ 10,773 $ 11,021 Other property and equipment depreciation 408 163 609 Total depletion and depreciation $ 34,450 $ 10,936 $ 11,630 Impairment During the three months ended March 31, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment. Therefore, we did not conduct further analysis on the recognition of additional impairment. |
Discontinued Operations
Discontinued Operations | 3 Months Ended |
Mar. 31, 2019 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | DISCONTINUED OPERATIONS (Predecessor) Alta Mesa distributed the non-STACK oil and gas assets and related liabilities to High Mesa immediately prior to the Business Combination. This distribution, including the results of operations of these assets and liabilities, is presented as discontinued operations during the Predecessor Period. Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bore simple interest at 10% . The Founder Notes were converted into an equity interest in High Mesa immediately prior to the Business Combination as they were considered 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. Predecessor Period interest on the Founder Notes was $0.1 million. Predecessor (in thousands) January 1, 2018 Revenue Oil $ 1,617 Natural gas 1,023 Natural gas liquids 236 Other 16 Operating revenue 2,892 Loss on sale of assets (1,923 ) Total revenue 969 Operating expenses Lease operating 1,770 Transportation and marketing 83 Production taxes 167 Workovers 127 Depreciation, depletion and amortization 884 Impairment of assets 5,560 General and administrative 21 Total operating expenses 8,612 Other expense Interest expense (103 ) Total other expense (103 ) Loss from discontinued operations, net of tax $ (7,746 ) Predecessor (in thousands) January 1, 2018 Total operating cash flows of discontinued operations $ 2,974 Total investing cash flows of discontinued operations (601 ) |
Derivatives
Derivatives | 3 Months Ended |
Mar. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | DERIVATIVES We have entered into derivatives to reduce our exposure to price risk associated with our production. From time to time, we may enter into interest rate swap agreements to mitigate the risk of changes in interest rates, but as of March 31, 2019 , we have none. We do not designate any of our derivatives as hedges under GAAP. The following summarizes the fair value and classification of our derivatives: March 31, 2019 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 $ 6,525 $ (6,525 ) $ — Derivatives, long-term assets 8,182 (7,721 ) 461 Total $ 14,707 $ (14,246 ) $ 461 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 $ 11,582 $ (6,525 ) $ 5,057 Derivatives, long-term liabilities 9,786 (7,721 ) 2,065 Total $ 21,368 $ (14,246 ) $ 7,122 December 31, 2018 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 The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands): Successor Predecessor Derivatives not designated as hedges Three Months Ended February 9, 2018 January 1, 2018 Gain (loss) on derivatives - Oil $ (21,669 ) $ (21,944 ) $ 4,796 Natural gas (2,108 ) (67 ) 1,867 Total gain (loss) on derivatives $ (23,777 ) $ (22,011 ) $ 6,663 Other receivables at March 31, 2019 and December 31, 2018 include $0.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the next month. 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 March 31, 2019 : OIL Volume Weighted Range Settlement Period and Type of Contract in bbls Average High Low 2019 Price Swap Contracts 137,500 $ 63.03 $ 63.03 $ 63.03 Collar Contracts Short Call Options 2,035,000 66.31 75.20 56.50 Long Put Options 2,172,500 53.80 62.00 50.00 Short Put Options 2,172,500 42.72 52.00 37.50 2020 Collar Contracts Short Call Options 1,017,600 63.95 73.80 59.55 Long Put Options 1,566,600 56.81 62.50 50.00 Short Put Options 1,566,600 42.81 50.00 37.50 2021 Collar Contracts Short Call Options 279,750 63.51 63.75 63.35 Long Put Options 279,750 55.00 55.00 55.00 Short Put Options 279,750 43.00 43.00 43.00 GAS Volume in Weighted Range Settlement Period and Type of Contract MMBtu Average High Low 2019 Price Swap Contracts 11,030,000 $ 2.67 $ 2.72 $ 2.64 Basis Swap Contracts 16,050,000 (0.73 ) (0.49 ) (0.93 ) Collar Contracts Short Call Options 1,525,000 3.19 3.20 3.17 Long Put Options 1,525,000 2.70 2.70 2.70 Short Put Options 1,525,000 2.20 2.20 2.20 2020 Price Swap Contracts 1,284,000 2.54 2.54 2.54 Basis Swap Contracts 910,000 (0.49 ) (0.49 ) (0.50 ) Collar Contracts Short Call Options 3,874,500 3.19 3.69 2.77 Long Put Options 10,749,500 2.59 3.00 2.50 Short Put Options 9,696,000 2.10 2.50 2.00 2021 Collar Contracts Short Call Options 540,000 3.25 3.25 3.25 Long Put Options 2,790,000 2.62 2.65 2.50 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 March 31, 2019 : Total Gas Volumes in MMBtu (1) over Remaining Term 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 ) 13,450,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '19 — Dec '19 (0.70 ) 910,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '20 — Mar '20 (0.49 ) 2,140,000 San Juan NYMEX Henry Hub Jan '19 — Oct '19 (0.81 ) ________________ (1) Represents short swaps that fix the basis differentials between OneOK, T ex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub. |
Accounts Payable And Accrued Li
Accounts Payable And Accrued Liabilities | 3 Months Ended |
Mar. 31, 2019 | |
Payables and Accruals [Abstract] | |
Accounts Payable And Accrued Liabilities | ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (in thousands) March 31, 2019 December 31, 2018 Accounts payable $ 8,502 $ 20,200 Accruals for capital expenditures 25,964 101,214 Revenue and royalties payable 40,365 46,870 Accruals for operating expenses 8,910 16,355 Accrued interest 13,754 1,784 Derivative settlements 49 109 Other 11,122 10,532 Total accrued liabilities 100,164 176,864 Accounts payable and accrued liabilities $ 108,666 $ 197,064 |
Asset Retirement Obligations
Asset Retirement Obligations | 3 Months Ended |
Mar. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Balance, beginning of period $ 11,409 $ — $ 10,469 Liabilities assumed in Business Combination — 5,998 — Liabilities incurred 315 421 — Liabilities settled (147 ) (166 ) (63 ) Revisions to estimates (4) 300 63 Accretion expense 225 102 39 Balance, end of period 11,798 6,655 10,508 Less: Current portion 48 622 33 Long-term portion $ 11,750 $ 6,033 $ 10,475 |
Long Term Debt, Net
Long Term Debt, Net | 3 Months Ended |
Mar. 31, 2019 | |
Debt Disclosure [Abstract] | |
Long Term Debt, Net And Notes Payable To Founder | LONG TERM DEBT, NET (in thousands) March 31, 2019 December 31, 2018 Alta Mesa RBL $ 278,000 $ 161,000 2024 Notes 500,000 500,000 Unamortized premium on 2024 notes 27,892 29,123 Total long-term debt, net $ 805,892 $ 690,123 Alta Mesa RBL The Alta Mesa RBL has two covenants that are tested quarterly: • 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 Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0 . For the first 3 measurement periods following the Business Combination we were able to annualize cumulative Successor Period results in measuring Adjusted EBITDAX. During 2019, and possibly as soon as June 30, 2019, we may be unable to satisfy the leverage ratio. Also, we recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. 2024 Notes In connection with the Business Combination, we recorded the fair value of our $500.0 million unsecured senior notes at $ 533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $194.9 million at March 31, 2019 . This estimation was based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. Maturities of Long-Term Debt Fiscal year (in thousands) 2019 $ — 2020 — 2021 — 2022 — 2023 278,000 Thereafter 500,000 $ 778,000 |
Commitments And Contingencies
Commitments And Contingencies | 3 Months Ended |
Mar. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments And Contingencies | COMMITMENTS AND CONTINGENCIES There have been no material developments during the first quarter of 2019 in relation to our commitments and contingencies as compared to our discussion of those matters in our Annual Report on Form 10-K for the year ended December 31, 2018 . |
Significant Concentrations
Significant Concentrations | 3 Months Ended |
Mar. 31, 2019 | |
Significant Concentrations [Abstract] | |
Significant Concentrations | SIGNIFICANT CONCENTRATIONS During the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC (“ARM”) marketed 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. During January and February 2019 and for all of 2018, ARM collected payments from purchasers, deducted their marketing fee and remitted the balance to us. In March 2019, in preparation for the return of oil and NGL marketing responsibilities to us, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. Effective as of June 1, 2019, we have terminated our oil and NGL marketing agreement with ARM and will market such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019. With respect to gas sales, ARM continues to collect payments from purchasers, deducts their marketing fee and remits the balance to us. Our affiliate, Kingfisher Midstream, LLC (“KFM”) is responsible for marketing our firm transportation on the ONEOK Gas Transmission, L.L.C. system, which is indirectly marketed by ARM through an asset management agreement with KFM for a management fee. ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities. Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Revenue marketed by ARM on our behalf $ 83,831 $ 37,343 $ 28,757 Marketing and management fees paid to ARM $ 661 $ — $ — Fees paid to ARM for services relating to our derivatives 193 74 66 Total fees paid to ARM $ 854 $ 74 $ 66 Receivables from ARM for sales on our behalf were $ 3.8 million and $38.4 million as of March 31, 2019 and December 31, 2018 , respectively, which are reflected in accounts receivable on our balance sheets. 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. |
Equity-Based Compensation (Succ
Equity-Based Compensation (Successor) | 3 Months Ended |
Mar. 31, 2019 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-Based Compensation (Successor) | EQUITY-BASED COMPENSATION (Successor) Stock compensation expense recognized was as follows: Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Stock options $ 791 $ 1,048 $ — Restricted stock awards 862 564 — Performance-based restricted stock units 8 1,156 — Total compensation expense $ 1,661 $ 2,768 $ — Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year are based on achievement of annual company-specific performance goals and obligations applicable to each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the target growth applicable to each vesting period. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted. The performance targets for the 2019 tranche were established in March 2019 and 595,417 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment. No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured. |
Related Party Transactions
Related Party Transactions | 3 Months Ended |
Mar. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | NOTE 16 — RELATED PARTY TRANSACTIONS As of December 31, 2018, we had a payable of $2.9 million to KFM for produced water disposal services provided following the sale of the produced water system to them during the fourth quarter of 2018. Beginning in 2019, these costs are utilized to reduce the amount that KFM owes us for marketing our production, which are reported in related party receivables. As of March 31, 2019 and December 31, 2018, we had a payable to AMR of $0.5 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 $36,000 and $ 28,000 for the period February 9, 2018 through March 31, 2018 and the Predecessor Period, respectively. 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 $768,860 , $970,197 and $28,874 during the 2019 Quarter , the period February 9, 2018 through March 31, 2018 and the Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019. 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 $70,180 , $112,761 and $67,322 during the 2019 Quarter , the period February 9, 2018 through March 31, 2018 and the Predecessor Period, 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 our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established 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 our 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, we and BCE will each bear our 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 period February 9, 2018 through March 31, 2018, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of March 31, 2019 , 61 joint wells have been drilled or spudded. At March 31, 2019 and December 31, 2018 , $4.5 million and $9.8 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 condensed consolidated balance sheets. At March 31, 2019 , there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2019 | |
Accounting Policies [Abstract] | |
Recently Issued and Applicable Accounting Standards | Recently Issued Accounting Standards Applicable to Us Adopted Effective January 1, 2019, we adopted 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. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019. Not Yet Adopted 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 and notes 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 and notes 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 do not expect the adoption of this standard to impact our financial position or results of operations. |
Adoption of ASU No. 2016-02, _2
Adoption of ASU No. 2016-02, Leases (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Leases [Abstract] | |
Schedule of Practical Expedients | Upon adoption, we selected the following practical expedients: Practical expedient package We did not reassess whether any expired or existing contracts are, or contain, leases. We did not reassess the lease classification of any expired or existing leases. We did not reassess initial direct costs of any expired or existing leases. Hindsight practical expedient We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets. Easement expedient We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease. Combining lease and non-lease components expedient We elected to account for lease and non-lease components as a single component. Short-term lease expedient We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet. |
Lease Cost | The following summarizes the components of our lease expense: (in thousands) Three Months Ended Operating lease cost $ 811 Variable lease cost 323 Short-term lease cost 2,187 Total lease cost $ 3,321 |
Maturities of Operating Lease Liabilities | Maturities of our operating lease liabilities were as follows as of March 31, 2019 : Fiscal year (in thousands) Remainder of 2019 $ 2,200 2020 2,965 2021 2,942 2022 3,010 2023 2,718 Thereafter 12,647 Total lease payments 26,482 Less: imputed interest (11,625 ) Present value of operating lease liabilities $ 14,857 Current portion of operating lease liabilities $ 895 Operating lease liabilities, net of current portion 13,962 Present value of operating lease liabilities $ 14,857 |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosures To The Consolidated Statements Of Cash Flows | Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Supplemental cash flow information: Cash paid for interest $ 1,750 $ 1,092 $ 1,145 Non-cash investing and financing activities: Increase in asset retirement obligations 314 421 — Increase (decrease) in accruals or payables for capital expenditures (84,162 ) (36,866 ) 4,896 Distribution of non-STACK assets, net of liabilities — — 43,482 |
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) March 31, 2019 March 31, 2018 February 8, 2018 Cash and cash equivalents $ 27,045 $ 255,701 $ 9,070 Restricted cash 798 1,295 1,275 Total cash, cash equivalents and restricted cash $ 27,843 $ 256,996 $ 10,345 |
Receivables (Tables)
Receivables (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Receivables [Abstract] | |
Schedule of Accounts Receivable | Accounts Receivable (in thousands) March 31, 2019 December 31, 2018 Production sales $ 32,332 $ 31,532 Joint interest billings 18,224 18,147 Pooling interest (1) 14,960 18,786 Allowance for doubtful accounts (113 ) (95 ) Total accounts receivable, net $ 65,403 $ 68,370 _________________ (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. Related Party Receivables (in thousands) March 31, 2019 December 31, 2018 Related party receivables $ 27,013 $ 33,316 Allowance for doubtful accounts (9,887 ) (9,034 ) Related party receivables, net 17,126 24,282 Notes receivable from related parties 13,403 13,403 Allowance for doubtful accounts (13,403 ) (13,403 ) Notes receivable from related parties, net — — Total related party receivables, net $ 17,126 $ 24,282 |
Property And Equipment (Tables)
Property And Equipment (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Summary Of Property And Equipment | Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Oil and gas properties depletion $ 34,042 $ 10,773 $ 11,021 Other property and equipment depreciation 408 163 609 Total depletion and depreciation $ 34,450 $ 10,936 $ 11,630 (in thousands) March 31, 2019 December 31, 2018 Oil and gas properties Unproved properties $ 811,804 $ 816,282 Accumulated impairment of unproved properties (742,065 ) (742,065 ) Unproved properties, net 69,739 74,217 Proved oil and gas properties 2,163,279 2,110,346 Accumulated depletion and impairment (1,455,268 ) (1,421,226 ) Proved oil and gas properties, net 708,011 689,120 Total oil and gas properties, net 777,750 763,337 Other property and equipment Land 5,059 5,059 Fresh water wells 27,742 27,366 Produced water disposal system 3,590 3,608 Office furniture, equipment and vehicles 2,842 2,840 Accumulated depreciation (1,134 ) (726 ) Other property and equipment, net 38,099 38,147 Total property and equipment, net $ 815,849 $ 801,484 |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
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 Revenue Oil $ 1,617 Natural gas 1,023 Natural gas liquids 236 Other 16 Operating revenue 2,892 Loss on sale of assets (1,923 ) Total revenue 969 Operating expenses Lease operating 1,770 Transportation and marketing 83 Production taxes 167 Workovers 127 Depreciation, depletion and amortization 884 Impairment of assets 5,560 General and administrative 21 Total operating expenses 8,612 Other expense Interest expense (103 ) Total other expense (103 ) Loss from discontinued operations, net of tax $ (7,746 ) Predecessor (in thousands) January 1, 2018 Total operating cash flows of discontinued operations $ 2,974 Total investing cash flows of discontinued operations (601 ) |
Derivatives (Tables)
Derivatives (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
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: March 31, 2019 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 $ 6,525 $ (6,525 ) $ — Derivatives, long-term assets 8,182 (7,721 ) 461 Total $ 14,707 $ (14,246 ) $ 461 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 $ 11,582 $ (6,525 ) $ 5,057 Derivatives, long-term liabilities 9,786 (7,721 ) 2,065 Total $ 21,368 $ (14,246 ) $ 7,122 December 31, 2018 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 |
Effect Of Derivative Instruments In The Consolidated Statements Of Operations | The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands): Successor Predecessor Derivatives not designated as hedges Three Months Ended February 9, 2018 January 1, 2018 Gain (loss) on derivatives - Oil $ (21,669 ) $ (21,944 ) $ 4,796 Natural gas (2,108 ) (67 ) 1,867 Total gain (loss) on derivatives $ (23,777 ) $ (22,011 ) $ 6,663 |
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 137,500 $ 63.03 $ 63.03 $ 63.03 Collar Contracts Short Call Options 2,035,000 66.31 75.20 56.50 Long Put Options 2,172,500 53.80 62.00 50.00 Short Put Options 2,172,500 42.72 52.00 37.50 2020 Collar Contracts Short Call Options 1,017,600 63.95 73.80 59.55 Long Put Options 1,566,600 56.81 62.50 50.00 Short Put Options 1,566,600 42.81 50.00 37.50 2021 Collar Contracts Short Call Options 279,750 63.51 63.75 63.35 Long Put Options 279,750 55.00 55.00 55.00 Short Put Options 279,750 43.00 43.00 43.00 |
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 11,030,000 $ 2.67 $ 2.72 $ 2.64 Basis Swap Contracts 16,050,000 (0.73 ) (0.49 ) (0.93 ) Collar Contracts Short Call Options 1,525,000 3.19 3.20 3.17 Long Put Options 1,525,000 2.70 2.70 2.70 Short Put Options 1,525,000 2.20 2.20 2.20 2020 Price Swap Contracts 1,284,000 2.54 2.54 2.54 Basis Swap Contracts 910,000 (0.49 ) (0.49 ) (0.50 ) Collar Contracts Short Call Options 3,874,500 3.19 3.69 2.77 Long Put Options 10,749,500 2.59 3.00 2.50 Short Put Options 9,696,000 2.10 2.50 2.00 2021 Collar Contracts Short Call Options 540,000 3.25 3.25 3.25 Long Put Options 2,790,000 2.62 2.65 2.50 Short Put Options 2,250,000 2.15 2.15 2.15 |
Basis Swap Derivative Contract | |
Derivative [Line Items] | |
Natural Gas Basis Swap Contracts | We had the following basis swaps at March 31, 2019 : Total Gas Volumes in MMBtu (1) over Remaining Term 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 ) 13,450,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '19 — Dec '19 (0.70 ) 910,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '20 — Mar '20 (0.49 ) 2,140,000 San Juan NYMEX Henry Hub Jan '19 — Oct '19 (0.81 ) ________________ (1) Represents short swaps that fix the basis differentials between OneOK, T ex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub. |
Accounts Payable And Accrued _2
Accounts Payable And Accrued Liabilities (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Payables and Accruals [Abstract] | |
Detail Of Accounts Payable And Accrued Liabilities | (in thousands) March 31, 2019 December 31, 2018 Accounts payable $ 8,502 $ 20,200 Accruals for capital expenditures 25,964 101,214 Revenue and royalties payable 40,365 46,870 Accruals for operating expenses 8,910 16,355 Accrued interest 13,754 1,784 Derivative settlements 49 109 Other 11,122 10,532 Total accrued liabilities 100,164 176,864 Accounts payable and accrued liabilities $ 108,666 $ 197,064 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Summary Of Changes In Asset Retirement Obligations | Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Balance, beginning of period $ 11,409 $ — $ 10,469 Liabilities assumed in Business Combination — 5,998 — Liabilities incurred 315 421 — Liabilities settled (147 ) (166 ) (63 ) Revisions to estimates (4) 300 63 Accretion expense 225 102 39 Balance, end of period 11,798 6,655 10,508 Less: Current portion 48 622 33 Long-term portion $ 11,750 $ 6,033 $ 10,475 |
Long Term Debt, Net (Tables)
Long Term Debt, Net (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Debt Disclosure [Abstract] | |
Long-Term Debt, Net And Notes Payable To Founder | (in thousands) March 31, 2019 December 31, 2018 Alta Mesa RBL $ 278,000 $ 161,000 2024 Notes 500,000 500,000 Unamortized premium on 2024 notes 27,892 29,123 Total long-term debt, net $ 805,892 $ 690,123 |
Summary Of Future Maturities Of Long-Term Debt | Fiscal year (in thousands) 2019 $ — 2020 — 2021 — 2022 — 2023 278,000 Thereafter 500,000 $ 778,000 |
Significant Concentrations (Tab
Significant Concentrations (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Significant Concentrations [Abstract] | |
Schedule of Significant Concentrations | ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities. Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Revenue marketed by ARM on our behalf $ 83,831 $ 37,343 $ 28,757 Marketing and management fees paid to ARM $ 661 $ — $ — Fees paid to ARM for services relating to our derivatives 193 74 66 Total fees paid to ARM $ 854 $ 74 $ 66 |
Equity-Based Compensation (Su_2
Equity-Based Compensation (Successor) (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock compensation expense recognized | Stock compensation expense recognized was as follows: Successor Predecessor (in thousands) Three Months Ended February 9, 2018 January 1, 2018 Stock options $ 791 $ 1,048 $ — Restricted stock awards 862 564 — Performance-based restricted stock units 8 1,156 — Total compensation expense $ 1,661 $ 2,768 $ — |
Going Concern (Details)
Going Concern (Details) - USD ($) | 1 Months Ended | ||||
Jun. 30, 2019 | May 31, 2019 | Apr. 01, 2019 | Mar. 31, 2019 | Mar. 25, 2019 | |
Line of Credit Facility [Line Items] | |||||
Current liabilities in excess of current assets | $ 4,800,000 | ||||
Capital program well costs | $ 3,000,000 | ||||
Unsecured debt | $ 500,000,000 | ||||
Subsequent Event | Alta Mesa Credit Facility | |||||
Line of Credit Facility [Line Items] | |||||
Credit facility amount | $ 370,000,000 | ||||
Cash | $ 93,700,000 | ||||
Scenario, Forecast | Subsequent Event | |||||
Line of Credit Facility [Line Items] | |||||
Interest payment | $ 20,000,000 | ||||
Common Class A | Parent Company | |||||
Line of Credit Facility [Line Items] | |||||
Common stock par value (in dollars per share) | $ 1 |
Adoption of ASU No. 2016-02, _3
Adoption of ASU No. 2016-02, Leases (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating lease, right of use asset recognized | $ 14,758 | ||
Operating lease liability recognized | $ 14,857 | ||
Weighted-average remaining lease term (in years) | 8 years 3 months 18 days | ||
Weighted-average discount rate | 14.30% | ||
Lease cost | $ 3,321 | ||
Lease payment under ASC 840, due 2019 | $ 2,800 | ||
Lease payment under ASC 840, due 2020 | 2,900 | ||
Lease payment under ASC 840, due 2021 | 2,900 | ||
Lease payment under ASC 840, due 2022 | 3,100 | ||
Lease payment under ASC 840, due 2023 | 3,000 | ||
Lease payment under ASC 840, due thereafter | $ 12,200 | ||
Lease operating expense | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Lease cost | 2,300 | ||
General and administrative | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Lease cost | $ 1,000 | ||
Accounting Standards Update 2016-02 | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating lease, right of use asset recognized | $ 15,000 | ||
Operating lease liability recognized | $ 15,000 |
Adoption of ASU No. 2016-02, _4
Adoption of ASU No. 2016-02, Leases (Components of Lease Expense) (Details) $ in Thousands | 3 Months Ended |
Mar. 31, 2019USD ($) | |
Leases [Abstract] | |
Operating lease cost | $ 811 |
Variable lease cost | 323 |
Short-term lease cost | 2,187 |
Total lease cost | $ 3,321 |
Adoption of ASU No. 2016-02, _5
Adoption of ASU No. 2016-02, Leases (Maturities of Operating Lease Liabilities) (Details) $ in Thousands | Mar. 31, 2019USD ($) |
Leases [Abstract] | |
Remainder of 2019 | $ 2,200 |
2020 | 2,965 |
2021 | 2,942 |
2022 | 3,010 |
2023 | 2,718 |
Thereafter | 12,647 |
Total lease payments | 26,482 |
Less: imputed interest | (11,625) |
Present value of operating lease liability | 14,857 |
Current portion of operating lease liabilities | 895 |
Operating lease liabilities, net of current portion | 13,962 |
Operating lease liability recognized | $ 14,857 |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Supplemental Disclosures To The Consolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | |
Supplemental cash flow information: | |||
Cash paid for interest | $ 1,092 | $ 1,750 | |
Non-cash investing and financing activities: | |||
Increase in asset retirement obligations | 421 | 314 | |
Increase (decrease) in accruals or payables for capital expenditures | (36,866) | (84,162) | |
Distribution of non-STACK assets, net of liabilities | $ 0 | $ 0 | |
Predecessor | |||
Supplemental cash flow information: | |||
Cash paid for interest | $ 1,145 | ||
Non-cash investing and financing activities: | |||
Increase in asset retirement obligations | 0 | ||
Increase (decrease) in accruals or payables for capital expenditures | 4,896 | ||
Distribution of non-STACK assets, net of liabilities | $ 43,482 |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information (Cash and Restricted Cash) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 | Mar. 31, 2018 | Feb. 08, 2018 | Dec. 31, 2017 |
Summary Of Significant Accounting Policies [Line Items] | |||||
Cash and cash equivalents | $ 27,045 | $ 12,984 | $ 255,701 | ||
Restricted cash | 798 | 1,295 | |||
Total cash, cash equivalents and restricted cash | $ 27,843 | $ 13,985 | $ 256,996 | $ 10,345 | |
Predecessor | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Cash and cash equivalents | 9,070 | ||||
Restricted cash | 1,275 | ||||
Total cash, cash equivalents and restricted cash | $ 10,345 | $ 4,990 |
Receivables (Schedule of Accoun
Receivables (Schedule of Accounts Receivable) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Receivables [Abstract] | ||
Production sales | $ 32,332 | $ 31,532 |
Joint interest billings | 18,224 | 18,147 |
Pooling interest | 14,960 | 18,786 |
Allowance for doubtful accounts | (113) | (95) |
Total related party receivables, net | $ 65,403 | $ 68,370 |
Receivables (Schedule of Relate
Receivables (Schedule of Related Party Receivables) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Receivables [Abstract] | ||
Related party receivables | $ 27,013 | $ 33,316 |
Allowance for doubtful accounts | (9,887) | (9,034) |
Related party receivables, net | 17,126 | 24,282 |
Notes receivable from related parties | 13,403 | 13,403 |
Allowance for doubtful accounts | (13,403) | (13,403) |
Notes receivable from related parties, net | 0 | 0 |
Total related party receivables, net | $ 17,126 | $ 24,282 |
Receivables Receivables (Narrat
Receivables Receivables (Narrative) (Details) - USD ($) | 1 Months Ended | 2 Months Ended | 3 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 29, 2017 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Notes receivable from related party, net | $ 0 | $ 0 | |||
Related party receivables, net | 17,126,000 | 24,282,000 | |||
Northwest Gas Processing | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Promissory note | $ 1,500,000 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 8.00% | ||||
Notes receivable from related party, net | 1,700,000 | 1,700,000 | |||
Alta Mesa Resources | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Related party receivables | $ 3,800,000 | 3,300,000 | |||
High Mesa Agreement | Affiliated Entity | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Initial agreement term | 180 days | ||||
Automatic renewal period | 180 days | ||||
Notice period to terminate agreement | 90 days | ||||
Management fee | 10,000 | ||||
Balance of note receivable | $ 9,900,000 | 10,100,000 | |||
Allowance for uncollectible accounts | 9,900,000 | 9,000,000 | |||
Unamortized premium on 2024 notes | High Mesa Services LLC | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Balance of note receivable | $ 11,700,000 | 11,700,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 8.00% | ||||
Related party receivables, net | $ 8,500,000 | ||||
Kingfisher | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Transportation and marketing expense | $ 3,100,000 | $ 4,600,000 | 15,200,000 | ||
Related party receivables | 2,300,000 | 7,800,000 | |||
Kingfisher | Affiliated Entity | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Related party receivables | 1,900,000 | 3,400,000 | |||
Kingfisher | High Mesa Agreement | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Related party receivables | $ 9,100,000 | $ 8,700,000 |
Property And Equipment (Summary
Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Property, Plant and Equipment [Line Items] | ||
Unproved properties | $ 811,804 | |
Accumulated impairment of unproved properties | (742,065) | |
Unproved properties, net | 69,739 | |
Proved oil and gas properties | 2,163,279 | |
Accumulated depletion and impairment | (1,455,268) | |
Proved oil and gas properties, net | 708,011 | |
Total oil and gas properties, net | 777,750 | $ 763,337 |
Land | 5,059 | |
Fresh water wells | 27,742 | |
Produced water disposal system | 3,590 | |
Office furniture, equipment and vehicles | 2,842 | |
Accumulated depreciation | (1,134) | |
Other property and equipment, net | 38,099 | 38,147 |
Total property and equipment, net | $ 815,849 | 801,484 |
Predecessor | ||
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 depletion 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 |
Property And Equipment (Depreci
Property And Equipment (Depreciation and Depletion Expense) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | |
Property, Plant and Equipment [Line Items] | |||
Oil and gas properties depletion | $ 10,773 | $ 34,042 | |
Other property and equipment depreciation | 163 | 408 | |
Total depletion and depreciation | $ 10,936 | $ 34,450 | |
Predecessor | |||
Property, Plant and Equipment [Line Items] | |||
Oil and gas properties depletion | $ 11,021 | ||
Other property and equipment depreciation | 609 | ||
Total depletion and depreciation | $ 11,630 |
Discontinued Operations (Narrat
Discontinued Operations (Narrative) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | Dec. 31, 2018 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Interest converted into debt | $ 0 | $ 0 | ||
Predecessor | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Interest converted into debt | $ 103 | |||
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 |
Discontinued Operations (Schedu
Discontinued Operations (Schedule Of Operations And Other Items Reclassified In Discontinued Operations) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | |
Operating expenses | |||
Interest expense | $ 0 | $ 0 | |
Predecessor | |||
Operating expenses | |||
Interest expense | $ (103) | ||
Predecessor | Weeks Island Field, Louisiana | Non Stack Assets [Member] | Disposed of by Sale | |||
Revenue | |||
Oil | 1,617 | ||
Natural gas | 1,023 | ||
Natural gas liquids | 236 | ||
Other | 16 | ||
Operating revenue | 2,892 | ||
Loss on sale of assets | (1,923) | ||
Total revenue | 969 | ||
Operating expenses | |||
Lease operating | 1,770 | ||
Transportation and marketing | 83 | ||
Production taxes | 167 | ||
Workovers | 127 | ||
Depreciation, depletion and amortization | 884 | ||
Impairment of assets | 5,560 | ||
General and administrative | 21 | ||
Total operating expenses | 8,612 | ||
Interest expense | (103) | ||
Total other expense | (103) | ||
Loss from discontinued operations, net of tax | $ (7,746) |
Discontinued Operations (Total
Discontinued Operations (Total Operating And Investing Cash Flows Of Discontinued Operations) (Details) - Predecessor - Weeks Island Field, Louisiana - Disposed of by Sale $ in Thousands | 1 Months Ended |
Feb. 08, 2018USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Total operating cash flows of discontinued operations | $ 2,974 |
Total investing cash flows of discontinued operations | $ (601) |
Derivatives (Fair Values Of Der
Derivatives (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Derivatives, Fair Value [Line Items] | ||
Gross fair value of assets | $ 14,707 | $ 30,422 |
Gross liabilities offset against assets in the Balance Sheet | (14,246) | (11,052) |
Net fair value of assets presented in the Balance Sheet | 461 | 19,370 |
Gross fair value of liabilities | 21,368 | 12,942 |
Gross assets offset against liabilities in the Balance Sheet | (14,246) | (11,052) |
Net fair value of liabilities presented in the Balance Sheet | 7,122 | 1,890 |
Derivatives, current assets | ||
Derivatives, Fair Value [Line Items] | ||
Gross fair value of assets | 6,525 | 22,512 |
Gross liabilities offset against assets in the Balance Sheet | (6,525) | (6,089) |
Net fair value of assets presented in the Balance Sheet | 0 | 16,423 |
Derivatives, long-term assets | ||
Derivatives, Fair Value [Line Items] | ||
Gross fair value of assets | 8,182 | 7,910 |
Gross liabilities offset against assets in the Balance Sheet | (7,721) | (4,963) |
Net fair value of assets presented in the Balance Sheet | 461 | 2,947 |
Derivatives, current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Gross fair value of liabilities | 11,582 | 7,799 |
Gross assets offset against liabilities in the Balance Sheet | (6,525) | (6,089) |
Net fair value of liabilities presented in the Balance Sheet | 5,057 | 1,710 |
Derivatives, long-term liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Gross fair value of liabilities | 9,786 | 5,143 |
Gross assets offset against liabilities in the Balance Sheet | (7,721) | (4,963) |
Net fair value of liabilities presented in the Balance Sheet | $ 2,065 | $ 180 |
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 |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (loss) on derivative contracts | $ (22,011) | $ (23,777) | |
Predecessor | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (loss) on derivative contracts | $ 6,663 | ||
Derivatives Not Designated As Hedging | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (loss) on derivative contracts | (22,011) | (23,777) | |
Derivatives Not Designated As Hedging | Oil | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (loss) on derivative contracts | (21,944) | (21,669) | |
Derivatives Not Designated As Hedging | Natural gas | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (loss) on derivative contracts | $ (67) | $ (2,108) | |
Derivatives Not Designated As Hedging | Predecessor | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (loss) on derivative contracts | 6,663 | ||
Derivatives Not Designated As Hedging | Predecessor | Oil | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (loss) on derivative contracts | 4,796 | ||
Derivatives Not Designated As Hedging | Predecessor | Natural gas | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (loss) on derivative contracts | $ 1,867 |
Derivatives (Additional Informa
Derivatives (Additional Information) (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Contracts To be Settled January 2019 | ||
Derivative [Line Items] | ||
Derivative contracts | $ 0.4 | $ 1.3 |
Derivatives (Oil Derivative Con
Derivatives (Oil Derivative Contracts) (Details) - Oil Derivative Contracts | 3 Months Ended |
Mar. 31, 2019$ / bblbbl | |
Price Swap Contracts | 2019 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 137,500 |
Weighted Average Swap Price (USD per unit) | 63.03 |
Price Swap Contracts | 2019 | High | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 63.03 |
Price Swap Contracts | 2019 | Low | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 63.03 |
Short Call Options | 2019 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 2,035,000 |
Weighted Average Option Price (USD per unit) | 66.31 |
Short Call Options | 2019 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 75.20 |
Short Call Options | 2019 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 56.50 |
Short Call Options | 2020 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,017,600 |
Weighted Average Option Price (USD per unit) | 63.95 |
Short Call Options | 2020 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 73.80 |
Short Call Options | 2020 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 59.55 |
Short Call Options | 2021 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 279,750 |
Weighted Average Option Price (USD per unit) | 63.51 |
Short Call Options | 2021 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 63.75 |
Short Call Options | 2021 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 63.35 |
Long Put Options | 2019 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 2,172,500 |
Weighted Average Option Price (USD per unit) | 53.80 |
Long Put Options | 2019 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 62 |
Long Put Options | 2019 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 50 |
Long Put Options | 2020 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,566,600 |
Weighted Average Option Price (USD per unit) | 56.81 |
Long Put Options | 2020 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 62.50 |
Long Put Options | 2020 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 50 |
Long Put Options | 2021 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 279,750 |
Weighted Average Option Price (USD per unit) | 55 |
Long Put Options | 2021 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 55 |
Long Put Options | 2021 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 55 |
Short Put Options | 2019 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 2,172,500 |
Weighted Average Option Price (USD per unit) | 42.72 |
Short Put Options | 2019 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 52 |
Short Put Options | 2019 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 37.50 |
Short Put Options | 2020 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,566,600 |
Weighted Average Option Price (USD per unit) | 42.81 |
Short Put Options | 2020 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 50 |
Short Put Options | 2020 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 37.50 |
Short Put Options | 2021 | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 279,750 |
Weighted Average Option Price (USD per unit) | 43 |
Short Put Options | 2021 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 43 |
Short Put Options | 2021 | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 43 |
Derivatives (Natural Gas Deriva
Derivatives (Natural Gas Derivative Contracts) (Details) - Natural Gas Derivative Contract | 3 Months Ended |
Mar. 31, 2019MMBTU$ / MMBTU | |
2019 | Price Swap Contracts | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 11,030,000 |
Weighted Average Swap Price (USD per unit) | 2.67 |
2019 | Price Swap Contracts | High | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 2.72 |
2019 | Price Swap Contracts | Low | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 2.64 |
2019 | Basis Swap Contracts | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 16,050,000 |
Weighted Average Swap Price (USD per unit) | (0.73) |
2019 | Basis Swap Contracts | High | |
Derivative [Line Items] | |
Swap Price (USD per unit) | (0.49) |
2019 | Basis Swap Contracts | Low | |
Derivative [Line Items] | |
Swap Price (USD per unit) | (0.93) |
2019 | Short Call Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 1,525,000 |
Weighted Average Option Price (USD per unit) | 3.19 |
2019 | Short Call Options | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.20 |
2019 | Short Call Options | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.17 |
2019 | Long Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 1,525,000 |
Weighted Average Option Price (USD per unit) | 2.70 |
2019 | Long Put Options | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.70 |
2019 | Long Put Options | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.70 |
2019 | Short Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 1,525,000 |
Weighted Average Option Price (USD per unit) | 2.20 |
2019 | Short Put Options | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.20 |
2019 | Short Put Options | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.20 |
2020 | Price Swap Contracts | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 1,284,000 |
Weighted Average Swap Price (USD per unit) | 2.54 |
2020 | Price Swap Contracts | High | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 2.54 |
2020 | Price Swap Contracts | Low | |
Derivative [Line Items] | |
Swap Price (USD per unit) | 2.54 |
2020 | Basis Swap Contracts | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 910,000 |
Weighted Average Swap Price (USD per unit) | (0.49) |
2020 | Basis Swap Contracts | High | |
Derivative [Line Items] | |
Swap Price (USD per unit) | (0.49) |
2020 | Basis Swap Contracts | Low | |
Derivative [Line Items] | |
Swap Price (USD per unit) | (0.50) |
2020 | Short Call Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 3,874,500 |
Weighted Average Option Price (USD per unit) | 3.19 |
2020 | Short Call Options | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.69 |
2020 | Short Call Options | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.77 |
2020 | Long Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 10,749,500 |
Weighted Average Option Price (USD per unit) | 2.59 |
2020 | Long Put Options | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3 |
2020 | Long Put Options | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.50 |
2020 | Short Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 9,696,000 |
Weighted Average Option Price (USD per unit) | 2.10 |
2020 | Short Put Options | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.50 |
2020 | Short Put Options | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2 |
2021 | Short Call Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 540,000 |
Weighted Average Option Price (USD per unit) | 3.25 |
2021 | Short Call Options | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.25 |
2021 | Short Call Options | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 3.25 |
2021 | Long Put Options | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 2,790,000 |
Weighted Average Option Price (USD per unit) | 2.62 |
2021 | Long Put Options | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.65 |
2021 | Long Put Options | Low | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.50 |
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 | High | |
Derivative [Line Items] | |
Option Price (USD per unit) | 2.15 |
2021 | Short Put Options | Low | |
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 | 3 Months Ended |
Mar. 31, 2019MMBTU$ / 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 | 13,450,000 |
Weighted average spread | $ / MMBTU | (0.70) |
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 | 2,140,000 |
Weighted average spread | $ / MMBTU | (0.81) |
Accounts Payable And Accrued _3
Accounts Payable And Accrued Liabilities (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 |
Payables and Accruals [Abstract] | ||
Accounts payable | $ 8,502 | $ 20,200 |
Accruals for capital expenditures | 25,964 | 101,214 |
Revenue and royalties payable | 40,365 | 46,870 |
Accruals for operating expenses | 8,910 | 16,355 |
Accrued interest | 13,754 | 1,784 |
Derivative settlements | 49 | 109 |
Other | 11,122 | 10,532 |
Total accrued liabilities | 100,164 | 176,864 |
Accounts payable and accrued liabilities | $ 108,666 | $ 197,064 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | ||||
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Mar. 31, 2018 | Feb. 08, 2018 | |
Asset Retirement Obligation [Line Items] | |||||||
Balance, beginning of period | $ 0 | $ 11,409 | |||||
Liabilities assumed | 5,998 | 0 | |||||
Liabilities incurred | 421 | 315 | |||||
Liabilities settled | (166) | (147) | |||||
Revisions to estimates | 300 | (4) | |||||
Accretion expense | 102 | 225 | |||||
Balance, end of period | 0 | $ 11,409 | $ 11,798 | $ 11,409 | $ 6,655 | $ 0 | |
Less: Current portion | 48 | 2,079 | 622 | ||||
Long-term portion | $ 11,750 | $ 9,330 | $ 6,033 | ||||
Predecessor | |||||||
Asset Retirement Obligation [Line Items] | |||||||
Balance, beginning of period | $ 10,469 | 10,508 | |||||
Liabilities assumed | 0 | ||||||
Liabilities incurred | 0 | ||||||
Liabilities settled | (63) | ||||||
Revisions to estimates | 63 | ||||||
Accretion expense | 39 | ||||||
Balance, end of period | $ 10,469 | $ 10,508 | 10,508 | ||||
Less: Current portion | 33 | ||||||
Long-term portion | $ 10,475 |
Long Term Debt, Net (Schedule o
Long Term Debt, Net (Schedule of Long-Term Debt, Net) (Details) - USD ($) $ in Thousands | Mar. 31, 2019 | Dec. 31, 2018 | Feb. 09, 2018 |
Debt Instrument [Line Items] | |||
Total long-term debt, net | $ 805,892 | $ 690,123 | |
2024 Notes | |||
Debt Instrument [Line Items] | |||
2024 Notes | 500,000 | $ 500,000 | |
Unamortized premium on 2024 notes | |||
Debt Instrument [Line Items] | |||
Unamortized premium on 2024 notes | 27,892 | 29,123 | |
Alta Mesa RBL | Alta Mesa RBL | |||
Debt Instrument [Line Items] | |||
Alta Mesa RBL | $ 278,000 | $ 161,000 |
Long Term Debt, Net (Narrative)
Long Term Debt, Net (Narrative) (Details) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Feb. 09, 2018USD ($) | |
2024 Notes | |||
Debt Instrument [Line Items] | |||
2024 Notes | $ 500,000 | $ 500,000 | |
Alta Mesa Credit Facility | |||
Debt Instrument [Line Items] | |||
Debt covenant, current ratio, minimum required | 1 | ||
Maximum leverage ratio | 4 | ||
Alta Mesa RBL | 2024 Notes | |||
Debt Instrument [Line Items] | |||
Notes Payable, Fair Value Disclosure | $ 194,900 |
Long Term Debt, Net (Summary Of
Long Term Debt, Net (Summary Of Future Maturities Of Long-Term Debt) (Details) $ in Thousands | Mar. 31, 2019USD ($) |
Summary of future maturities of long-term debt | |
2019 | $ 0 |
2020 | 0 |
2021 | 0 |
2022 | 0 |
2023 | 278,000 |
Thereafter | 500,000 |
Total long-term debt | $ 778,000 |
Significant Concentrations (Det
Significant Concentrations (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 12 Months Ended | |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | Dec. 31, 2016 | Dec. 31, 2018 | |
Concentration Risk [Line Items] | |||||
Revenues | $ 33,885 | $ 94,303 | |||
AEM | |||||
Concentration Risk [Line Items] | |||||
Revenues | $ 28,757 | 83,831 | $ 37,343 | ||
Fees paid | 66 | 74 | 193 | ||
Total fees paid to ARM | 66 | 74 | 854 | ||
Accounts receivable | 3,800 | $ 38,400 | |||
Marketing fees | AEM | |||||
Concentration Risk [Line Items] | |||||
Fees paid | $ 0 | $ 0 | $ 661 |
Equity-Based Compensation (Su_3
Equity-Based Compensation (Successor) (Stock Compensation Expense) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended |
Feb. 08, 2018 | Mar. 31, 2018 | Mar. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | $ 2,768 | $ 1,661 | |
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | 1,048 | 791 | |
Restricted stock awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | 564 | 862 | |
Performance-based restricted stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | $ 1,156 | $ 8 | |
Predecessor | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | $ 0 | ||
Predecessor | Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | 0 | ||
Predecessor | Restricted stock awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | 0 | ||
Predecessor | Performance-based restricted stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | $ 0 |
Equity-Based Compensation (Su_4
Equity-Based Compensation (Successor) (Narrative) (Details) - Performance-based restricted stock units - $ / shares | 3 Months Ended | 11 Months Ended |
Mar. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period | 3 years | |
Awards deemed granted (in shares) | 595,417 | |
Fair value of tranche granted (in USD per share) | $ 0.27 | |
Tranche one | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting rate | 20.00% | |
Tranche two | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting rate | 30.00% | |
Tranche three | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting rate | 50.00% | |
Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Percentage of shares that may be earned | 0.00% | |
Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Percentage of shares that may be earned | 200.00% |
Related Party Transactions (Det
Related Party Transactions (Details) | Feb. 08, 2018USD ($) | Dec. 31, 2016 | Mar. 31, 2018USD ($) | Mar. 31, 2019USD ($)well | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jan. 13, 2016well |
Related Party Transaction [Line Items] | |||||||
Advances from related party | $ 4,479,000 | $ 9,822,000 | |||||
BCE | |||||||
Related Party Transaction [Line Items] | |||||||
Advances from related party | 4,500,000 | 9,800,000 | |||||
Land consulting services | Vice President | David Murrell, VP of Land and Business Development | |||||||
Related Party Transaction [Line Items] | |||||||
Total fees paid to ARM | $ 36,000 | ||||||
Land consulting services | Predecessor | Vice President | David Murrell, VP of Land and Business Development | |||||||
Related Party Transaction [Line Items] | |||||||
Total fees paid to ARM | $ 28,000 | ||||||
Compensation to related party | Vice President | David Mcclure Vp of Facilities and Infrastructure | |||||||
Related Party Transaction [Line Items] | |||||||
Total compensation | 970,197 | 768,860 | |||||
Compensation to related party | Landman | David Pepper, Surface Land Manager | |||||||
Related Party Transaction [Line Items] | |||||||
Total compensation | $ 112,761 | 70,180 | |||||
Compensation to related party | Predecessor | Vice President | David Mcclure Vp of Facilities and Infrastructure | |||||||
Related Party Transaction [Line Items] | |||||||
Total compensation | 28,874 | ||||||
Compensation to related party | Predecessor | Landman | David Pepper, Surface Land Manager | |||||||
Related Party Transaction [Line Items] | |||||||
Total compensation | 67,322 | ||||||
KFM | Affiliated Entity | |||||||
Related Party Transaction [Line Items] | |||||||
Advances from related party | 2,900,000 | ||||||
AMR | Affiliated Entity | |||||||
Related Party Transaction [Line Items] | |||||||
Advances from related party | 500,000 | $ 500,000 | |||||
Joint Development Agreement | |||||||
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 | BCE | |||||||
Related Party Transaction [Line Items] | |||||||
Percent committed to fund | 100.00% | ||||||
Drilling and completion costs (maximum) | $ 3,200,000 | ||||||
Working interest received (percent) | 80.00% | ||||||
Reduced interest (percent) | 20.00% | ||||||
Internal rate of return | 15.00% | ||||||
Advances from related party | $ 39,500,000 | ||||||
Number of wells drilled | well | 61 |